Abraxas Petroleum 10Q 2009 Q2 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009

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

COMMISSION FILE NUMBER: 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Nevada		74-2584033
(State of Incorporation)		(I.R.S. Employer Identification No.)

18803 Meisner Drive, San Antonio, TX 78258

(Address of principal executive offices) (Zip Code)

210-490-4788

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o (Do not mark if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨No x

The number of shares of the issuer’s common stock outstanding as of May 7, 2009 was:

Class	Shares Outstanding
Common Stock, $.01 Par Value	49,787,914

Forward-Looking Information

We make forward-looking statements throughout this document. Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe”, “expect”, “anticipate”, “intend”, “plan”, “seek”, “estimate”, “could”, “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable. The forward-looking information contained in this document is generally located in the material set forth under the headings “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 success in development, exploitation and exploration activities;

our ability to make planned capital expenditures;

declines in our production of oil and gas;

prices for oil and gas;

our ability to raise equity capital or incur additional indebtedness;

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

prices and availability of alternative fuels;

our restrictive debt covenants;

our acquisition and divestiture activities;

results of our hedging activities; and

other factors discussed elsewhere in this report.

In addition to these factors, important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the Cautionary Statements.

ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES

FORM 10 – Q

INDEX

	PART I
	FINANCIAL INFORMATION

ITEM 1 -	FINANCIAL STATEMENTS
	Condensed Consolidated Balance Sheets – March 31, 2009 – (unaudited) and December 31, 2008	4
	Condensed Consolidated Statements of Operations – (unaudited) Three Months Ended March 31, 2009 and 2008	6
	Condensed Consolidated Statements of Cash Flows – (unaudited) Three Months Ended March 31, 2009 and 2008	7
	Notes to Condensed Consolidated Financial Statements (unaudited)	8

ITEM 2 –	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

ITEM 3 –	Quantitative and Qualitative Disclosure about Market Risks	46

ITEM 4 –	Controls and Procedures	48

	PART II
	OTHER INFORMATION

ITEM 1–	Legal Proceedings	49
ITEM 1a –	Risk Factors	49
ITEM 2 –	Unregistered Sales of Equity Securities and Use of Proceeds	49
ITEM 3 –	Defaults Upon Senior Securities	49
ITEM 4 –	Submission of Matters to a Vote of Security Holders	49
ITEM 5 –	Other Information	49
ITEM 6 –	Exhibits	49
	Signatures	50

PART 1

FINANCIAL INFORMATION

Item 1. Financial Statements

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)

	March 31,		December 31,
	2009		2008 (1)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	613	$	1,924
Accounts receivable, net:
Joint owners		705		1,740
Oil and gas production		5,008		6,168
Other		25		58
		5,738		7,966

Derivative asset – current		24,424		22,832
Other current assets		494		572
Total current assets		31,269		33,294

Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved		444,959		440,712
Unproved properties excluded from depletion		—		—
Other property and equipment		11,018		10,986
Total		455,977		451,698
Less accumulated depreciation, depletion, and amortization		295,876		291,390
Total property and equipment – net		160,101		160,308

Deferred financing fees, net		1,723		1,443
Derivative asset – long-term		21,663		16,394
Other assets		445		400
Total assets	$	215,201	$	211,839

(1)	As adjusted for FAS No. 160 “Noncontrolling Interest in Consolidated Financial Statements.” (See Note 1)

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands)

	March 31,			December 31,
	2009			2008 (1)
	(Unaudited)
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	6,440		$	10,748
Oil and gas production payable		2,443			3,176
Accrued interest		242			350
Other accrued expenses		1,580			1,886
Derivative liability – current		2,950			3,000
Current maturities of long-term debt		40,147			40,134
Other current liabilities		19			—
Total current liabilities		53,821			59,294

Long-term debt, excluding current maturities		133,788			130,835

Future site restoration		10,107			9,959
Total liabilities		197,716			200,088

Equity
Abraxas Petroleum Corporation stockholders’ equity:
Convertible preferred stock, par value $.01, authorized 1,000,000 shares; -0- issued and outstanding		—			—
Common Stock, par value $.01 per share-authorized 200,000,000 shares;issued and outstanding 49,737,914 and, 49,622,423		497			496
Additional paid-in capital		187,567			187,243
Accumulated deficit		(178,744	)		(183,194	)
Accumulated other comprehensive income		155			113
Total Abraxas Petroleum Corporation stockholders’ equity		9,475			4,658
Non-controlling interest equity		8,010			7,093
Total stockholders' equity		17,485			11,751
Total liabilities and stockholders’ equity	$	215,201		$	211,839

(1)	As adjusted for FAS No. 160 “Noncontrolling Interest in Consolidated Financial Statements.” (See Note 1)

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)

	Three Months Ended March 31,
	2009			2008 (1)
Revenue:
Oil and gas production revenues	$	10,596		$	21,863
Rig revenues		253			306
Other		1			1
		10,850			22,170
Operating costs and expenses:
Lease operating and production taxes		5,869			5,202
Depreciation, depletion and amortization		4,487			5,094
Rig operations		188			210
General and administrative (including stock-based compensation of $267 and $246)		2,129			1,799
		12,673			12,305
Operating income (loss)		(1,823	)		9,865

Other (income) expense
Interest income		(5	)		(96	)
Interest expense		2,556			2,466
Financing costs		362			—
Amortization of deferred financing fees		212			194
(Gain) loss on derivative contracts (unrealized $(6,430) and $26,075)		(12,865	)		26,958
Other		21			—
		(9,719	)		29,522
Consolidated net income (loss)		7,896			(19,657	)
Less: Net (income) loss attributable to non-controlling interest		(3,446	)		10,666
Net income (loss) attributable to Abraxas Petroleum Corporation	$	4,450		$	(8,991	)

Net earnings (loss) attributable to Abraxas Petroleum common stockholders - per common share – basic	$	0.09		$	(0.18	)
Net earnings (loss) attributable to Abraxas Petroleum common stockholders - per common share – diluted	$	0.09		$	(0.18	)

(1)	As adjusted for FAS No. 160 “Noncontrolling Interest in Consolidated Financial Statements.” (See Note 1)

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	Three Months Ended March 31,
	2009			2008 (1)
Cash flows from Operating Activities
Net income (loss) ��	$	7,896		$	(19,657	)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Change in derivative fair value		(6,911	)		23,541
Depreciation, depletion, and amortization		4,487			5,094
Accretion of future site restoration		141			120
Amortization of deferred financing fees		212			194
Stock-based compensation		267			246
Other non-cash items		18			21
Changes in operating assets and liabilities:
Accounts receivable		2,228			(8,509	)
Other		75			31
Accounts payable and accrued expenses		(5,463	)		8,595
Net cash provided by operations		2,950			9,676

Cash flows from Investing Activities
Capital expenditures, including purchases and development of properties		(4,271	)		(137,859	)
Net cash used in investing activities		(4,271	)		(137,859	)

Cash flows from Financing Activities
Proceeds from long-term borrowings		3,000			119,700
Payments on long-term borrowings		(34	)		—
Proceeds from exercise of stock options		—			15
Deferred financing fees		(492	)		(1,499	)
Partnership distributions to non-controlling interest		(2,257	)		(2,398	)
Other		(207	)		—
Net cash provided by financing operations		10			115,818
Decrease in cash		(1,311	)		(12,365	)
Cash, at beginning of period		1,924			18,936
Cash, at end of period	$	613		$	6,571

Supplemental disclosures of cash flow information:
Interest paid	$	2,415		$	2,314

(1) As adjusted for FAS No. 160 “Noncontrolling Interest in Consolidated Financial Statements.” (See Note 1)

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Notes to Condensed Consolidated 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”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K filed for the year ended December 31, 2008. 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 registered public 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, 2009 are not necessarily indicative of results to be expected for the full year.

The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we”, “us”, “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating effective May 25, 2007. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 52.7% non-controlling owners of the Partnership presented as non-controlling interest. Abraxas owns the remaining 47.3% of the partnership interests. The Company has determined that based on its control of the general partner of the Partnership, this 47.3% owned entity should be consolidated for financial reporting purposes.

The condensed consolidated financial statements included herein have been prepared by Abraxas and are unaudited, except for the balance sheet at December 31, 2008, which has been derived from the audited consolidated financial statements at that date. In the opinion of management, the unaudited condensed consolidated financial statements include all recurring adjustments necessary for a fair presentation of the financial position as of March 31, 2009, the results of operations and the cash flows for each of the three-month periods ended March 31, 2009 and 2008. Although management believes the unaudited interim related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The results of operations and the cash flows for the three-month period ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

On January 1, 2009, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for (1) ownership interests in subsidiaries held by others, (2) the amount of consolidated net income attributable to the controlling and noncontrolling interests, (3) changes in the controlling ownership interest, (4) the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated and (5) disclosures that clearly identify and distinguish between the interests of the controlling and noncontrolling owners. The adoption of SFAS 160 resulted in changes to our presentation for noncontrolling interests and did not have a material impact on the Company’s results of operations and financial condition. Certain prior period balances have been restated to reflect the changes required by SFAS 160.

The following table illustrates the changes in consolidated equity:

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			Abraxas Petroleum Corporation Shareholders
	Comprehensive Income		Common Stock		Additional Paid-in Capital		Accumulated Deficit			Accumulated Other Comprehensive Income (loss)		Non- Controlling Interest			Total
January 1, 2009	$	—	$	496	$	187,243	$	(183,194	)	$	113	$	7,093		$	11,751
Comprehensive income:
Net income		7,896		—		—		4,450			—		3,446			7,896
Unrealized gain on securities		42		—		—		—			42		—			42
Equity based compensation		—		—		220		—			—		23			243
Partnership distributions		—		—		—		—			—		(2,257	)		(2,257	)
Registration fees		—		—		—		—			—		(550	)		(550	)
Other		—		1		104		—			—		255			360
March 31, 2009	$	7,938	$	497	$	187,567	$	(178,744	)	$	155	$	8,010		$	17,485

In accordance with previous generally accepted accounting principles, when cumulative losses applicable to the non-controlling interest exceed the non-controlling interest equity capital in the entity, such excess and any further losses applicable to the non-controlling interest were charged to the earnings of the majority interest. Future earnings were recognized by the non-controlling interest and were credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. For the year ended December 31, 2008, primarily as a result of the ceiling test impairment of the Partnerships' oil and gas properties, losses applicable to the non-controlling interest exceeded the non-controlling interest equity capital by $9.3 million and, as a result, $9.3 million of the non-controlling interest loss in excess of equity was charged to earnings and was reflected as a reduction of the loss applicable to the non-controlling interst.

In June 2008, the FASB ratified EITF Issue No. 07-5, Determining Whether an Instrument (or Embedded Feature) is indexed to an Entity’s Own Stock (“EITF 07-5”). EITF 07-5 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early application is not permitted. EITF 07-5 provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer’s own stock and thus able to qualify for the SFAS No. 133 paragraph 11(a) scope exception. The Company intends to utilize liability treatment of warrants going forward. The adoption of this standard has not had a significant impact on the Company’s consolidated financial position, results of operations or cash flows.

Use of Estimates

The preparation of financial statements in conformity with generally accepted 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 as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Equity-based Compensation

Stock Options

The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees. For the three months ended March 31, 2009 and 2008, the Company recognized $181,000 and $246,000 respectively related to stock options and restricted shares.

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The following table summarizes the stock option activities for the three months ended March 31, 2009. (In thousands, except per share amounts)

	Shares		Weighted Average Option Exercise Price Per Share		Weighted Average Grant Date Fair Value Per Share		Aggregate Intrinsic Value
Outstanding, December 31, 2008	2,390		$	2.81	$	1.60	$	3,830
Granted	905		$	0.99	$	0.70		633
Exercised	—		$	—	$	—		—
Expired or canceled	(61	)	$	4.30	$	2.74		(167	)
Outstanding, March 31, 2009	3,234		$	2.27	$	1.33	$	4,296

The following table shows the weighted average assumptions used in the Black-Scholes valuation of the fair value of option grants during 2009.

Expected dividend yield		0	%
Volatility		81.55	%
Risk free interest rate		2.35	%
Expected life		6.08
Fair value of options granted (in thousands)	$	633
Weighted average grant date fair value of options granted	$	0.70

Additional information related to options at March 31, 2009 and December 31, 2008 is as follows:

	March 31,	December 31,
	2009	2008
Options exercisable	1,952	1,963

As of March 31, 2009, there was approximately $1.3 million of unamortized compensation expense related to outstanding options that will be recognized in 2009 through 2013.

Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. Compensation expense is recorded over the applicable restricted stock vesting periods.

A summary of the Company’s restricted stock activity for the quarter ended March 31, 2009 is presented in the following table:

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	Number of Shares			Weighted average grant date fair value (per share)
Unvested December 31, 2008	164,280		$	3.35
Granted	5,000			0.80
Vested/Released	(4,625	)		3.59
Forfeited	(1,712	)		4.24
Unvested March 31, 2009	162,943		$	3.26

For the quarter ended March 31, 2009, the Company incurred $39,000 in equity based compensation expense relating to restricted stock.

Restricted Unit Awards

Restricted unit awards are awards of partnership units that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the implied market price on the grant date. The implied market price is determined by comparing the average trading yields of comparable publicly-traded master limited partnerships to the most recent quarterly distribution paid or declared by the Partnership. Compensation expense is recorded over the applicable restricted unit vesting periods.

A summary of the Partnership’s restricted unit activity for the quarter ended March 31, 2009 is presented in the following table:

	Number of Units			Weighted average grant date fair value (per Unit)
Unvested December 31, 2008	—		$	—
Granted	52,000			7.23
Vested/Released	—			—
Forfeited	(100	)		7.23
Unvested March 31, 2009	51,900		$	7.23

For the quarter ended March 31, 2009, the Partnership incurred $22,000 in equity based compensation expense relating to restricted units.

Phantom Units

On January 31, 2008, in connection with the closing of an acquisition of properties from St. Mary Land & Exploration Company, the Board of Directors of the general partner of the Partnership awarded phantom units with distribution equivalency rights under its long-term incentive plan to certain key employees of Abraxas Petroleum.

The phantom units and associated distribution equivalency rights will vest over four years and their value is based on the price of common units, as determined by the Board of Directors of the general partner of the Partnership, quarterly cash distributions and the percentage increase in cash distributions over time.

For the quarter ended March 31, 2009, the Partnership incurred $25,000 in equity based compensation expense relating to phantom units.

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Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, 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. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity. The cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production, using commodity prices on the last day of the quarter, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the our financial statements. As of March 31, 2009, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $37.1 million ($4.7 million on Abraxas Petroleum properties and $32.4 million on the Partnership properties). These amounts were calculated considering March 31, 2009 quarter end prices. We did not adjust the capitalized costs of our properties because subsequent to March 31, 2009, crude oil and natural gas prices increased such that capitalized costs did not exceed the present value of the estimated proved oil and gas reserves on a consolidated basis as determined using increased NYMEX prices on May 7, 2009 of $58.32 per Bbl for oil and $4.00 per Mcf for gas.

Working Capital (Deficit).

At March 31, 2009 our current liabilities of approximately $53.8 million exceeded our current assets of $31.3 million resulting in a working capital deficit of $22.5 million. This compares to a working capital deficit of approximately $26.0 million at December 31, 2008. Current liabilities at March 31, 2009 primarily consisted of the current portion of long-term debt consisting of $40.0 million outstanding under the Subordinated Credit Agreement, the current portion of derivative liabilities of $3.0 million, trade payables of $6.4 million, revenues due third parties of $2.4 million, and other accrued liabilities of $1.6 million. The Subordinated Credit Agreement matures on July 1 , 2009. The Partnership has intended to re-pay the amounts due under this agreement with the proceeds of the initial public offering. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. In addition, the Partnership’s failure to receive $20.0 million of proceeds from an equity issuance on or prior to June 30, 2009 would be an event of default under the Subordinated Credit Agreement. The Partnership has engaged an exclusive financial advisor to refinance the Subordinated Credit Agreement. We cannot assure you that the Partnership will successfully refinance this indebtedness. If the Partnership is unable to refinance or amend the indebtedness under its Subordinated Credit Agreement, it may be required to sell assets and reduce capital expenditures and cash distributions. We cannot assure you that the Partnership will be able to re-finance the indebtedness under its Subordinated Credit Agreement, sell assets or obtain additional financing on terms acceptable to it, if at all. If an event of default were to occur under the Subordinated Credit Agreement, an event of default would also occur under the Partnership Credit Facility. Upon an event of default, the lenders could foreclose on the Partnership’s assets and exercise other customary remedies, all of which would have a material adverse effect on us.

Recently Issued Accounting Pronouncements

In April 2009, the FASB issued FSP FAS No. 115-2 and No. 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” FSP SFAS No. 115-2 and SFAS No. 124-2 provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. FSP SFAS No. 115-2 and SFAS No. 124-2 is effective for interim and annual reporting periods beginning after June 15, 2009 and is effective for us at June 30, 2009. We have not yet determined the impact, if any, that the FSP will have on our results of operations or financial position.

In April 2009, the FASB issued FSP No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” FSP No.157-4 provides additional authoritative guidance to assist in determining whether a market is active or inactive, and whether a transaction is distressed. FSP No. 157-4 is effective for interim and annual reporting periods beginning after June 15, 2009 and is effective for us at June 30, 2009. We have not yet determined the impact, if any, that the FSP will have on our results of operations or financial position.

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Management believes the impact of other recently issued accounting standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.

On December 29, 2008, the Securities and Exchange Commission adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves.

The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago.

New disclosure requirements include:

·	Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes.

·	Enabling companies to additionally disclose their probable and possible reserves to investors. Currently, the rules limit disclosure to only proved reserves.

·	Allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves.

·	Requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit.

Requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period – rather than the year-end price – to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

Note 2. Acquisition

On January 31, 2008, Abraxas Operating , LLC, a wholly-owned subsidiary of the Partnership, consummated the acquisition of certain oil and gas properties located in various states from St. Mary Land & Exploration Company (“St. Mary”) and certain other sellers. The properties are primarily located in the Rockies and Mid-Continent regions of the United States, and include approximately 57.2 Bcfe (9,525 MBOE) of estimated proved reserves for a purchase price of approximately $126.0 million.

The Partnership borrowed approximately $115.6 million under the Partnership Credit Facility and $50 million under its Subordinated Credit Agreement in order to complete this acquisition and repay its previously outstanding indebtedness of $45.9 million. For a complete description of these credit facilities, please see Note 4 “Long-Term Debt”.

Simultaneously, Abraxas Petroleum announced that it had completed the acquisition of certain oil and gas properties from St. Mary with estimated proved reserves of approximately 4.3 Bcfe (725 MBOE) for a purchase price of approximately $5.6 million. Abraxas paid the purchase price from its internal funds. The right to purchase these properties had been assigned to Abraxas by the Partnership.

Substantially all amounts paid in the acquisition, including acquisition costs of approximately $1.1 million, were allocated to the oil and gas properties. The following unaudited supplemental information presents pro forma financial results assuming the acquisition had occurred on January 1, 2008. The unaudited pro forma financial results are not necessarily those that would have been attained had the acquisition occurred as of an earlier date, nor are they necessarily representative of the future results that may occur.

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Unaudited Pro Forma Financial Information
	Three months ended March 31, 2008
Revenue	$	25,815
Net Income	$	(6,869	)
Earnings per share - basic	$	(0.14	)

Note 3. 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 three-month period ended March 31, 2009 and 2008, there is no current or deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowance which have been recorded against such benefits.

The Company accounts for uncertain tax positions under provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 did not have any effect on the Company’s financial position or results of operations for the quarters ended March 31, 2008 and 2009. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2009, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2008 remain open to examination by the tax jurisdictions to which the Company is subject.

Note 4. Debt

Long-term debt consisted of the following:


	March 31, 2009			December 31, 2008
Partnership credit facility	$	125,600		$	125,600
Partnership subordinated credit agreement		40,000			40,000
Senior secured credit facility		3,000			—
Real estate lien note		5,335			5,369
		173,935			170,969
Less current maturities		(40,147	)		(40,134	)
	$	133,788		$	130,835

Abraxas Senior Secured Credit Facility. On June 27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50.0 million. Availability under the Credit Facility is subject to a borrowing base. The borrowing base under the Credit Facility, which is currently $6.5 million, is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we may also request one redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our current borrowing base. Our borrowing base at March 31, 2009 of $6.5 million was determined based upon our reserves at December 31, 2008. Our borrowing base can never exceed the $50.0 million maximum commitment amount. Outstanding amounts under the Credit Facility bear interest at (a) the greater of the reference rate announced from time to time by Société Générale, and (b) the Federal Funds Rate plus 0.5% of 1%, plus in each case, (c) 0.5% -

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1.5% depending on utilization of the borrowing base, or, if Abraxas elects, at the London Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization of the borrowing base. At March 31, 2009, the interest rate on the Credit Facility was 2.3%. Subject to earlier termination rights and events of default, the Credit Facility’s stated maturity date is September 30, 2010. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances.

Abraxas is permitted to terminate the Credit Facility, and may, from time to time, permanently reduce the lenders’ aggregate commitment under the Credit Facility in compliance with certain notice and dollar increment requirements.

Each of Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC, which we refer to as the GP, and Abraxas Energy Investments, LLC has guaranteed Abraxas’ obligations under the Credit Facility on a senior secured basis. Obligations under the Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of Abraxas’ and the subsidiary guarantors’ material property and assets.

Under the Credit Facility, Abraxas is subject to customary covenants, including certain financial covenants and reporting requirements. The Credit Facility requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. The current ratio is the ratio of consolidated current assets to consolidated current liabilities. For purposes of this calculation, current assets include, as of the date of the calculation, the portion of the borrowing base which is undrawn but exclude, as of the date of calculation, any cash deposited with or at the request of a counterparty to any derivative contract, any assets representing a valuation account arising from the application of SFAS 133 (which relates to derivative instruments and hedging activities) and SFAS 143 (which relates to asset retirement obligations) and any distributions payable by the Partnership to the GP unless such distributions have been received by the GP in cash, and current liabilities exclude, as of the date of calculation, the current portion of long-term debt, any liabilities representing a valuation account arising from the application of SFAS 133 and SFAS 143 and any liabilities of the GP arising solely in its capacity as a general partner of the Partnership. The interest coverage ratio is the ratio of consolidated EBITDA for the four quarters then ended to consolidated interest for the four quarters then ended. For the purpose of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of SFAS 123R (which relates to stock-based compensation), SFAS 133 and SFAS 143 less all non-cash items of income which were included in determining consolidated net income, including non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letters of credit fees and other fees and expenses incurred in connection with any debt. For purposes of calculating both ratios, any amounts attributable to the Partnership are not included. At March 31, 2009, our current ratio was 0.92 to 1.00 and our interest coverage ratio was 29.68 to 1.00.

In addition to the foregoing and other customary covenants, the Credit Facility contains a number of covenants that, among other things, will restrict Abraxas’ ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates other than on an “arms-length” basis;

· make any change in the principal nature of its business; and

· permit a change of control.

The Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

The Company was in compliance with all covenants as of March 31, 2009 or has obtained a waiver for noncompliance.

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million. Availability under the Partnership Credit Facility is subject to a borrowing base. The borrowing base under the Partnership Credit Facility, which at May 7, 2009, was $130.0 million, is determined semi-annually by the lenders based upon the Partnership’s reserve reports, one of which must be prepared by the Partnership’s independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Partnership’s proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of the Partnership’s then current borrowing base.

The Partnership’s borrowing base at May 7, 2009 of $130.0 million was determined based upon its reserves at December 31, 2008. The borrowing base can never exceed the $300.0 million maximum commitment amount. At March 31, 2009 and May 7, 2009, the Partnership had a total of $125.6 million outstanding under the Partnership Credit Facility. Under the amended terms of the Partnership Credit Facility, on May 14, 2009, Abraxas Petroleum is required to re-pay the distribution of approximately $1.9 million paid to it relating to the fourth quarter of 2008 to the Partnership and the Partnership must, in turn, make a principal payment of approximately $1.9 million under the Partnership Credit Facility. Abraxas Petroleum intends to make this payment on or before May 14, 2009. Once this payment has been made, the borrowing base under the Partnership Credit Facility will be reduced to approximately $128.1 million and the Partnership Credit Facility will have a balance of approximately $123.7 million and availability of $4.4 million. In consideration of making this payment, Abraxas Petroleum will be issued a number of additional units of the Partnership determined by dividing $1.9 million by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by the Partnership times four.

Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR rate plus, in each case, 1.5% - 2.5%, depending on the utilization of the borrowing base, or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate plus in each case, 2.5% - 3.5% depending on the utilization of the borrowing base. At May 7, 2009 the interest rate on the Partnership Credit Facility was 5.5%. Subject to earlier termination rights and events of default, the Partnership Credit Facility’s stated maturity date is January 31, 2012. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Partnership Credit Facility, and under certain circumstances, may be required, from time to time, to permanently reduce the lenders’ aggregate commitment under the Partnership Credit Facility.

The Partnership, GP, which is a wholly-owned subsidiary of Abraxas, and Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we refer to as the Operating Company, have guaranteed the Partnership’s obligations under the Partnership Credit Facility on a senior secured basis. Obligations under the Partnership Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the property and assets of the GP, the Partnership and the Operating Company, other than the GP’s general partner units in the Partnership.

Under the Partnership Credit Facility, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter of not less than 2.50 to 1.00. Current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For purposes of this calculation, current assets include, as of the date of the calculation, the portion of the borrowing base which is undrawn but exclude, as of the date of calculation, any cash deposited with or at the request of a counterparty to any derivative contract and any assets representing a valuation account arising from the application of SFAS 133 and SFAS 143 and current liabilities exclude, as of the date of calculation, the current portion of long-term debt and any liabilities representing a valuation account arising from the application of SFAS 133 and SFAS 143 . The interest coverage ratio is the ratio of consolidated EBITDA for the four quarters then ended to consolidated interest for the four quarters then ended. For the purpose of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the

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application of SFAS 123R, SFAS 133 and SFAS 143 less all non-cash items of income which were included in determining consolidated net income, including non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letters of credit fees and other fees and expenses incurred in connection with any debt. At March 31, 2009, the Partnership’s current ratio was 27.47 to 1.00 and its interest coverage ratio was 4.58 to 1.00.

The Partnership Credit Facility required the Partnership to enter into derivative contracts for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011. The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011. The second amendment to the Partnership Credit Facility required additional derivative contracts for volumes equating to approximately 60% of the estimated oil and gas production from net proved developed reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012.

Under the terms of the Partnership Credit Facility, the Partnership may make cash distributions if, after giving effect to such distributions, the Partnership is not in default under the Partnership Credit Facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under the Partnership Credit Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing base (which at May 7, 2009 was $130.0 million) or the total commitment amount of the Partnership Credit Facility (which at May 7, 2009 was $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under the Partnership Credit Facility after giving effect to such distribution exceeds $20.0 million, or (ii) the Subordinated Credit Agreement shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while the Subordinated Credit Agreement is outstanding. The declaration of the cash distribution to be made by the Partnership on or about May 15, 2009 attributable to the first quarter of 2009 is being deferred. While the Subordinated Credit Agreement is outstanding, the Partnership’s capital expenditures are limited to $12.5 million per year.

In addition to the foregoing and other customary covenants, the Partnership Credit Facility contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

· make any change in the principal nature of its business; and

· permit a change of control.

The Partnership Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Subordinated Credit Agreement described below, bankruptcy and material judgments and liabilities. In addition, an event of default would occur if the Partnership fails to receive a letter of credit, which we refer to as the APC L/C, in its favor from Abraxas Petroleum equal to the May 14, 2009 Payment Amount of approximately $1.9 million, the Partnership fails to draw on the APC L/C on or before May 14, 2009 or the Partnership fails to use the proceeds of the APC L/C to make the principal payment due on May 14, 2009. This event of default would not occur in the event that the Partnership repays the principal amount due on May 14, 2009 with funds received from Abraxas Petroleum. Abraxas Petroleum intends to make this payment to the Partnership on or before May 14, 2009. The Partnership and Abraxas Petroleum have agreed that upon the occurrence of such a payment or the Partnership’s drawing on the APC L/C that, in consideration thereof, the Partnership would issue a number of additional units to Abraxas Petroleum determined by dividing approximately $1.9 million by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by the Partnership times four. Abraxas Petroleum intends to make this payment on or before May 14, 2009. Finally, if the indebtedness under the Subordinated Credit Agreement has not been repaid on or before July 1, 2009, the Partnership must pay the lenders a consent fee of $2.4 million.

The Partnership was in compliance with all covenants as of March 31, 2009.

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Subordinated Credit Agreement

On January 31, 2008, the Partnership entered into a subordinated credit agreement which was amended on January 16, 2009 and further amended on April 30, 2009 and May 7, 2009, which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement has a maximum commitment of $40.0 million. Outstanding amounts under the Subordinated Credit Agreement bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR Offered Rate, plus in each case (b) 9.0% or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate, in each case, plus 10.0%. At May 7, 2009, the interest rate on the Subordinated Credit Agreement was 12.0%. If the Subordinated Credit Agreement is not repaid on or before July 1, 2009, the interest rate will be (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR Offered Rate, plus in each case (b) 12.0% or, if the Partnership elects, at the greater of (a) 2.0% and (b) at the London Interbank Offered Rate plus, in each case, 13.0%. For any interest payment due on or after July 2, 2009, 3% per annum of the accrued interest payable shall be capitalized and added to the principal amount of the loan. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and under certain circumstances, may be required, from time to time, to make prepayments under the Subordinated Credit Agreement.

Subject to earlier termination rights and events of default, the Subordinated Credit Agreement’s stated maturity date is July 1, 2009. The maturity date may be accelerated if any limited partner of the Partnership, other than Perlman Value Partners, exercises its right to convert its limited partner units into shares of common stock of Abraxas Petroleum pursuant to the terms of the exchange and registration rights agreement, as amended, among Abraxas Petroleum, the Partnership and the purchasers named therein. The date on which the purchasers, if the Partnership’s initial public offering has not been consummated prior to that date, may first exchange their Partnership units for Abraxas Petroleum common stock is June 30, 2009.

Each of the GP and the Operating Company has guaranteed the Partnership’s obligations under the Subordinated Credit Agreement on a subordinated secured basis. Obligations under the Subordinated Credit Agreement are secured by subordinated security interests, subject to certain permitted encumbrances, in all of the property and assets of the Partnership, GP, and the Operating Company, other than the GP’s general partner units in the Partnership.

Under the Subordinated Credit Agreement, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Subordinated Credit Agreement requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.00 to 1.00 and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. Current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For purposes of this calculation, current assets include, as of the date of the calculation, the portion of the borrowing base which is undrawn but exclude, as of the date of calculation, any cash deposited with or at the request of a counterparty to any derivative contract and any assets representing a valuation account arising from the application of SFAS 133 and 143, and current liabilities exclude, as of the date of calculation, the current portion of long-term debt and any liabilities representing a valuation account arising from the application of SFAS 133 and 143. The interest coverage ratio is the ratio of consolidated EBITDA for the four quarters then ended to consolidated interest for the four quarters then ended. For the purpose of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of SFAS 123R (which relates to stock-based compensation), SFAS 133 and SFAS 143 less all non-cash items of income which were included in determining consolidated net income, including non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letters of credit fees and other fees and expenses incurred in connection with any debt. At March 31, 2009, the Partnerships current ratio was 27.47 to 1.00 and its interest coverage ratio was 4.58 to 1.00.

The Subordinated Credit Agreement required the Partnership to enter into derivative contracts for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011. The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011. The second amendment to the Partnership Credit Facility required additional derivative contracts for volumes equating to approximately 60% of the estimated oil and gas production from net proved developed reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price

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swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012.

In addition to the foregoing and other customary covenants, the Subordinated Credit Agreement contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

· make any change in the principal nature of its business; and

· permit a change of control.

The Subordinated Credit Agreement also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Partnership Credit Facility, bankruptcy and material judgments and liabilities. An event of default would also occur if the Partnership fails to receive $20.0 million of proceeds from an equity issuance on or before June 30, 2009. In addition, if the indebtedness under the Subordinated Credit Agreement has not been repaid on or before July 1, 2009, the Partnership is required to issue warrants to purchase 2.5% of the then outstanding units to the lenders at an exercise price of $0.01 per unit. Finally, if the indebtedness under the Subordinated Credit Agreement is repaid on or before July 1, 2009, the Partnership must pay the lenders a consent fee of $200,000 upon payment of the loan.

The Partnership was in compliance with all covenants as of March 31, 2009.

The Partnership’s Subordinated Credit Agreement matures on July 1, 2009. The Partnership has intended to repay its indebtedness under the Subordinated Credit Agreement with proceeds from its initial public offering. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. The Partnership is in discussions with other lending institutions to re-finance the $40 million currently outstanding on the Subordinated Credit Agreement. If the Partnership is unable to re-finance or amend the indebtedness under its Subordinated Credit Agreement, it may be required to sell assets and further reduce capital expenditures and cash distributions. We cannot assure you that the Partnership will be able to re-finance the indebtedness under its Subordinated Credit Agreement, sell assets or obtain additional financing on terms acceptable to it, if at all. If an event of default were to occur under the Partnership Subordinated Credit Agreement, an event of default would also occur under the Partnership Credit Facility. Upon an event of default, the lenders could foreclose on the Partnership’s assets and exercise other customary remedies, all of which would have a material adverse effect on us.

Real Estate Lien Note

On May 9, 2008 the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a new building to serve as its corporate headquarters. This note was refinanced in November 2008. The new note bears interest at a fixed rate of 6.375%, and is payable in monthly installments of principal and interest of $39,754 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of March 31, 2009, $5.3 million was outstanding on the note.

5. Condensed Consolidating Financial Statements

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and the operations of the Partnership which was formed on May 25, 2007. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes. The interest of the 52.7% owners of the Partnership are presented as non-controlling interest. Abraxas owns the remaining 47.3% of the partnership interests. The Company has determined that based on its control of the general partner of the Partnership, this 47.3% owned entity should be consolidated for financial reporting purposes. The consolidating financial statements are presented as follows:

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Condensed Consolidating Balance Sheet
March 31, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation		Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Assets:
Cash	$	—	$	613		$	—		$	613
Accounts receivable, less allowance for doubtful accounts		6,030		6,622			(6,914	)		5,738
Derivative asset – current		—		24,424			—			24,424
Other current assets		467		27			—			494
Total current assets		6,497		31,686			(6,914	)		31,269
Property and equipment – net		42,319		115,011			2,771			160,101
Deferred financing fees, net		92		1,631			—			1,723
Derivative asset – long-term		—		21,663			—			21,663
Investment in partnership		11,890		—			(11,890	)		—
Other assets		445		—			—			445
Total assets	$	61,243	$	169,991		$	(16,033	)	$	215,201
Liabilities and Stockholders’ equity:
Current liabilities:
Accounts payable	$	5,962	$	478		$	—		$	6,440
Oil and gas production payable		7,433		—			(4,990	)		2,443
Accrued interest		20		222			—			242
Other accrued expenses		3,504		—			(1,924	)		1,580
Derivative liability – current		—		2,950			—			2,950
Current maturities of long-term debt		147		40,000			—			40,147
Dividend payable		—		19			—			19
Total current liabilities		17,066		43,669			(6,914	)		53,821
Long-term debt		8,188		125,600			—			133,788
Future site restoration		928		9,179			—			10,107
Total liabilities		26,182		178,448			(6,914	)		197,716

Abraxas Petroleum equity (deficit)		35,061		(8,457)			(17,129	)		9,475
Non-controlling interest (deficit)		—		—			8,010			8,010
Total equity (deficit)		35,061		(8,457	)		(9,119	)		17,485
Total liabilities and stockholders’ equity (deficit)	$	61,243	$	169,991		$	(16,033	)	$	215,201

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Condensed Consolidating Balance Sheet
December 31, 2008
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation		Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Assets:
Cash	$	—	$	1,924		$	—		$	1,924
Accounts receivable, less allowance for doubtful accounts		11,514		7,695			(11,243	)		7,966
Derivative asset – current		—		22,832			—			22,832
Other current assets		535		37			—			572
Total current assets		12,049		32,488			(11,243	)		33,294
Property and equipment – net		41,291		119,017			—			160,308
Deferred financing fees, net		102		1,341			—			1,443
Derivative asset – long-term		—		16,394			—			16,394
Investment in partnership		11,889		—			(11,889	)		—
Other assets		400		—			—			400
Total assets	$	65,731	$	169,240		$	(23,132	)	$	211,839
Liabilities and Stockholders’ equity:
Current liabilities:
Accounts payable	$	9,606	$	1,142		$	—		$	10,748
Oil and gas production payable		12,053		8			(8,885)			3,176
Accrued interest		18		332			—			350
Other accrued expenses		1,643		243			—			1,886
Derivative liability – current		—		3,000			—			3,000
Current maturities of long-term debt		134		40,000			—			40,134
Dividend payable		—		2,358			(2,358	)		—
Total current liabilities		23,454		47,083			(11,243	)		59,294
Long-term debt		5,235		125,600			—			130,835
Future site restoration		910		9,049			—			9,959
Total liabilities		29,599		181,732			(11,243	)		200,088

Abraxas Petroleum equity (deficit)		36,132		(12,492	)		(18,982	)		4,658
Non-controlling interest equity		—		—			7,093			7,093
Total equity (deficit)		36,132		(12,492	)		(11,889	)		11,751
Total liabilities and stockholders’ equity (deficit)	$	65,731	$	169,240		$	(23,132	)	$	211,839

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Condensed Consolidating Parent Company and Subsidiary Statement of Operations
For the three months ended March 31, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Revenues:
Oil and gas production revenues	$	1,966		$	8,630		$	—		$	10,596
Rig revenues		253			—			—			253
Other		1			—			—			1
		2,220			8,630			—			10,850
Operating costs and expenses:
Lease operating and production taxes		1,065			4,804			—			5,869
Depreciation, depletion, and amortization		957			3,526			4			4,487
Impairment		—			2,775			(2,775	)		—
Rig operations		188			—			—			188
General and administrative		1,322			807			—			2,129
		3,532			11,912			(2,771	)		12,673
Operating loss		(1,312	)		(3,282	)		2,771			(1,823	)

Other (income) expense:
Interest income		(3	)		(2	)		—			(5	)
Amortization of deferred financing fees		10			202			—			212
Interest expense		118			2,438			—			2,556
Financing fees		—			362			—			362
Gain on derivative contracts		—			(12,865	)		—			(12,865	)
Other		—			21			—			21
		125			(9,844	)		—			(9,719	)
Net income (loss)		(1,437	)		6,562			2,771			7,896
Less: Net income attributable to non-controlling interest		—			—			(3,446	)		(3,446	)
Net loss attributable to Abraxas Petroleum Corporation	$	(1,437	)	$	6,562		$	(675	)	$	4,450

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Condensed Consolidating Parent Company and Subsidiary Statement of Operations
For the three months ended March 31, 2008
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations		Consolidated
Revenues:
Oil and gas production revenues	$	3,047		$	18,816		$	—	$	21,863
Rig revenues		306			—			—		306
Other		1			—			—		1
		3,354			18,816			—		22,170
Operating costs and expenses:
Lease operating and production taxes		776			4,426			—		5,202
Depreciation, depletion, and amortization		590			4,504			—		5,094
Rig operations		210			—			—		210
General and administrative		1,285			514			—		1,799
		2,861			9,444			—		12,305
Operating income		493			9,372			—		9,865

Other (income) expense:
Interest income		(83	)		(13	)		—		(96	)
Amortization of deferred financing fees		10			184			—		194
Interest expense		22			2,444			—		2,466
Loss on derivative contracts		—			26,958			—		26,958
		(51	)		29,573			—		29,522
Net income (loss)		544			(20,201	)		—		(19,657	)
Less: Net loss attributable to non-controlling interest		—			—			10,666		10,666
Net income (loss) attributable to Abraxas Petroleum Corporation.	$	544		$	(20,201	)	$	10,666	$	(8,991	)

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Condensed Consolidating Parent Company and Subsidiary Statement of Cash Flows
For the three months ended March 31, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Operating Activities
Net income (loss)	$	(1,437	)	$	6,562		$	2,771		$	7,896
Adjustments to reconcile net income to net cash provided by operating activities:
Change in derivative fair value		—			(6,911	)		—			(6,911	)
Depreciation, depletion, and amortization		957			3,526			4			4,487
Proved property impairment		—			2,775			(2,775	)		—
Accretion of future site restoration		13			128			—			141
Amortization of deferred financing fees		10			202			—			212
Stock-based compensation		220			47			—			267
Other non-cash transactions		18			—			—			18
Changes in operating assets and liabilities:
Accounts receivable		(769	)		1,073			1,924			2,228
Other assets		65			10			—			75
Accounts payable		(2,445	)		(672	)		(1,924	)		(5,041	)
Accrued expenses		2,317			(2,739	)		—			(422	)
Net cash provided by (used in) operations		(1,051	)		4,001			—			2,950

Investing Activities
Capital expenditures, including purchases and development of properties – net of dispositions		(1,978	)		(2,293	)		—			(4,271	)
Net cash used in investing activities		(1,978	)		(2,293	)		—			(4,271	)

Financing Activities
Proceeds from issuance of common stock
Proceeds from long-term borrowings		3,000			—			—			3,000
Payments on long-term borrowings		(34	)		—			—			(34	)
Partnership distribution		86			(2,343	)		—			(2,257	)
Deferred financing fees		—			(492	)		—			(492	)
Other		(23	)		(184	)		—			(207	)
Net cash provided by (used in) financing activities		3,029			(3,019	)		—			10
Decrease in cash		—			(1,311	)		—			(1,311	)
Cash at beginning of year		—			1,924			—			1,924
Cash at end of year	$	—		$	613		$	—		$	613

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Condensed Consolidating Parent Company and Subsidiary Statement of Cash Flows
For the three months ended March 31, 2008
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations		Consolidated
Operating Activities
Net income (loss)	$	544		$	(20,201	)	$	—	$	(19,657	)
Adjustments to reconcile net income to net cash provided by operating activities:
Change in derivative fair value		—			23,541			—		23,541
Depreciation, depletion, and amortization		590			4,504			—		5,094
Accretion of future site restoration		(25	)		145			—		120
Amortization of deferred financing fees		10			184			—		194
Stock-based compensation		246			—			—		246
Other non-cash transactions		21			—			—		21
Changes in operating assets and liabilities:
Accounts receivable		(3,760	)		(4,749	)		—		(8,509	)
Other assets		19			12			—		31
Accounts payable and accrued expenses		(1,442	)		10,037			—		8,595
Net cash provided by (used in) operations		(3,797	)		13,473			—		9,676

Investing Activities
Capital expenditures, including purchases and development of properties		(9,964	)		(127,895	)		—		(137,859	)
Net cash used in investing activities		(9,964	)		(127,895	)		—		(137,859	)

Financing Activities
Proceeds from issuance of common stock		15			—			—		15
Proceeds from long-term borrowings		—			119,700			—		119,700
Partnership distribution		2,008			(4,406	)		—		(2,398	)
Deferred financing fees		—			(1,499	)		—		(1,499	)
Net cash provided by financing activities		2,023			113,795			—		115,818
Decrease in cash		(11,738	)		(627	)		—		(12,365	)
Cash at beginning of year		17,177			1,759			—		18,936
Cash at end of year	$	5,439		$	1,132		$	—	$	6,571

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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,
	2009		2008
Numerator:	(in thousands except per share data)
Net income ( loss) available to common stockholders	$	4,450	$	(8,991	)
Denominator:
Denominator for basic earnings per share – weighted-average shares		49,499,062		48,871,974
Effect of dilutive securities:
Stock options and warrants		343,434		—
Denominator for diluted earnings per share - adjusted weighted-average shares and assumed Conversions		49,842,446		48,871,974
Net income (loss) per common share – basic	$	0.09	$	(0.18	)
Net income (loss) per common share – diluted	$	0.09	$	(0.18	)

For the three months ended 2008, 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 the period, dilutive shares would have been 339,122 for the three months ended March 31, 2008.

Note 7. Hedging Program and Derivatives

The Company does not use hedge accounting rules as prescribed by SFAS 133 Accounting for Derivative Instruments and Hedging Activities, and related interpretations. Accordingly, instruments are recorded on the balance sheet at their fair value with adjustments to the carrying value of the instruments being recognized in gain loss on derivative contracts in the current period.

The following table sets forth the Partnership’s derivative contract position at March 31, 2009:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2009	Gas	10,595 Mmbtu	$8.44
Year 2009	Oil	1,000 Bbl	$83.80
Year 2010	Gas	9,130 Mmbtu	$8.22
Year 2010	Oil	895 Bbl	$83.26
Year 2011	Gas	8,010 Mmbtu	$8.10
Year 2011	Oil	810 Bbl	$86.45

At March 31, 2009, the aggregate fair market value of our commodity derivative contracts was approximately $46.1 million. In connection with the April 30, 2009 amendment to the Partnership Credit Facility, the Partnership was required to enter into additional derivative contracts for volumes equating to approximately 60%

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of the estimated oil and gas production from net proved developed reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012.

In order to mitigate its interest rate exposure, the Partnership entered into an interest rate swap, effective August 12, 2008, amended in February 2009, to fix its floating LIBOR based debt. The 2-year interest rate swap arrangement is for $100 million at a fixed rate of 2.95%. The arrangement expires on August 12, 2010. The fair value of this interest rate swap was a liability of $2.9 million.

Note 8. Financial Instruments

SFAS 157—Effective January 1, 2008, the Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate, which was not material. The primary impact from adoption was additional disclosures.

The Company elected to implement SFAS 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”), issued February 2008, which deferred the effective date of SFAS 157 for one year for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. As it relates to the Company, the deferral applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and gas property assessments; and the initial recognition of asset retirement obligations for which fair value is used.

Fair Value Hierarchy—SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2- inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

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	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of March 31, 2009
Assets
Investment in common stock	$	155	$	—	$	—	$	155
NYMEX-based fixed price derivative contracts		—		46,087		—		46,087
Total assets	$	155	$	46,087	$	—	$	46,242
Liabilities
Interest Rate Swaps	$	—	$	—	$	2,950	$	2,950
Total Liabilities	$	—	$	—	$	2,950	$	2,950

The Company has an investment in a former subsidiary consisting of shares of common stock. The stock is actively traded on the Toronto Stock Exchange. This investment is valued at its quoted price as of March 31, 2009 in US dollars. Accordingly this investment is characterized as Level 1.

The Partnership’s derivative contracts consist of NYMEX-based fixed price commodity swaps and interest rate swaps, which are not traded on a public exchange. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity, and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2.

In August 2008, the Partnership entered into a two year interest rate swap. The notional amount is $100.0 million for the first year and $50.0 million for the second year. The Partnership will pay interest at 3.367% and be paid on a floating Libor rate. The interest rate swap was amended in February 2009 and increased the notional amount in the second year to $100.0 million and reduced the overall interest rate to 2.95%. As there is no actively traded market for this type of swap and no observable market parameters, these derivative contracts are classified as Level 3.

Additional information for the Partnership’s recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the quarter ended March 31, 2009 is as follows (in thousands):

	Derivative Assets and (Liabilities) net
Balance December 31, 2008	$	(3,000	)
Total realized and unrealized losses included in change in net liability		(512	)
Settlements during the period		562
Ending balance March 31, 2009	$	(2,950	)

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Note 9. Contingencies - Litigation

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 March 31, 2009, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its operations.

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

The following is a discussion of our 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, included in our Annual Report on Form 10-K filed for the year ended December 31, 2008 filed with the Securities and Exchange Commission on February 24, 2009. The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we”, “us”, “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 52.7% non-controlling owners presented as non-controlling interest. Abraxas owns the remaining 47.3% of the partnership interests.

Critical Accounting Policies

Except as set forth in the following paragraph, there have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2008.

General

We are independent energy company primarily engaged in the development and production of oil and gas. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our development and exploration activities is critical to the maintenance and growth of our current production levels and associated reserves.

Factors Affecting Our Financial Results

While we have attained positive net income in three of the five years ended December 31, 2008, we sustained a loss in the year ended December 31, 2008 and we cannot assure you that we can achieve positive operating income and net income in the future. Our financial results depend upon many factors, which significantly affect our results of operations including the following:

· the sales prices of oil and gas;

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· the level of total sales volumes of oil and 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 of success of exploitation, exploration and development activity.

Commodity Prices and Hedging Activities.

The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, price differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis. Recently, the prices of oil and gas have been volatile. During the first quarter of 2009, prices of oil and gas declined significantly from the near record levels experienced during the firstquarter of 2008. During the first quarter of 2009, the New York Mercantile (NYMEX) price for West Texas Intermediate (WTI) averaged $43.19 per barrel as compared to $97.81 per barrel during the first quarter of 2008. NYMEX Henry Hub spot prices for gas averaged $4.55 per million British thermal units (MMBtu) for the first quarter of 2009 compared to $8.64 for the same period of 2008. Prices closed the quarter at $49.66 per Bbl of oil and $3.61 per MMBtu of gas and continue to be significantly lower when compared to the same period of 2008. The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:

basis differentials which are dependent on actual delivery location,

adjustments for BTU content; and

gathering, processing and transportation costs.

During the first quarter of 2009, differentials averaged $8.06 per Bbl of oil and $0.92 per Mcf of gas as compared to $4.18 per Bbl of oil and $1.32 per Mcf of gas during the first quarter of 2008. We are realizing greater differentials during 2009 as compared to 2008 because of the increased percentage of our production from the Rocky Mountain and Mid-Continent regions which experience higher differentials than our Texas properties. Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 and 60% of the estimated oil and gas production from its net estimated proved developed producing reserves for calendar year 2012. By removing a significant portion of price volatility on its future oil and gas production, the Partnership believes it will mitigate, but not eliminate, the potential effects of changing commodity gas prices on its cash flow from operations for those periods. Because the prices at which we have hedged our oil and gas production are significantly higher than current commodity prices, we will realize increased cash flow on the portion of our production that we have hedged and we will sustain realized and unrealized gains on our derivative contracts. Conversely, our commodity price hedging strategy has limited and may in the future limit our ability to realize increased cash flow from price increases. The Partnership intends to enter into derivative contracts in the future to reduce the impact of price volatility on its cash flow. The prices at which future production is hedged will be dependent upon commodity prices at the time the agreement is entered into, which may be substantially higher or lower than current oil and gas prices. Accordingly, future commodity derivative contracts may not protect us from significant declines in oil and gas prices. We have not elected hedge accounting as allowed by applicable accounting rules.

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The following table sets forth the Partnership’s derivative contract position at March 31, 2009:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2009	Gas	10,595 Mmbtu	$8.44
Year 2009	Oil	1,000 Bbl	$83.80
Year 2010	Gas	9,130 Mmbtu	$8.22
Year 2010	Oil	895 Bbl	$83.26
Year 2011	Gas	8,010 Mmbtu	$8.10
Year 2011	Oil	810 Bbl	$86.45

In connection with the April 30, 2009 amendment to the Partnership Credit Facility, the Partnership was required to enter into additional derivative contracts for volumes equating to approximately 60% of the estimated oil and gas production from net proved developed producing reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012.

At March 31, 2009, the aggregate fair market value of our derivative contracts was approximately $46.1 million.

Production Volumes. Because our proved reserves will decline as oil and gas are produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Approximately 85% of the estimated ultimate recovery of Abraxas’ and 92% of the Partnership’s, or 92% of our consolidated proved developed producing reserves as of December 31, 2008 had been produced. Based on the reserve information set forth in our reserve estimates as of December 31, 2008, Abraxas’ average annual estimated decline rate for its net proved developed producing reserves is 18% during the first five years, 13% in the next five years, and approximately 7% thereafter. Based on the reserve information set forth in our reserve estimates as of December 31, 2008, the Partnership’s average annual estimated decline rate for its net proved developed producing reserves is 10% during the first five years, 8% in the next five years and approximately 8% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While Abraxas has had some success in finding, acquiring and developing additional revenues, Abraxas has not always been able to fully replace the production volumes lost from natural field declines and prior property sales. For example, in 2006, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we replaced 219% of the reserves we produced and in 2008, we replaced 555% of the reserves we produced primarily as a result of the St. Mary property acquisition in January 2008. 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, exploration and development projects.

We had capital expenditures of $4.3 million during the first quarter of 2009 of which $2.3 million was by the Partnership and $2.0 million was by Abraxas Petroleum and our capital budget for 2009 is approximately $32.0 million, of which $20.0 million is applicable to Abraxas and $12.0 million applicable to the Partnership. Under the terms of the Partnership Credit Facility, the Partnership’s capital expenditures may not exceed $12.5 million prior to the termination of the Partnership’s Subordinated Credit Agreement. The final amount of our capital expenditures for 2009 will depend on our success rate, production levels, the availability of capital and commodity prices.

Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, distributions from the Partnership, which are currently restricted by terms of the Partnership Credit Facility, sales of debt or equity securities, if available, and, if an appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it. At March 31, 2009, Abraxas had approximately $3.5 million of availability under the Credit Facility and the Partnership had approximately $14.4 million of availability under the Partnership Credit Facility.

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The Partnership’s Subordinated Credit Agreement matures on July 1, 2009. The Partnership has intended to repay its indebtedness under the Subordinated Credit Agreement with proceeds from its initial public offering. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. The Partnership is in discussions with other lending institutions to re-finance the $40 million currently outstanding on the Subordinated Credit Agreement. If the Partnership is unable to re-finance or amend the indebtedness under its Subordinated Credit Agreement , it may be required to sell assets and further reduce capital expenditures and cash distributions. We cannot assure you that the Partnership will be able to re-finance the indebtedness under its Subordinated Credit Agreement, sell assets or obtain additional financing on terms acceptable to it, if at all. If an event of default were to occur under the Partnership Subordinated Credit Agreement, an event of default would also occur under the Partnership Credit Facility. Upon an event of default, the lenders could foreclose on the Partnership’s assets and exercise other customary remedies, all of which would have a material adverse effect on us.

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. Our properties are concentrated in locations that facilitate substantial economies of scale in drilling and production operations and more efficient reservoir management practices. At December 31, 2008, we operated properties accounting for approximately 83% of our reserves, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified 234 additional drilling locations (of which 109 were classified as proved undeveloped at December 31, 2008) on our existing leasehold, the successful development of which we believe could significantly increase our production and proved reserves.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. In 2006, for example, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we replaced 219% of our reserves, and in 2008, we replaced 555% of our reserves, primarily as the result of the St. Mary property acquisition in January 2008. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations, distributions of available cash from the Partnership to Abraxas and the amount that Abraxas is able to borrow under its credit facility and that the Partnership will be able to borrow under its credit facility will also decline. In addition, approximately 65% of Abraxas’ and 39% of the Partnership’s estimated proved reserves at December 31, 2008 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected.

Borrowings and Interest. The Partnership had indebtedness of approximately $125.6 million under the Partnership Credit Facility and $40 million under its Subordinated Credit Agreement as of March 31, 2009. At May 7, 2009, the Partnership had $4.4 million available under the Partnership Credit Facility. Under the amended terms of the Partnership Credit Facility, on May 14, 2009, Abraxas Petroleum is required to re-pay the distribution of approximately $1.9 million paid to it relating to the fourth quarter of 2008 to the Partnership and the Partnership must, in turn, make a principal payment of approximately $1.9 million under the Partnership Credit Facility. Once this payment has been made, the borrowing base under the Partnership Credit Facility will be reduced to approximately $128.1 million and the Partnership Credit Facility will have a balance of approximately $123.7 million and availability of $4.4 million. Abraxas Petroleum intends to make this payment on or before May 14, 2009. In consideration of making this payment, Abraxas Petroleum will be issued a number of additional units of the Partnership determined by dividing approximately $1.9 million by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by the Partnership times four. At March 31, 2009, Abraxas had indebtedness of $3.0 million and availability of $3.5 million under its Credit Facility. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our numerous drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices. In order to mitigate its interest rate exposure, the Partnership entered

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into an interest rate swap, effective August 12, 2008, to fix its floating LIBOR-based debt. The Partnership’s two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% expires on August 12, 2010. This interest rate swap was amended in February 2009 lowering the Partnership’s fixed rate to 2.95%.

Results of Operations

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

	Three Months Ended March 31,
	2009			2008 (2)
	(in thousands)
Operating Revenue: (1)
Oil sales	$	5,030		$	10,858
Gas sales		5,566			11,005
Rig operations		253			306
Other		1			1
	$	10,850		$	22,170

Operating Income (loss)	$	(1,823	)	$	9,865

Oil production (MBbl)		143.2			116.0
Gas production (MMcf)		1,621			1,504
Average oil sales price ($/Bbl)	$	35.13		$	93.63
Average gas sales price ($/Mcf)	$	3.43		$	7.32

(1) Revenue and average sales prices are before the impact of derivative activities.

(2) Includes results of operations for properties acquired from St. Mary Land & Exploration for February and March 2008.

Comparison of Three Months Ended March 31, 2009 to Three Months Ended March 31, 2008

Operating Revenue. During the three months ended March 31, 2009, operating revenue from oil and gas sales decreased to $10.6 million from $21.9 million for the first quarter of 2008. The decrease in revenue was primarily due to significant decreases in commodity prices during the first quarter of 2009. Decreased prices had a negative impact on oil and gas revenue of $12.6 million. Increased production volumes contributed $1.3 million to oil and gas revenue for the quarter ended March 31, 2009.

Average sales prices before the impact of derivative activities for the quarter ended March 31, 2009 were:

§ $35.13 per Bbl of oil,

§ $ 3.43 per Mcf of gas

Average sales prices before the impact of derivative activities for the quarter ended March 31, 2008 were:

§ $93.63 per Bbl of oil,

§ $ 7.32 per Mcf of gas

Oil sales volumes increased from 116.0 MBbls during the quarter ended March 31, 2008 to 143.2 MBbls for the same period of 2009. The increase in oil sales volumes was primarily due to production from properties acquired in the St. Mary acquisition that closed on January 31, 2008. Production for the quarter ended March 31, 2008 included

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the months of February and March from these properties and added 64.7 MBbls of oil. For the quarter ended March 31, 2009 production from these properties contributed 85.5 MBbls of oil. Gas production volumes increased from 1,504 MMcf for the three months ended March 31, 2008 to 1,621 MMcf for the same period of 2009. The properties acquired in the St. Mary acquisition contributed 468.0 MMcf of gas production for the quarter ended March 31, 2009 as compared to 352.9 MMcf of gas production during the first quarter of 2008. This increase was partially offset by natural field declines.

Lease Operating Expenses. Lease operating expenses (“LOE”) for the three months ended March 31, 2009 increased to $5.9 million compared to $5.2 million in 2008. The increase in LOE was partially related to the properties acquired in the St. Mary property acquisition. These properties added $ 2.5 million to LOE during the first quarter of 2009 as compared to $1.5 million to LOE during the first quarter of 2008. LOE on a per BOE basis for the three months ended March 31, 2009 was $14.20 per BOE compared to $14.19 for the same period of 2008.

General and Administrative (“G&A”) Expenses. G&A expenses, excluding stock-based compensation, increased to $1.9 million for the quarter ended March 31, 2009 compared to $1.3 million during for the quarter ended March 31, 2008. The increase in G&A was primarily due to higher professional fees in 2009 as compared to 2008. G&A expense on a per BOE basis was $4.50 for the first quarter of 2009 compared to $4.24 for the same period of 2008. The increase in G&A expense on a per BOE basis was primarily due to increased cost in the first quarter of 2009 compared to the same period in 2008.

Equity-based Compensation. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees. Options granted to employees are valued at the date of grant and expense is recognized over the options vesting period. In addition to options, restricted shares of the Company’s common stock and restricted units of the Partnership have been granted. For the quarters ended March 31, 2009 and 2008, equity based compensation was approximately $267,000 and $246,000 respectively. The increase in 2009 as compared to 2008 was due to the grant of options and restricted units in the first quarter of 2009.

Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization (“DD&A”) expense decreased to $4.5 million for the three months ended March 31, 2009 from $5.1 million for same period of 2008. The decrease in DD&A was primarily the result of a reduction in the depletion base as a result of the proved property impairment recorded for the year ended December 31, 2008. Our DD&A on a per BOE basis for the three months ended March 31, 2009 was $10.85 per BOE compared to $13.89 per BOE in 2008. The decrease in the per BOE DD&A was due to the lower depletion base for the period.

Interest Expense. Interest expense was consistent at $2.6 million for the first three months of 2009 and $2.5 million for the same period of 2008. The interest rates on the Credit Facility averaged approximately 2.5%, on the Partnership Credit Facility approximately 4.0% and on the Subordinated Credit Agreement approximately 10.1% for the quarter ended March 31, 2009.

Gain (loss) from derivative contracts. We account for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of the derivative contract is recognized in earnings during the current period. The Partnership has entered into a series of NYMEX–based fixed price commodity swaps, the estimated unearned value of these derivative contracts was approximately $46.1 million as of March 31, 2009. For the quarter ended March 31, 2009, we realized a gain on these derivative contracts of $7.0 million.

Ceiling Limitation Write-down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, 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. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash

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flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity. The cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production, using commodity prices on the last day of the quarter, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the our financial statements. As of March 31, 2009, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $37.1 million ($4.7 million on Abraxas Petroleum properties and $32.4 million on the Partnership properties). These amounts were calculated considering March 31, 2009 quarter end prices. We did not adjust the capitalized costs of our properties because subsequent to March 31, 2009, crude oil and natural gas prices increased such that capitalized costs did not exceed the present value of the estimated proved oil and gas reserves on a consolidated basis as determined using increased NYMEX prices on May 7, 2009 of $58.32 per Bbl for oil and $4.00 per Mcf for gas.

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed. 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 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 reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.

Non-controlling interest. Non-controlling interest represents the share of the net income (loss) of Abraxas Energy Partners for the period owned by the partners other than Abraxas Petroleum. For the quarter ended March 31, 2009, the non-controlling interest in the net income of the Partnership was approximately $3.4 million.

Recently Issued Accounting Pronouncements

Management believes the impact of other recently issued accounting standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.

New disclosure requirements include:

·	Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes.

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·	Enabling companies to additionally disclose their probable and possible reserves to investors. Currently, the rules limit disclosure to only proved reserves.

·	Allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves.

·	Requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit.

Liquidity and Capital Resources

General. The oil and 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 additional oil and gas properties; and

production and transportation facilities.

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to continue to grow the business through the development of existing properties and the acquisition of new properties.

Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under its credit facility, distributions from the Partnership, which are currently restricted, and if an appropriate opportunity presents itself, proceeds from the sale of properties. We may also seek equity capital although we may not be able to complete any equity financings on terms acceptable to us, if at all. The Partnership’s principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it.

Working Capital (Deficit). At March 31, 2009, our current liabilities of approximately $53.8 million exceeded our current assets of $31.3 million resulting in a working capital deficit of $22.5 million. This compares to a working capital deficit of approximately $26.0 million at December 31, 2008. Current liabilities at March 31, 2009 primarily consisted of the current portion of long-term debt consisting of $40.0 million outstanding under the Subordinated Credit Agreement, the current portion of derivative liabilities of $3.0 million, trade payables of $6.4 million, revenues due third parties of $2.4 million, and other accrued liabilities of $1.6 million. The Subordinated Credit Agreement matures on July 1 , 2009. The Partnership has intended to re-pay the amounts due under this agreement with the proceeds of the initial public offering. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. In addition, the Partnership’s failure to receive $20.0 million of proceeds from an equity issuance on or prior to June 30, 2009 would be an event of default under the Subordinated Credit Agreement. The Partnership has engaged an exclusive financial advisor to refinance the Subordinated Credit Agreement. We cannot assure you that the Partnership will successfully refinance this indebtedness. If the Partnership is unable to refinance or amend the indebtedness under its Subordinated Credit Agreement, it may be required to sell assets and reduce capital expenditures and cash distributions. We cannot assure you that the Partnership will be able to re-finance the indebtedness under its Subordinated Credit Agreement, sell assets or obtain additional financing on terms acceptable to it, if at all. If an event of default were to occur under the Subordinated Credit Agreement, an event of default would also occur under the Partnership Credit Facility. Upon an event of default, the lenders could foreclose on the Partnership’s assets and exercise other customary remedies, all of which would have a material adverse effect on us.

Capital expenditures. Capital expenditures during the first three months of 2009 were $4.3 million compared to $137.9 million during the same period of 2008. The table below sets forth the components of these capital expenditures on a historical basis for the three months ended March 31, 2009 and 2008.

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	Three Months Ended March 31,
	2009		2008
	(in thousands)
Expenditure category:
Acquisitions	$	—	$	131,333
Development		4,238		6,340
Facilities and other		33		186
Total	$	4,271	$	137,859

During the three months ended March 31, 2009, capital expenditures were primarily for development of our existing properties. During the three months ended March 31, 2008, capital expenditures were primarily for the acquisition of properties from St. Mary as well as the development of our existing properties. We anticipate making capital expenditures of $20 million in 2009. The Partnership anticipates making capital expenditures for 2009 of $12 million which will be used primarily for the development of its current properties. These anticipated expenditures are subject to adequate cash flow from operations, availability under our Credit Facility and the Partnership’s Credit Facility and, in Abraxas’ case, distributions of available cash from the Partnership, which are currently restricted by the Partnership Credit Facility. If these sources of funding do not prove to be sufficient, we may also issue additional shares of equity securities although we may not be able to complete equity financings on terms acceptable to us, if at all. Our ability to make all of our budgeted capital expenditures will also be subject to availability of drilling rigs and other field equipment and services. Our capital expenditures could also include expenditures for the acquisition of producing properties if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of oil and gas decline and if our costs of operations continue to increase or if our production volumes decrease, 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 oil and gas production volumes decreases caused by natural field declines and sales of producing properties, if any.

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:

	Three Months Ended March 31,
	2009			2008
	(in thousands)
Net cash provided by operating activities	$	2,950		$	9,676
Net cash used in investing activities		(4,271	)		(137,859	)
Net cash provided by financing activities		10			115,818
Total	$	(1,311	)	$	(12,365	)

Operating activities during the three months ended March 31, 2009 provided us $2.9 million of cash compared to providing $9.7 million in the same period in 2008. The 2009 period includes cash provided by the Partnership of approximately $5.9 million and cash used by Abraxas Petroleum of approximately ($3.0) million. Net income plus non-cash expense items during 2009 and 2008 and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $115.8 million for the first three months of 2008 compared to providing $10,000 for the same period of 2009. Funds provided in 2008 were primarily proceeds from the Partnership Credit Facility and Subordinated Credit Agreement. Funds provided in 2009 were borrowings under the Credit Facility of $3.0 million less distributions by the Partnership to its partners of approximately $2.3 million. In addition, under the amended terms of the Partnership Credit Facility, Abraxas Petroleum is required to repay the distribution for the fourth quarter of 2008 of approximately $1.9 million to the Partnership which must, in turn, make a principal payment under the Partnership Credit Facility of approximately $1.9 million. Investing activities used $4.3 million during the three months ended March 31, 2009 compared to using $137.9 million for the quarter ended March 31, 2008. For the first quarter of 2009, capital expenditures were primarily for the development of existing properties. Expenditures during the quarter ended March 31, 2008 were primarily for the acquisition of properties from St. Mary Land and Exploration as well as the development of our existing properties.

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Future Capital Resources. Since the formation of the Partnership in May 2007, Abraxas’ sources of capital going forward have primarily been cash from operating activities, funding under the Credit Facility and distributions from the Partnership. As a result of the most recent amendments to the Partnership Credit Facility, Abraxas Petroleum will not be able to receive distributions from the Partnership until such time as the indebtedness under the Subordinated Credit Agreement has been repaid and is required to repay the distribution it received for the fourth quarter of 2008 of approximately $1.9 million. Abraxas Petroleum may also sell debt or equity securities or conduct asset sales in order to provide itself with capital. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility, and sales of debt or equity securities, if available to it.

Cash from operating activities is dependent upon commodity prices and production volumes. Oil and gas prices are volatile and declined significantly during the second half of 2008 and have continued to decline since the end of the year. Further, the decline in commodity prices has not been accompanied by a relative decline in the prices of goods and services that we use to drill, complete and operate our wells. The decline in commodity prices has significantly reduced our cash flow from operations. As the result of the global recession, commodity prices may stay depressed which could further reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans.

Our cash flow from operations will also depend upon the volume of oil and gas that we produce. Unless we otherwise expand reserves, our production volumes may decline as reserves are produced. For example, in 2006, Abraxas replaced only 7% of the reserves it produced. In 2007 we replaced 219% of the reserves we produced and in 2008, we replaced 555% of the reserves we produced, primarily as the result of the St. Mary property acquisition in January 2008. In the future, if an appropriate opportunity presents itself, we may sell producing 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 and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be found. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations, distributions from the Partnership and the amount that we are able to borrow under our credit facilities will also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 65% of Abraxas Petroleum’s and 39% of the Partnership’s total estimated proved reserves at December 31, 2008 were undeveloped.

Our Credit Facility and the Partnership Credit Facility are each subject to a borrowing base. Our Credit Facility matures on September 30, 2010 and the Partnership Credit Facility matures on January 31, 2012. Should current credit market volatility be prolonged for several years, future extensions of credit may contain terms that are less favorable than those in our Credit Facility and the Partnership Credit Facility. The Subordinated Credit Agreement matures on July 1, 2009. The Partnership has intended to re-pay the amounts due under this agreement with the proceeds of the initial public offering. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. In addition, the Partnership’s failure to receive $20.0 million of proceeds from an equity issuance on or prior to June 30, 2009 would be an event of default under the Subordinated Credit Agreement. The Partnership has engaged an exclusive financial advisor to refinance the Subordinated Credit Agreement. We cannot assure you that the Partnership will successfully refinance this indebtedness. If the Partnership is unable to refinance or amend the indebtedness under its Subordinated Credit Agreement, it may be required to sell assets and reduce capital expenditures and cash distributions. We cannot assure you that the Partnership will be able to re-finance the indebtedness under its Subordinated Credit Agreement, sell assets or obtain additional financing on terms acceptable to it, if at all. If an event of default were to occur under the Subordinated Credit Agreement, an event of default would also occur under the Partnership Credit Facility. Upon an event of default, the lenders could foreclose on the Partnership’s assets and exercise other customary remedies, all of which would have a material adverse effect on us.

The credit markets are undergoing significant volatility and capacity constraints. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit market. Our exposure to the current credit market crisis includes our Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement and counterparty performance risk.

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Current market conditions also elevate concern over counterparty risks related to our commodity derivative instruments. The Partnership has all of its commodity derivative instruments with one major financial institution. Should this financial counterparty not perform, we may not realize the benefit of some of our hedges under lower commodity prices. Although these derivative instruments as well as our Credit Facility and the Partnership Credit Facility expose us to credit risk, we monitor the creditworthiness of our counterparty, and we are not currently aware of any inability on the part of our counterparty to perform under our contracts. However, we are not able to predict sudden changes in the credit worthiness of our counterparty.

Since the formation of the Partnership in May 2007, cash distributions from the Partnership have been a significant source of liquidity for Abraxas Petroleum. During 2008, Abraxas Petroleum received $8.9 million in distributions. The declaration of the cash distribution to be made by the Partnership on or about May 15, 2009 attributable to the first quarter of 2009 is being deferred. In addition, under the amended terms of the Partnership Credit Facility, Abraxas Petroleum is required to repay the distribution for the fourth quarter of 2008 of approximately $1.9 million to the Partnership which must, in turn, make a principal payment under the Partnership Credit Facility of approximately $1.9 million. In consideration of making this payment, Abraxas Petroleum will be issued a number of additional units of the Partnership determined by dividing approximately $1.9 million by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by the Partnership times four. As a result of these amendments, Abraxas Petroleum will not be able to rely on distributions from the Partnership as a source of liquidity until such time as the indebtedness under the Subordinated Credit Agreement has been repaid.

Both Abraxas Petroleum and the Partnership could also seek capital through the sale of debt and equity securities, including the proposed initial public offering of the Partnership. The current state of the equity and debt markets will have a significant impact on our ability to sell debt or equity securities on terms as favorable as those which existed prior to the current crisis.

Contractual Obligations

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

· Long-term debt

· Interest on long-term debt

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, 2009:

Contractual Obligations (dollars in thousands)	Payments due in twelve month periods ending:
Contractual Obligations (dollars in thousands)	Total		March 31, 2010		March 31, 2011-2012		March 31, 2013-2014		Thereafter
Long-Term Debt (1)	$	173,935	$	40,147	$	128,901	$	343	$	4,544
Interest on long-term debt (2)		17,484		6,547		9,968		611		358
Total	$	191,419	$	46,694	$	138,869	$	954	$	4,902

(1)	These amounts represent the balances outstanding under the Credit Facility, the Partnership Credit Facility the Subordinated Credit Agreement and the Real estate term loan. These repayments assume that we will not draw down additional funds.

(2)	Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At March 31, 2009, our reserve for these obligations totaled $10.1 million for which no contractual commitment exists.

Off-Balance Sheet Arrangements. At March 31, 2009, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have or are reasonably likely to have a current or future effect on our financial

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condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At March 31, 2009, we were not engaged in any legal proceedings that were expected, individually or in the aggregate, to have a material adverse effect on the Company.

Other obligations. We make and will continue to make substantial capital expenditures for the acquisition, development, exploration and production of oil and 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.

Long-Term Indebtedness

Long-term debt consisted of the following:


	March 31, 2009			December 31, 2008
Partnership credit facility	$	125,600		$	125,600
Partnership subordinated credit agreement		40,000			40,000
Senior secured credit facility		3,000			—
Real estate lien note		5,335			5,369
		173,935			170,969
Less current maturities		(40,147	)		(40,134	)
	$	133,788		$	130,835

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Under the Credit Facility, Abraxas is subject to customary covenants, including certain financial covenants and reporting requirements. The Credit Facility requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. Current ratio is the ratio of consolidated current assets to consolidated current liabilities. For purposes of this calculation, current assets include, as of the date of the calculation, the portion of the borrowing base which is undrawn but exclude, as of the date of calculation, any cash deposited with or at the request of a counterparty to any derivative contract, any assets representing a valuation account arising from the application of SFAS 133 (which relates to derivative instruments and hedging activities) and SFAS 143 (which relates to asset retirement obligations) and any distributions payable by the Partnership to the GP unless such distributions have been received by the GP in cash, and current liabilities exclude, as of the date of calculation, the current portion of long-term debt, any liabilities representing a valuation account arising from the application of SFAS 133 and SFAS 143 and any liabilities of the GP arising solely in its capacity as a general partner of the Partnership. The interest coverage ratio is the ratio of consolidated EBITDA for the four quarters then ended to consolidated interest for the four quarters then ended. For the purpose of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of SFAS 123R (which relates to stock-based compensation), SFAS 133 and SFAS 143 less all non-cash items of income which were included in determining consolidated net income, including non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letters of credit fees and other fees and expenses incurred in connection with any debt. For purposes of calculating both ratios, any amounts attributable to the Partnership are not included. At March 31, 2009, our current ratio was 0.92 to 1.00 and our interest coverage ratio was 29.68 to 1.00.

In addition to the foregoing and other customary covenants, the Credit Facility contains a number of covenants that, among other things, will restrict Abraxas’ ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates other than on an “arms-length” basis;

· make any change in the principal nature of its business; and

· permit a change of control.

The Company was in compliance with all covenants as of March 31, 2009 or has obtained a waiver for noncompliance.

Amended and Restated Partnership Credit Facility. On May 25, 2007, the Partnership entered into a senior secured revolving credit facility which was amended and restated on January 31, 2008 and further amended on January 16, 2009, April 30, 2009 and May 7, 2009, which we refer to as the Partnership Credit Facility. The Partnership Credit Facility has a maximum commitment of $300.0 million. Availability under the Partnership Credit Facility is subject to a borrowing base. The borrowing base under the Partnership Credit Facility, which at May 7, 2009 was $130.0 million, is determined semi-annually by the lenders based upon the Partnership’s reserve reports, one of which must be prepared by the Partnership’s independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Partnership’s proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of the Partnership’s then current borrowing base. The Partnership’s borrowing base at May 7, 2009 of $130.0 million was determined based upon its reserves at December 31, 2008. The borrowing base can never exceed the $300.0 million maximum commitment amount. At March 31, 2009 and May 7, 2009, the Partnership had a total of $125.6 million outstanding under the Partnership Credit Facility. Under the amended terms of the Partnership Credit Facility, on May 14, 2009, Abraxas Petroleum is required to re-pay the distribution of

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approximately $1.9 million paid to it relating to the fourth quarter of 2008 to the Partnership and the Partnership must, in turn, make a principal payment of approximately $1.9 million under the Partnership Credit Facility. Abraxas Petroleum intends to make this payment on or before May 14, 2009. Once this payment has been made, the borrowing base under the Partnership Credit Facility will be reduced to approximately $128.1 million and the Partnership Credit Facility will have a balance of approximately $123.7 million and availability of $4.4 million. In consideration of making this payment, Abraxas Petroleum will be issued a number of additional units of the Partnership determined by dividing $1.9 million by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by the Partnership times four.

Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR rate plus, in each case 1.5% - 2.5%, depending on the utilization of the borrowing base, or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate plus in each case, 2.5% - 3.5% depending on the utilization of the borrowing base. At May 7, 2009 the interest rate on the Partnership Credit Facility was 5.5%. Subject to earlier termination rights and events of default, the Partnership Credit Facility’s stated maturity date is January 31, 2012. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Partnership Credit Facility, and under certain circumstances, may be required, from time to time, to permanently reduce the lenders’ aggregate commitment under the Partnership Credit Facility.

The Partnership, the GP, which is a wholly-owned subsidiary of Abraxas, and Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we refer to as the Operating Company, have guaranteed the Partnership’s obligations under the Partnership Credit Facility on a senior secured basis. Obligations under the Partnership Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the property and assets of the GP, the Partnership and the Operating Company, other than the GP’s general partner units in the Partnership.

Under the Partnership Credit Facility, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter of not less than 2.50 to 1.00. Current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For purposes of this calculation, current assets include, as of the date of the calculation, the portion of the borrowing base which is undrawn but exclude, as of the date of calculation, any cash deposited with or at the request of a counterparty to any derivative contract, and any assets representing a valuation account arising from the application of SFAS 133 and SFAS 143 and current liabilities exclude, as of the date of calculation, the current portion of long-term debt and any liabilities representing a valuation account arising from the application of SFAS 133 and SFAS 143. The interest coverage ratio is the ratio of consolidated EBITDA for the four quarters then ended to consolidated interest for the four quarters then ended. For the purpose of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of SFAS 123R, SFAS 133 and SFAS 143 less all non-cash items of income which were included in determining consolidated net income, including non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letters of credit fees and other fees and expenses incurred in connection with any debt. At March 31, 2009, the Partnership’s current ratio was 27.47 to 1.00 and its interest coverage ratio was 4.58 to 1.00.

The Partnership Credit Facility required the Partnership to enter into derivative contracts for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011. The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011. The second amendment to the Partnership Credit Facility required additional derivative contracts for volumes equating to approximately 60% of the estimated oil and gas production from net proved developed producing reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012.

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Under the terms of the Partnership Credit Facility, the Partnership may make cash distributions if, after giving effect to such distributions, the Partnership is not in default under the Partnership Credit Facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under the Partnership Credit Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing base (which at May 7, 2009 was $130.0 million) or the total commitment amount of the Partnership Credit Facility (which at May 7, 2009 was $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under the Partnership Credit Facility after giving effect to such distribution exceeds $20.0 million, or (ii) the Subordinated Credit Agreement shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while the Subordinated Credit Agreement is outstanding. The declaration amount of the cash distribution to be made by the Partnership on or about May 15, 2009 attributable to the first quarter of 2009 is being deferred. While the Subordinated Credit Agreement is outstanding, the Partnership’s capital expenditures are limited to $12.5 million per year.

In addition to the foregoing and other customary covenants, the Partnership Credit Facility contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

· make any change in the principal nature of its business; and

· permit a change of control.

The Partnership Credit Facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness including the Subordinated Credit Agreement described below, bankruptcy and material judgments and liabilities. In addition, an event of default would occur if the Partnership fails to receive a letter of credit, which we refer to as the APC L/C, in its favor from Abraxas Petroleum equal to the May 14, 2009 Payment Amount of approximately $1.9 million, the Partnership fails to draw on the APC L/C on or before May 14, 2009 or the Partnership fails to use the proceeds of the APC L/C to make the principal payment due on May 14, 2009. This event of default would not occur in the event that the Partnership repays the principal amount due on May 14, 2009 with funds received from Abraxas Petroleum. Abraxas Petroleum intends to make this payment to the Partnership on or before May 14, 2009. The Partnership and Abraxas Petroleum have agreed that upon the occurrence of such a payment or the Partnership’s drawing on the APC L/C that, in consideration thereof, the Partnership would issue a number of additional units to Abraxas Petroleum determined by dividing the approximately $1.9 million by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by the Partnership times four. Abraxas Petroleum intends to make this payment on or before May 14, 2009. Finally, if the indebtedness under the Subordinated Credit Agreement has not been repaid on or before July 1, 2009, the Partnership must pay the lenders a consent fee of $2.4 million.

The Partnership was in compliance with all covenants as of March 31, 2009.

Subordinated Credit Agreement

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(a) 2.0% and (b) the London Interbank Offered Rate plus, in each case, 13.0%. For any interest payment due on or after July 2, 2009, 3% per annum of the accrued interest payable shall be capitalized and added to the principal amount of the loan. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and under certain circumstances, may be required, from time to time, to make prepayments under the Subordinated Credit Agreement.

The Subordinated Credit Agreement required the Partnership to enter into derivative contracts for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011. The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011. The second amendment to the Partnership Credit Facility required additional derivative contracts for volumes equating to approximately 60% of the estimated oil and gas production from net proved developed producing reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012.

In addition to the foregoing and other customary covenants, the Subordinated Credit Agreement contains a number of covenants that, among other things, will restrict the Partnership’s ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

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· engage in transactions with affiliates;

· make any change in the principal nature of its business; and

· permit a change of control.

The Partnership is in compliance with all covenants as of March 31, 2009.

Real Estate Lien Note

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 terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into hedging arrangements for specified volumes, which equates to approximately 85% of the estimated oil and gas production through December 31, 2011 and approximately 60% of the estimated oil and gas production for calendar year 2012 from its net proved developed producing reserves.

Net Operating Loss Carryforwards.

At December 31, 2008, we had, subject to the limitation discussed below, $194.4 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2028 if not 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 $60.8 million for deferred tax assets at December 31, 2008.

We account for uncertain tax positions under provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 did not have any effect on the Company’s financial position or results of operations as of January 1, 2007 or for the quarters ended March 31, 2008 and 2009. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2009, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2008 remain open to examination by the tax jurisdictions to which the Company is subject.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

As an independent oil and 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 oil and gas. Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices

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may reduce the amount of oil and 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 oil and 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 quarter ended March 31, 2009, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $1.0 million for the quarter, however, due to the derivative contracts that the Partnership has in place, it is unlikely that a 10% decline in commodity prices from their current levels would significantly impact our operating revenue, cash flow and net income.

Derivative Instrument Sensitivity

The Partnership accounts for its derivative instruments in accordance with 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. In 2003 we elected not to designate derivative instruments as hedges. Accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded as gain (loss) on derivative contracts in the current period.

Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011, from its net estimated proved developed producing reserves. In connection with the April 30, 2009 amendment to the Partnership Credit Facility, the Partnership was required to enter into additional derivative contracts for volumes equating to approximately 60% of the estimated oil and gas production from net proved developed producing reserves for the year 2012. As a result, the Partnership entered into NYMEX-based fixed price swaps on 670 barrels of oil per day at $67.60 and 3,000 MMBbtu of gas per day at $6.88 for 2012. The Partnership intends to enter into derivative contracts in the future to reduce the impact of price volatility on its cash flow. By removing a significant portion of price volatility on its future oil and gas production, the Partnership believes it will mitigate, but not eliminate, the potential effects of changing commodity prices on its cash flow from operations for those periods. Because the prices at which we have hedged our oil and gas production are significantly higher than current commodity prices, we will realize increased cash flow on the portion of our production that we have hedged as a result of these high contract prices and we will sustain realized and unrealized gains on our derivative contracts. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

The following table sets forth the Partnership’s derivative contract position at March 31, 2009:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2009	Gas	10,595 Mmbtu	$8.44
Year 2009	Oil	1,000 Bbl	$83.80
Year 2010	Gas	9,130 Mmbtu	$8.22
Year 2010	Oil	895 Bbl	$83.26
Year 2011	Gas	8,010 Mmbtu	$8.10
Year 2011	Oil	810 Bbl	$86.45

At March 31, 2009, the aggregate fair market value of our commodity derivative contracts was approximately $46.1 million.

For the three months ended March 31, 2009 we recognized a realized gain of $7.0 million and an unrealized gain of $6.3 million. We expect to continue to sustain realized and unrealized gains on our derivative contracts if market prices continue to be less than our contract prices.

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Interest rate risk

The Partnership is subject to interest rate risk associated with borrowings under the Partnership Credit Facility and the Subordinated Credit Agreement. At March 31, 2009, the Partnership had $125.6 million in outstanding indebtedness under the Partnership Credit Facility. Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR rate plus, in each case, 1.5% - 2.5%, depending on the utilization of the borrowing base, or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate plus, in each case 2.5% - 3.5% depending on the utilization of the borrowing base. At May 7, 2009, the interest rate on the facility was 5.5%. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.3 million on an annual basis. In addition the Partnership had $40.0 million in outstanding indebtedness under the Subordinated Credit Agreement. Outstanding amounts under the Subordinated Credit Agreement bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR Offered Rate, plus in each case (b) 9.0% or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate, in each case, plus 10.0%. At May 7, 2009 the interest rate on the facility was 12.0%. For every percentage point that the rate rises, our interest expense would increase by approximately $400,000 on an annual basis. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The arrangement expires on August 12, 2010. The interest rate swap was amended in February 2009 lowering the Partnership’s fixed rate from 3.367% to 2.95%.

Item 4. Controls and Procedures.

As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas’ “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that the disclosure controls and procedures were effective.

There were no changes in our internal controls over financial reporting during the three month period ended March 31, 2009 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

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ABRAXAS PETROLEUM CORPORATION

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

There have been no changes in legal proceedings from that described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, and in Note 6 in the Notes to Condensed Consolidated Financial Statements contained in Part I of this report on Form 10-Q.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing Abraxas. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None

Item 3. Defaults Upon Senior Securities.

None

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

None

Item 5. Other Information.

None

Item 6. Exhibits

(a) Exhibits

Exhibit 10.1

Amendment No. 3 to Amended and Restated Credit Agreement dated May 7, 2009, by and among Abraxas Energy Partners, L.P., Société Générale, as administrative agent and issuing lender, The Royal Bank of Canada, as syndication agent, The Royal Bank of Scotland PLC, as documentation agent, and the lenders signatory thereto.

Exhibit 10.2

Amendment No. 3 to Subordinated Credit Agreement dated May 7, 2009 by and among Abraxas Energy Partners, L.P., Société Générale, as administrative agent, The Royal Bank of Canada, as syndication agent, and the lenders signatory thereto.

Exhibit 31.1

Certification - Robert L.G. Watson, CEO

Exhibit 31.2

Certification – Chris E. Williford, CFO

Exhibit 32.1

Certification pursuant to 18 U.S.C. Section 1350 – Robert L.G. Watson, CEO

Exhibit 32.2

Certification pursuant to 18 U.S.C. Section 1350 – Chris E. Williford, CFO

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ABRAXAS PETROLEUM CORPORATION

SIGNATURES

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

Date: May 14, 2009		By: /s/Robert L.G. Watson
		ROBERT L.G. WATSON,
		President and Chief
		Executive Officer

Date: May 14, 2009		By: /s/Chris E, Williford
		CHRIS E. WILLIFORD,
		Executive Vice President and
		Principal Accounting Officer

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Abraxas Petroleum (AXAS) 10-Q2009 Q2 Quarterly report

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