Edgar Filing: ABRAXAS PETROLEUM CORP

axas10q0630090.htm

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 JUNE 30, 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 August 7, 2009 was:

Class	Shares Outstanding
Common Stock, $.01 Par Value	49,834,894

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

FORM 10 – Q

INDEX

PART I
FINANCIAL INFORMATION

ITEM 1 -	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets - June 30, 2009 (unaudited) and December 31, 2008	4
	Condensed Consolidated Statements of Operations – (unaudited) Three and Six Months Ended June 30, 2009 and 2008	6
	Condensed Consolidated Statements of Cash Flows – (unaudited) Six Months Ended June 30, 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	34

ITEM 3 -	Quantitative and Qualitative Disclosures about Market Risk	57

ITEM 4 -	Controls and Procedures	58

PART II
OTHER INFORMATION
ITEM 1 -	Legal Proceedings	59
ITEM 1a -	Risk Factors	59
ITEM 2 -	Unregistered Sales of Equity Securities and Use of Proceeds	59
ITEM 3 -	Defaults Upon Senior Securities	59
ITEM 4 -	Submission of Matters to a Vote of Security Holders	59
ITEM 5 -	Other Information	59
ITEM 6 -	Exhibits	59
	Signatures	61

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)

	June 30,		December 31,
	2009		2008 (1)
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,790	$	1,924
Accounts receivable, net:
Joint owners		845		1,740
Oil and gas production		6,217		6,168
Other		325		58
		7,387		7,966

Derivative asset – current		18,092		22,832
Other current assets		432		572
Total current assets		27,701		33,294

Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved		448,093		440,712
Unproved properties excluded from depletion		—		—
Other property and equipment		11,116		10,986
Total		459,209		451,698
Less accumulated depreciation, depletion, and amortization		300,385		291,390
Total property and equipment – net		158,824		160,308

Deferred financing fees, net		4,099		1,443
Derivative asset – long-term		9,456		16,394
Other assets		483		400
Total assets	$	200,563	$	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 (unaudited)

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands, except share data)

	June 30,			December 31,
	2009			2008 (1)
	(Unaudited)
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	5,240		$	10,748
Oil and gas production payable		2,750			3,176
Accrued interest		273			350
Other accrued expenses		1,575			1,886
Derivative liability – current		2,697			3,000
Current maturities of long-term debt		46,062			40,134
Other current liabilities		19			—
Total current liabilities		58,616			59,294

Long-term debt, excluding current maturities		128,843			130,835

Derivative liability – long-term		3,202			—
Future site restoration		10,172			9,959
Total liabilities		200,833			200,088

Equity (Deficit)
Abraxas Petroleum stockholders’ equity (deficit):
Convertible preferred stock, par value $.01, authorized 1,000,000 shares; -0- issued and outstanding		—			—
Common Stock, par value $.01, authorized 200,000,000 shares; issued and outstanding 49,804,894 and 49,622,423		498			496
Additional paid-in capital		187,938			187,243
Accumulated deficit		(188,776	)		(183,194	)
Accumulated other comprehensive income		192			113
Total Abraxas Petroleum stockholders’ equity (deficit)		(148	)		4,658
Non-controlling interest equity (deficit)		(122	)		7,093
Total stockholders’ equity (deficit)		(270	)		11,751
Total liabilities and stockholders’ equity (deficit)	$	200,563		$	211,839

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

See accompanying notes to condensed consolidated financial statements (unaudited)

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008 (1)			2009			2008 (1)
Revenue:
Oil and gas production revenues	$	12,119		$	34,083		$	22,715		$	55,946
Rig revenues		247			329			500			635
Other		2			11			3			12
		12,368			34,423			23,218			56,593
Operating costs and expenses:
Lease operating and production taxes		5,985			7,170			11,854			12,372
Depreciation, depletion, and amortization		4,507			6,004			8,994			11,098
Rig operations		211			193			399			403
General and administrative (including stock based compensation of $329, $650, $596, and $896)		1,601			1,873			3,730			3,672
		12,304			15,240			24,977			27,545
Operating income (loss)		64			19,183			(1,759	)		29,048

Other (income) expense:
Interest income		(6	)		(31	)		(11	)		(127	)
Interest expense		3,051			2,672			5,607			5,138
Financing fees		—			—			362			—
Amortization of deferred financing fee		374			273			586			467
Loss on derivative contracts (unrealized $20,889, $74,517, $14,459 and $100,592)		14,560			81,135			1,695			108,093
Other		2,208			734			2,229			734
		20,187			84,783			10,468			114,305
Consolidated net loss		(20,123	)		(65,600	)		(12,227	)		(85,257	)
Less: Net loss attributable to non-controlling interest		10,091			7,912			6,645			18,578
Net loss attributable to Abraxas Petroleum	$	(10,032	)	$	(57,688	)	$	(5,582	)	$	(66,679	)

Net loss attributable to Abraxas Petroleum common stockholders -per common share – basic	$	(0.20	)	$	(1.18	)	$	(0.11	)	$	(1.36	)

Net loss attributable to Abraxas Petroleum common stockholders -per common share – diluted	$	(0.20	)	$	(1.18	)	$	(0.11	)	$	(1.36	)

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

See accompanying notes to condensed consolidated financial statements (unaudited)

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	Six Months Ended June 30,
	2009			2008 (1)
Operating Activities
Net loss	$	(12,227	)	$	(85,257	)
Adjustments to reconcile net loss to net
cash provided by operating activities:
Change in derivative fair value		14,577			100,038
Depreciation, depletion, and amortization		8,994			11,098
Amortization of deferred financing fees		586			467
Accretion of future site restoration		281			263
Stock-based compensation		596			896
Other non-cash expenses		123			42
Registration fees previously capitalized		2,207			—
Changes in operating assets and liabilities:
Accounts receivable		579			(14,068	)
Other		135			68
Accounts payable and accrued expenses		(6,395	)		16,940
Net cash provided by operating activities		9,456			30,487

Investing Activities
Capital expenditures, including purchases and development of properties		(7,510	)		(155,475	)
Net cash used in investing activities		(7,510	)		(155,475	)

Financing Activities
Proceeds from long-term borrowings		5,924			124,362
Payments on long-term borrowings		(1,988	)		—
Partnership distributions		(2,257	)		(4,029	)
Deferred financing fees		(3,242	)		(1,615	)
Exercise of stock options		49			44
Other		(566	)		—
Net cash provided by financing activities		(2,080	)		118,762

Decrease in cash		(134	)		(6,226	)
Cash, at beginning of period		1,924			18,936
Cash, at end of period	$	1,790		$	12,710

Supplemental disclosure of cash flow information:
Interest paid	$	5,402		$	3,975

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

See accompanying notes to condensed consolidated financial statements (unaudited)

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 and six months ended June 30, 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 51.8% non-controlling owners of the Partnership presented as non-controlling interest. Abraxas owns the remaining 48.2% of the partnership interests. The Company has determined that based on its control of the general partner of the Partnership, this 48.2% owned entity should be consolidated for financial reporting purposes.

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 June 30, 2009, the results of operations and the cash flows for each of the three and six month periods ended June 30, 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 and six month periods ended June 30, 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:

				Abraxas Petroleum Corporation Shareholders Equity (deficit)
	Comprehensive Income			Common Stock		Additional Paid-in Capital		Accumulated Deficit			Accumulated Other Comprehensive Income		Parent Equity (deficit)			Non- Controlling Interest
January 1, 2009	$	—		$	496	$	187,243	$	(183,194	)	$	113	$	4,658		$	7,093
Comprehensive income:
Net loss		(12,227	)		—		—		(5,582	)		—		(5,582	)		(6,645	)
Unrealized gain on securities		79			—		—		—			79		79			—
Equity based compensation		—			—		526		—			—		526			46
Partnership distributions		—			—		—		—			—		—			(2,257	)
Registration fees		—			—		—		—			—		—			1,385
Shares issued for compensation		—			—		36		—			—		36			—
Options exercised		—			1		48		—			—		49			—
Other		—			1		85		—			—		86			256
June 30, 2009	$	(12,148	)	$	498	$	187,938	$	(188,776	)	$	192	$	(148	)	$	(122	)

In accordance with generally accepted accounting principles in effect prior to the adoption of SFAS 160, 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 controlling interest. Future earnings were recognized by the non-controlling interest and were credited to the controlling 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 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 interest.

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.

Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and short-term debt approximate fair value due to the short-term nature of these instruments.

The fair value of the Company’s long-term debt is estimated based on the discounted value of the future cash flows expected to be paid on the loans. The discount rate used to estimate the fair value of the loans is the rate currently available to the Company for loans with similar terms and maturities. The fair value at June 30, 2009 approximated the carrying value, however, as of June 30, 2009 the Company does not believe it is practicable to estimate the fair value of its outstanding debt in light of the impending maturity on August 14, 2009 that the Company is currently seeking to address..

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 and six months ended June 30, 2009, the Company recognized $270,000 and $450,000, respectively, related to stock options.

The following table summarizes the stock option activities for the six months ended June 30, 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	965		$	0.99	$	0.70		678
Exercised	(50	)	$	0.97	$	0.87		(44	)
Expired or canceled	(73	)	$	4.10	$	2.48		(181	)
Outstanding, June 30, 2009	3,232		$	2.27	$	1.33	$	4,283

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		81.61	%
Risk free interest rate		2.35	%
Expected life		6.06
Fair value of options granted (in thousands)	$	678
Weighted average grant date fair value of options granted	$	0.70

Additional information related to options at June 30, 2009 and December 31, 2008 is as follows:

	June 30,	December 31,
	2009	2008
Options exercisable (in thousands)	1,952	1,963

As of June 30, 2009, there was approximately $1.1 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 six months ended June 30, 2009 is presented in the following table:

	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 June 30, 2009		162,943		$	3.26

For the three and six months ended June 30, 2009, the Company incurred $36,000 and $75,000 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 unit 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 six months ended June 30, 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 June 30, 2009	51,900		$	7.23

For the three and six months ended June 30, 2009, the Partnership incurred $23,000 and $46,000 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 three and six months ended June 30, 2009, the Partnership incurred $0 and $25,000 in equity based compensation expense relating to phantom units.

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 June 30, 2009, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves.

Working Capital (Deficit)

At June 30, 2009 our current liabilities of approximately $58.6 million exceeded our current assets of $27.7 million resulting in a working capital deficit of $30.9 million. This compares to a working capital deficit of approximately $26.0 million at December 31, 2008. Current liabilities at June 30, 2009 primarily consisted of the current portion of long-term debt consisting of $40.0 million outstanding under the Subordinated Credit Agreement and $5.9 million outstanding under the Credit Facility, the current portion of derivative liabilities of $2.7 million, trade payables of $5.2 million, revenues due third parties of $2.8 million, and other accrued liabilities of $1.6 million. The Abraxas Senior Secured Credit Facility which is due on September 30, 2010 is classified as current maturities at June 30, 2009 as a result of continued non-compliance with the current ratio covenant as defined in the facility. The Subordinated Credit Agreement currently matures on August 14, 2009. The Partnership has entered into discussions with the lenders under the Partnership Credit Facility and the Subordinated Credit Agreement to extend the maturity date and certain other items to September 14, 2009. The Partnership had intended to repay the Subordinated Credit Agreement with proceeds from its initial public offering. Under the terms of the Voting Agreement (defined below), the Partnership agreed to not file any further amendments to the registration statement for its initial public offering or take any actions intended to consummate the initial public offering and, as a result of executing the Merger Agreement (defined below), we and the Partnership are no longer pursuing the refinancing of the Partnership’s Subordinated Credit Agreement other than in connection with the new credit facility which is subject to the completion of the Merger (defined below). In connection with a Merger, we have received a non-binding term sheet for a new senior secured revolving credit facility of up to $300.0 million, of which $155.0 million is expected to be available to us at closing. If the Merger is not consummated, the Partnership would be in default under its Subordinated Credit Agreement and under the Partnership Credit Facility. We cannot assure you that either the Merger or the new credit facility will be consummated. If an event of default were to occur under the Subordinated Credit Agreement or the Partnership Credit Facility, 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 June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”), which establishes the FASB Accounting Standards CodificationTM as the source of GAAP to be applied to nongovernmental agencies. SFAS 168 explicitly recognizes rules and interpretive releases of the SEC under authority of federal securities laws as authoritative GAAP for SEC registrants. SFAS 168 will become effective for interim or annual periods ending after September 15, 2009. SFAS 168 will not have a material impact on our financial statements.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”), which sets forth general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 was adopted effective for the second quarter of 2009 and did not have a material impact on our financial statements. The Company has evaluated subsequent events through the time of filing these financial statements with the SEC on August 10, 2009.

In April 2009, the FASB issued FASB Staff Position No. SFAS 107-1 and APB No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”), which requires quarterly disclosure of information about the fair value of financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments.” FSP FAS 107-1 and APB 28-1 was adopted effective for the second quarter of 2009 and did not have an impact on our financial statements.

In April 2009, the FASB issued FASB Staff Position No. FAS 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2 and 124-2”). FSP FAS 115-2 and 124-2 amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. FSP FAS 115-2 and 124-2 does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and 124-2 does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, FSP FAS 115-2 and 124-2 requires comparative disclosures only for periods ending after initial adoption. FSP FAS 115-2 and 124-2 was adopted effective for the second quarter of 2009 and did not have an impact on our financial statements.

In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K. The new requirements provide for consideration of new technologies in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations. The final rules are effective for fiscal years ending on or after December 31, 2009.

Note 2. Recent Events

Merger Agreement

On July 17, 2009, Abraxas Petroleum and Abraxas Energy Partners and, from and after its accession to the agreement, the Delaware limited liability company formed as a wholly-owned subsidiary of Abraxas (“Merger Sub”), entered into an Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which Abraxas Energy Partners will, subject to the terms and conditions of the Merger Agreement, merge with and into Merger Sub, with Merger Sub surviving and continuing as a wholly-owned subsidiary of Abraxas Petroleum (the “Merger”).

As of July 17, 2009, Abraxas Petroleum and its subsidiaries beneficially owned, within the meaning of Rule 13d-3 of the U.S. Securities and Exchange Act of 1934, as amended, 5,350,598 common units of Abraxas Energy Partners, representing approximately 46.7% of the outstanding Abraxas Energy Partners common units (the “Abraxas Energy Partners Common Units”).

Subject to the terms and conditions of the Merger Agreement, if and when the Merger is completed, each outstanding Abraxas Energy Partners Common Unit, other than treasury units and Abraxas Energy Partners Common Units owned by Abraxas Petroleum and its subsidiaries, will be canceled and converted into the right to receive the number of shares of Abraxas Petroleum common stock determined by dividing (i) $6.00 by (ii) the average volume weighted average price for the Abraxas Petroleum common stock as reported on NASDAQ for the twenty consecutive trading days ending on the third business day preceding the date of the meeting of the Abraxas Petroleum stockholders held to approve the Merger (the “Exchange Ratio”); provided, however, that in no event shall the Exchange Ratio be less than 4.25 or greater than 6.

In addition, as of the consummation of the Merger, each outstanding restricted unit and phantom unit of Abraxas Energy Partners will be converted into an equivalent number of shares of restricted stock of Abraxas Petroleum and each unit option of Abraxas Energy Partners which was to be issued upon the completion of the initial public offering of Abraxas Energy Partners will become a stock option of Abraxas Petroleum, with adjustments in the number of shares and exercise price to reflect the Exchange Ratio, but otherwise on substantially the same terms and conditions as were applicable prior to the Merger. The exercise price of the Abraxas Petroleum stock options will be the closing price of the Abraxas Petroleum common stock on the date the Merger closes.

The Merger Agreement contains (a) customary representations and warranties of Abraxas Petroleum Abraxas Energy Partners and Merger Sub; (b) covenants of Abraxas Petroleum and Abraxas Energy Partners to conduct their respective businesses in the ordinary course until the Merger is completed; and (c) covenants of Abraxas Petroleum and Abraxas Energy Partners not to take certain actions during such period, including prohibitions on the declaration or payment of dividends and distributions.

by the affirmative vote of the holders of a majority of the Abraxas Petroleum common stock voting at a stockholders’ meeting, (2) the approval of an amendment to the Abraxas Petroleum 2005 Long-Term Equity Incentive Plan to increase the number of authorized shares for issuance under the plan (the “LTIP Amendment”) by the affirmative vote of the holders of a majority of the outstanding Abraxas Petroleum common stock voting at a stockholders’ meeting, (3) the receipt by Abraxas Petroleum of financing that is sufficient to consummate the Merger and repay all indebtedness outstanding under Abraxas Energy Partner’s credit agreement and subordinated credit agreement, and, (4) certain other customary closing conditions.

The board of directors of Abraxas Petroleum and a special committee comprised entirely of independent Abraxas Petroleum directors have approved the Merger Agreement. The board of directors adopted a resolution recommending adoption of the LTIP Amendment and approval of the Stock Issuance by the Abraxas Petroleum stockholders.

The foregoing description of the Merger and the Merger Agreement does not purport to be complete and is qualified in its entirety by reference to the Merger Agreement which was filed with the SEC on July 21, 2009.

The above description of the Merger Agreement has been included to provide investors and security holders with information regarding its terms. It is not intended to provide any other factual information about the parties or their respective subsidiaries and affiliates. The Merger Agreement contains representations and warranties made by and to the parties thereto as of specific dates. The statements embodied in those representations and warranties were made for purposes of that contract between the parties and are subject to qualifications and limitations agreed to by the parties in connection with negotiating the terms of that contract. In addition, certain representations and warranties were made as of a specified date, may be subject to a contractual standard of materiality different from those generally applicable to investors, or may have been used for the purpose of allocating risk between the parties rather than establishing matters as facts.

Voting Agreement

In order to induce Abraxas Petroleum and Abraxas Energy Partners to enter into the Merger Agreement, certain limited partners of Abraxas Energy Partners entered into a Voting, Registration Rights and Lock-Up Agreement (the “Voting Agreement”) with Abraxas Petroleum and Abraxas Energy Partners.

The Voting Agreement provides, among other things, that all of the limited partners that are party to the Voting Agreement will:

•

vote all of their outstanding common units of Abraxas Energy Partners in favor of the Merger;

•

vote against any other merger agreement, consolidation, combination, sale of substantial assets or similar transaction;

•

grant an irrevocable proxy to Abraxas Petroleum to vote all of their common units of Abraxas Energy Partners in favor of the Merger Agreement and against any other transaction;

•

agree to not, directly or indirectly, transfer any of such limited partners common units of Abraxas Energy Partners to any person (other than an affiliate of such limited partner who agrees to be bound by the terms of this agreement) other than pursuant to the Merger;

•

not directly, or indirectly permit any person on behalf of such limited partner, to effect any transactions in the securities of Abraxas Petroleum;

•

not transfer any of the shares of Abraxas Petroleum common stock received by such limited partner in the Merger (the “Merger Shares”) for 90 days after the effective time of the Merger (the “Effective Time”) followed by a staggered lock-up period for the shares of Abraxas Petroleum common stock issued in the Merger; and

•

not exercise any of its rights or take any action under the Exchange and Registration Rights Agreement, dated as of May 25, 2007, as amended, by and among Abraxas Petroleum, Abraxas Energy Partners and the limited partners signatories thereto.

The Voting Agreement provides, among other things, that Abraxas Petroleum and Abraxas Energy Partners will

•

not file any further amendments to the registration statement on Form S-1 (No. 333-144537) relating to the initial public offering of the common units of Abraxas Energy Partners; and

•

at the Effective Time increase the size of the Board of Directors of Abraxas Petroleum by two members and elect Ed Russell and Brian Melton to serve on the Board of Directors.

In addition, under the Voting Agreement, Abraxas Petroleum agreed to file with the SEC a registration statement on Form S-3 or such other successor form, no later than 120 days following the Effective Time to enable the resale of the Merger Shares by the limited partners party to the Voting Agreement and shall use its commercially reasonable efforts to cause the Registration Statement to become effective. Abraxas Petroleum also granted such limited partners the right to demand that Abraxas Petroleum conduct an underwritten offering and to participate in certain Abraxas offerings.

The foregoing description of the Voting Agreement does not purport to be complete and is qualified in its entirety by reference to the Voting Agreement and Amendment No. 1 to the Voting Agreement which were filed with the SEC on July 21, 2009, respectively.

The above description of the Voting Agreement has been included to provide investors and security holders with information regarding its terms. It is not intended to provide any other factual information about the parties or their respective subsidiaries and affiliates. The Voting Agreement contains representations and warranties made by and to the parties thereto as of specific dates. The statements embodied in those representations and warranties were made for purposes of that contract between the parties and are subject to qualifications and limitations agreed to by the parties in connection with negotiating the terms of that contract. In addition, certain representations and warranties were made as of a specified date, may be subject to a contractual standard of materiality different from those generally applicable to investors, or may have been used for the purpose of allocating risk between the parties rather than establishing matters as facts.

Amendments to the Credit Agreements

On June 30, 2009, Abraxas Energy Partners entered into Amendment No. 4 to the Partnership Credit Facility, dated as of January 31, 2008, by and among Abraxas Energy Partners, the lenders party thereto and Société Générale, as Administrative Agent, and Amendment No. 4 to the Subordinated Credit Agreement dated as of January 31, 2008, by and among Abraxas Energy Partners, the lenders party thereto and Société Générale, as Administrative Agent. Pursuant to these amendments, among other things, the maturity date of the Subordinated Credit Agreement was extended to August 14, 2009.

On July 22, 2009, Abraxas Energy Partners entered into Amendment No. 5 to the Partnership Credit Facility, dated as of January 31, 2008, by and among Abraxas Energy Partners, the lenders party thereto and Société Générale, as Administrative Agent, and Amendment No. 5 to the Subordinated Credit Agreement dated as of January 31, 2008, by and among Abraxas Energy Partners, the lenders party thereto and Société Générale, as Administrative Agent. Pursuant to these amendments, among other things, the lenders permitted the monetization of the Partnership’s existing commodity swaps. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Facility on July 31, 2009. In connection with the monetization and repayment, the Partnership’s borrowing base was reduced to $95.0 million and the Partnership was required to enter into new commodity swaps. The following table sets forth the consolidated weighted average derivative contract position as of July 29, 2009 for Abraxas Petroleum and the Partnership:

	Fixed-Price Swaps
	Oil		Gas
Contract Period	Daily Volume (Bbl)	Swap Price	Daily Volume (Mmbtu)	Swap Price
Q4 2009	1,355	$68.90	13,981	$4.50
2010	1,158	73.28	11,258	5.73
2011	1,035	76.61	9,580	6.52
2012	946	70.89	8,303	6.77
2013	705	80.79	5,962	6.84

Note 3. 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 5 “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.

Unaudited Pro Forma Financial Information
	Six months ended June 30, 2008
Revenue	$	59,591
Net Income	$	(64,557	)
Earnings per share - basic	$	(1.32	)

Note 4. 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 and six month periods ended June 30, 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 six months ended June 30, 2008 and 2009. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 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 5. Long-Term Debt

Long-term debt consisted of the following:


	June 30, 2009			December 31, 2008
Partnership credit facility	$	123,675		$	125,600
Partnership subordinated credit agreement		40,000			40,000
Senior secured credit facility		5,924			—
Real estate lien note		5,306			5,369
		174,905			170,969
Less current maturities		(46,062	)		(40,134	)
	$	128,843		$	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, which was amended on February 4, 2009 and May 13, 2009. 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 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 June 30, 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% - 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 August 7, 2009, the interest rate on the Credit Facility was 2.8%. 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 June 30, 2009, our current ratio was 0.85 to 1.00 and our interest coverage ratio was 9.64 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 June 30, 2009 or has obtained a waiver for noncompliance. As a result of continued non-compliance with the current ratio covenant, the outstanding amount of this facility has been classified as current liability.

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, May 7, 2009, June 30, 2009 and July 22, 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 June 30, 2009, was $128.1 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 June 30, 2009 of $128.1 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 June 30, 2009 the Partnership had a total of $123.7 million outstanding under the Partnership Credit Facility. On July 31, 2009, the Partnership repaid $28.7 million of indebtedness after which, the Partnership had $95.0 million outstanding under the Partnership Credit Facility. Simultaneously, the borrowing base under the Partnership Credit Facility was reduced to $95.0 million.

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 August 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.

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 Abraxas Operating, 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 June 30, 2009, the Partnership’s current ratio was 23.74 to 1.00 and its interest coverage ratio was 3.85 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. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. In connection with the monetization and repayment, the Partnership was required to enter into new commodity swaps on approximately 85% of its estimated oil and gas production from its net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013.

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 July 31, 2009 was $95.0 million) or the total commitment amount of the Partnership Credit Facility (which at July 31, 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 was deferred. Furthermore, in accordance with the terms of the Merger Agreement, the Partnership is precluded from declaring or paying any future cash distributions. 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. If the indebtedness under the Subordinated Credit Agreement was not repaid on or before July 1, 2009, the Partnership was required to pay the lenders a consent fee of $2.4 million. This fee was paid by the Partnership on June 30, 2009 and capitalized as deferred financing fees.

The Partnership was in compliance with all covenants as of June 30, 2009.

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, May 7, 2009, June 30, 2009 and July 22, 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) 12.0% or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate, in each case, plus 13.00%. At August 7, 2009, the interest rate on the Subordinated Credit Agreement was 15.0%. 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.

Each of the GP and Abraxas Operating 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 Abraxas Operating, 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 June 30, 2009, the Partnerships current ratio was 23.74 to 1.00 and its interest coverage ratio was 3.85 to 1.00.

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. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. In connection with the monetization and repayment, the Partnership was required to enter into new commodity swaps on approximately 85% of its estimated oil and gas production from its net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013.

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 August 14, 2009. In addition, if the indebtedness under the Subordinated Credit Agreement has not been repaid on or before August 14, 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. The Subordinated Credit Agreement currently matures on August 14, 2009. The Partnership has entered into discussions with the lenders under the Partnership Credit Facility and the Subordinated Credit Agreement to extend the maturity date and the requirement for proceeds from an equity issuance and the warrant issuance to September 14, 2009. The Partnership had intended to repay the Subordinated Credit Agreement with proceeds from its initial public offering. Under the terms of the Voting Agreement, the Partnership agreed to not file any further amendments to the registration statement for its initial public offering or take any actions intended to consummate the initial public offering and, as a result of executing the Merger Agreement, we and the Partnership are no longer pursuing the refinancing of the Partnership’s Subordinated Credit Agreement other than in connection with the new credit facility which is subject to the completion of the Merger. In connection with the Merger, we have received a non-binding term sheet for a new senior secured revolving credit facility of up to $300.0 million, of which $155.0 million is expected to be available to us at closing. If the Merger is not consummated, the Partnership would be in default under its Subordinated Credit Agreement and under the Partnership Credit Facility. We cannot assure you that the Merger or the new credit facility will be consummated. If an event of default were to occur under the Subordinated Credit Agreement or the Partnership Credit Facility, 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 Partnership was in compliance with all covenants as of June 30, 2009.

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 June 30, 2009, $5.3 million was outstanding on the note.

Note 6. 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 51.8% owners of the Partnership are presented as non-controlling interest. Abraxas owns the remaining 48.2% of the partnership interests. The Company has determined that based on its control of the general partner of the Partnership, this 48.2% owned entity should be consolidated for financial reporting purposes. The consolidating financial statements are presented as follows:

Condensed Consolidating Balance Sheet
June 30, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation		Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Assets:
Cash	$	276	$	1,514		$	—		$	1,790
Accounts receivable, less allowance for doubtful accounts		7,427		7,953			(7,993	)		7,387
Derivative asset – current		—		18,092			—			18,092
Other current assets		391		41			—			432
Total current assets		8,094		27,600			(7,993	)		27,701
Property and equipment – net		43,811		112,312			2,701			158,824
Deferred financing fees, net		53		4,046			—			4,099
Derivative asset – long-term		—		9,456			—			9,456
Investment in partnership		11,890		—			(11,890	)		—
Other assets		483		—			—			483
Total assets	$	64,331	$	153,414		$	(17,182	)	$	200,563
Liabilities and Stockholders’ equity (deficit):
Current liabilities:
Accounts payable	$	4,928	$	312		$	—		$	5,240
Oil and gas production payable		10,743		—			(7,993	)		2,750
Accrued interest		18		255			—			273
Other accrued expenses		1,575		—			—			1,575
Derivative liability – current		—		2,697			—			2,697
Current maturities of long-term debt		6,062		40,000			—			46,062
Dividend payable		—		19			—			19
Total current liabilities		23,326		43,283			(7,993	)		58,616
Long-term debt		5,168		123,675			—			128,843
Future site restoration		929		9,243			—			10,172
Derivative liability – long-term		—		3,202			—			3,202
Total liabilities		29,423		179,403			(7,993	)		200,833

Abraxas Petroleum equity (deficit)		34,908		(25,989	)		(9,067	)		(148	)
Non-controlling interest equity (deficit)		—		—			(122	)		(122	)
Total equity (deficit)		34,908		(25,989	)		(9,189	)		(270	)
Total liabilities and stockholders’ equity (deficit)	$	64,331	$	153,414		$	(17,182	)	$	200,563

Condensed Consolidating Balance Sheet
December 31, 2008 (1)
(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

(1)	As adjusted for FAS No. 160 “Non-controlling Interest in Consolidated Financial Statements.”

Condensed Consolidating Statement of Operations
For the three months ended June 30, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Revenues:
Oil and gas production revenues	$	2,428		$	9,691		$	—		$	12,119
Rig revenues		247			—			—			247
Other		2			—			—			2
		2,677			9,691			—			12,368
Operating costs and expenses:
Lease operating and production taxes		956			5,029			—			5,985
Depreciation, depletion, and amortization		935			3,502			70			4,507
Rig operations		211			—			—			211
General and administrative		933			668			—			1,601
		3,035			9,199			70			12,304
Operating income (loss)		(358	)		492			(70	)		64

Other (income) expense:
Interest income		(2	)		(4	)		—			(6	)
Amortization of deferred financing fees		39			335			—			374
Interest expense		167			2,884			—			3,051
Loss on derivative contracts		—			14,560			—			14,560
Other		—			2,208			—			2,208
		204			19,983			—			20,187
Net loss		(562	)		(19,491	)		(70	)		(20,123	)
Less: Net loss attributable to non-controlling interest		—			—			10,091			10,091
Net loss attributable to Abraxas Petroleum …………………………………………………	$	(562	)	$	(19,491	)	$	10,021		$	(10,032	)

Condensed Consolidating Statement of Operations
For the three months ended June 30, 2008 (1)
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations		Consolidated
Revenues:
Oil and gas production revenues	$	5,639		$	28,444		$	—	$	34,083
Rig revenues		329			—			—		329
Other		11			—			—		11
		5,979			28,444			—		34,423
Operating costs and expenses:
Lease operating and production taxes		840			6,330			—		7,170
Depreciation, depletion, and amortization		925			5,079			—		6,004
Rig operations		193			—			—		193
General and administrative		1,097			776			—		1,873
		3,055			12,185			—		15,240
Operating income		2,924			16,259			—		19,183

Other (income) expense:
Interest income		(28	)		(3	)		—		(31	)
Amortization of deferred financing fees		10			263			—		273
Interest expense		48			2,624			—		2,672
Loss on derivative contracts		—			81,135			—		81,135
Other		23			711					734
		53			84,730			—		84,783
Net income (loss)		2,871			(68,471	)		—		(65,600	)
Less: Net loss attributable to non-controlling interest……………….		—			—			7,912		7,912
Net income (loss) attributable to Abraxas Petroleum.	$	2,871		$	(68,471	)	$	7,912	$	(57,688	)

(1)	As adjusted for FAS No. 160 “Non-controlling Interest in Consolidated Financial Statements.”

Condensed Consolidating Statement of Operations
For the six months ended June 30, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Revenues:
Oil and gas production revenues	$	4,394		$	18,321		$	—		$	22,715
Rig revenues		500			—			—			500
Other		3			—			—			3
		4,897			18,321			—			23,218
Operating costs and expenses:
Lease operating and production taxes		2,021			9,833			—			11,854
Depreciation, depletion, and amortization		1,892			7,028			74			8,994
Impairment		—			2,775			(2,775	)		—
Rig operations		399			—			—			399
General and administrative		2,255			1,475			—			3,730
		6,567			21,111			(2,701	)		24,977
Operating income (loss)		(1,670	)		(2,790	)		2,701			(1,759	)

Other (income) expense:
Interest income		(5	)		(6	)		—			(11	)
Amortization of deferred financing fees		49			537			—			586
Interest expense		285			5,322			—			5,607
Financing fees		—			362			—			362
Loss on derivative contracts		—			1,695			—			1,695
Other		—			2,229			—			2,229
		329			10,139			—			10,468
Net loss		(1,999	)		(12,929	)		2,701			(12,227	)
Less: Net loss attributable to non-controlling interest		—			—			6,645			6,645
Net loss attributable to Abraxas Petroleum	$	(1,999	)	$	(12,929	)	$	9,346		$	(5,582	)

Condensed Consolidating Statement of Operations
For the six months ended June 30, 2008 (1)
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations		Consolidated
Revenues:
Oil and gas production revenues	$	8,686		$	47,260		$	—	$	55,946
Rig revenues		635			—			—		635
Other		12			—			—		12
		9,333			47,260			—		56,593
Operating costs and expenses:
Lease operating and production taxes		1,616			10,756			—		12,372
Depreciation, depletion, and amortization		1,515			9,583			—		11,098
Rig operations		403			—			—		403
General and administrative		2,382			1,290			—		3,672
		5,916			21,629			—		27,545
Operating income		3,417			25,631			—		29,048

Other (income) expense:
Interest income		(111	)		(16	)		—		(127	)
Amortization of deferred financing fees		20			447			—		467
Interest expense		70			5,068			—		5,138
Loss on derivative contracts		—			108,093			—		108,093
Other		23			711			—		734
		2			114,303			—		114,305
Net income (loss)		3,415			(88,672	)		—		(85,257	)
Less: Net loss attributable to non-controlling interest		—			—			18,578		18,578
Net income (loss) attributable to Abraxas Petroleum .	$	3,415		$	(88,672	)	$	18,578	$	(66,679	)

(1)	As adjusted for FAS No. 160 “Non-controlling Interest in Consolidated Financial Statements.”

Condensed Consolidating Statement of Cash Flows
For the six months ended June 30, 2009
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Operating Activities
Net income (loss)	$	(1,999	)	$	(12,929	)	$	2,701		$	(12,227	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Change in derivative fair value		—			14,577			—			14,577
Depreciation, depletion, and amortization		1,892			7,028			74			8,994
Proved property impairment		—			2,775			(2,775	)		—
Accretion of future site restoration		26			255			—			281
Amortization of deferred financing fees		49			537			—			586
Stock-based compensation		526			70			—			596
Other non-cash transactions		123			—			—			123
Previously capitalized registration fees		—			2,207			—			2,207
Changes in operating assets and liabilities:
Accounts receivable		4,087			(258	)		(3,250	)		579
Other assets		139			(4	)		—			135
Accounts payable and accrued expenses		(6,063	)		(3,582	)		3,250			(6,395	)
Net cash provided by (used in) operations		(1,220	)		10,676			—			9,456

Investing Activities
Capital expenditures, including purchases and development of properties – net of dispositions		(4,412	)		(3,098	)		—			(7,510	)
Net cash used in investing activities		(4,412	)		(3,098	)		—			(7,510	)

Financing Activities
Proceeds from issuance of common stock
Proceeds from long-term borrowings		5,924			—			—			5,924
Payments on long-term borrowings		(63	)		(1,925	)		—			(1,988	)
Partnership distribution		—			(2,257	)		—			(2,257	)
Deferred financing fees		—			(3,242	)		—			(3,242	)
Other		47			(564	)		—			(517	)
Net cash provided by (used in) financing activities		5,908			(7,988	)		—			(2,080	)
Increase (decrease) in cash		276			(410	)		—			(134	)
Cash at beginning of period		—			1,924			—			1,924
Cash at end of period	$	276		$	1,514		$	—		$	1,790

Condensed Consolidating Statement of Cash Flows
For the six months ended June 30, 2008 (1)
(unaudited)
(In thousands)

	Abraxas Petroleum Corporation			Abraxas Energy Partners, L.P.			Reclassifi- cations and eliminations			Consolidated
Operating Activities
Net income (loss)	$	3,415		$	(88,672	)	$	—		$	(85,257	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Change in derivative fair value		—			100,038			—			100,038
Depreciation, depletion, and amortization		1,515			9,583			—			11,098
Distribution from Energy Partners		4,154			—			(4,154	)		—
Accretion of future site restoration		39			224			—			263
Amortization of deferred financing fees		20			447			—			467
Stock-based compensation		896			—			—			896
Other non-cash transactions		42			—			—			42
Changes in operating assets and liabilities:
Accounts receivable		(18,801	)		(9,871	)		14,604			(14,068	)
Other assets		78			(10	)		—			68
Accounts payable and accrued expenses		20,601			7,546			(11,207	)		16,940
Net cash provided by operations		11,959			19,285			(757	)		30,487

Investing Activities
Capital expenditures, including purchases and development of properties		(21,436	)		(134,039	)		—			(155,475	)
Net cash used in investing activities		(21,436	)		(134,039	)		—			(155,475	)

Financing Activities
Proceeds from stock options		44			—			—			44
Proceeds from long-term borrowings		4,662			119,700			—			124,362
Partnership distribution		—			(4,786	)		757			(4,029	)
Deferred financing fees		—			(1,615	)		—			(1,615	)
Net cash provided by financing activities		4,706			113,299			757			118,762
Decrease in cash		(4,771	)		(1,455	)		—			(6,226	)
Cash at beginning of period		17,177			1,759			—			18,936
Cash at end of year period	$	12,406		$	304		$	—		$	12,710

(1)	As adjusted for FAS No. 160 “Non-controlling Interest in Consolidated Financial Statements.”

Note 7. Earnings (Loss) Per Share

The following table sets forth the computation of basic and diluted earnings (loss) per share:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Numerator:
Net loss available to common stockholders	$	(10,032	)	$	(57,688	)	$	(5,582	)	$	(66,679	)
Denominator:
Denominator for basic earnings (loss) per share -
Weighted-average shares		49,564			48,911			49,628			48,901

Effect of dilutive securities:
Stock options and warrants		—			—			—			—

Dilutive potential common shares		—			—			—			—
Denominator for diluted earnings (loss) per share - adjusted weighted-average shares and assumed conversions		49,564			48,911			49,628			48,901

Net loss per common share – basic	$	(0.20	)	$	(1.18	)	$	(0.11	)	$	(1.36	)

Net loss per common share – diluted	$	(0.20	)	$	(1.18	)	$	(0.11	)	$	(1.36	)

For the three and six months ended June 30, 2009 and 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 periods. Had there not been losses in the periods, dilutive shares would have been 321,286 and 330,226 shares and 607,610 and 508,958 shares for the three and six months ended June 30, 2009 and 2008, respectively.

Note 8. 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 June 30, 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
Year 2012	Gas	3,000 Mmbtu	$6.88
Year 2012	Oil	670 Bbl	$67.60

At June 30, 2009, the aggregate fair market value of our commodity derivative contracts was approximately $24.3 million.

On July 29, 2009, the derivative contracts for the periods 2009 through 2011 were monetized for $26.7 million. These funds, together with the July 2009 settlement of its commodity swaps of $2.0 million, were used by the Partnership to repay outstanding indebtedness under the Partnership Credit Facility. In connection with the monetization and repayment, the Partnership was required to enter into new commodity swaps. The following table sets forth the consolidated weighted average derivative contract position as of July 29, 2009 for Abraxas Petroleum and the Partnership:

	Fixed-Price Swaps
	Oil		Gas
Contract Period	Daily Volume (Bbl)	Swap Price	Daily Volume (Mmbtu)	Swap Price
Q4 2009	1,355	$68.90	13,981	$4.50
2010	1,158	73.28	11,258	5.73
2011	1,035	76.61	9,580	6.52
2012	946	70.89	8,303	6.77
2013	705	80.79	5,962	6.84

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 at June 30, 2009 was a liability of $2.7 million.

Note 9. 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. The adoption of FAS 157 did not have an impact on the Company.

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 June 30, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of June 30, 2009
Assets
Investment in common stock	$	192	$	—	$	—	$	192
NYMEX-based fixed price derivative contracts		—		27,548		—		27,548
Total assets	$	192	$	27,548	$	—	$	27,740
Liabilities
NYMEX-based fixed price derivative contracts	$	—	$	3,202	$	—	$	3,202
Interest Rate Swaps		—		—		2,697		2,697
Total Liabilities	$	—	$	3,202	$	2,697	$	5,899

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 June 30, 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 three and six months ended June 30, 2009 is as follows (in thousands):

	Derivative Assets and (Liabilities) - net
	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Balance Beginning of period	$	(2,950	)	$	(3,000	)
Total realized and unrealized losses included in change in net liability		(357	)		(869	)
Settlements during the period		610			1,172
Ending balance June 30, 2009	$	(2,697	)	$	(2,697	)

Note 10. 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 June 30, 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.

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 51.8% non-controlling owners presented as non-controlling interest. Abraxas owns the remaining 48.2% 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 an 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 four 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;

· 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 six months of 2008, prices for oil and gas were sustained at record or near-record levels. New York Mercantile Exchange (NYMEX) spot prices for West Texas Intermediate (WTI) oil averaged $111.10 per barrel for the six month period ended June 30, 2008. WTI oil ended the quarter at $140.00 per barrel. NYMEX Henry Hub spot prices for gas averaged $10.02 per million British thermal units (MMBtu) during first six months of 2008. During the first six months of 2009, prices of oil and gas declined significantly from the levels experienced during the first six months of 2008. During the first six months of 2009, the New York Mercantile (NYMEX) price for West Texas Intermediate (WTI) averaged $51.59 per barrel. NYMEX Henry Hub spot prices for gas averaged $4.12 per million British thermal units (MMBtu) for the first six months of 2009. Prices closed the quarter at $69.89 per Bbl of oil and $3.71 per MMBtu of gas and continue to be significantly lower when compared to the same period of 2008. If commodity prices continue to decline, our revenue and cash flow from operations could also decline. In addition, lower commodity prices could also significantly reduce the amount of oil and gas we can produce economically. The current global recession has had a significant impact on commodity prices and our operations. If commodity prices remain depressed, our revenues, profitability and cash flow from operations may decrease which could cause us to alter our business plans, including reducing our drilling activities.

Declines in commodity prices could also result in downward adjustments to our estimated proved reserves under applicable accounting rules. Under these rules, if the net capitalized cost of oil and gas properties exceeds the PV-10 of our reserves, we must charge the amount of the excess to earnings. For example, as of December 31, 2008, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $116.4 million ($19.2 million for Abraxas Petroleum’s properties and $97.1 million for Abraxas Energy’s properties) resulting in a write-down of $116.4 million. These amounts were calculated considering 2008 year-end prices of $44.60 per Bbl for oil and $5.62 per Mcf for gas as adjusted to reflect the expected realized prices for each of our oil and gas reserves compared to each of the full cost pools. This charge did not impact cash flow from operating activities, but did reduce our stockholder’s equity and earnings. The risk that we will be required to write-down the carrying value of oil and gas properties increases when oil and gas prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher gas and oil prices may have increased the ceiling applicable to the subsequent period.

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 quality; and

gathering, processing and transportation costs.

During the first six months of 2009, differentials averaged $7.71 per Bbl of oil and $0.99 per Mcf of gas as compared to $3.85 per Bbl of oil and $1.38 per Mcf of gas during the first six months 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. As the percentage of our production from the Rocky Mountain and Mid-Continent regions increases, we expect that our price differentials will also increase. Increases in the differential between benchmark prices for oil and gas and the wellhead price we receive could significantly reduce revenues and cash flow from operations.

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. 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 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 June 30, 2009:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2009	Gas	10,595 Mmbtu	$8.45
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
Year 2012	Gas	3,000 Mmbtu	$6.88
Year 2012	Oil	670 Bbl	$67.60

At June 30, 2009, the aggregate fair market value of our derivative contracts was approximately $24.3 million.

On July 29, 2009, the derivative contracts for the periods 2009 through 2011 were monetized for $26.7 million. These funds, together with the July 2009 settlement of its commodity swaps of $2.0 million, were used by the Partnership to repay outstanding indebtedness under the Partnership Credit Facility. In connection with the monetization and repayment, the Partnership’s borrowing base was reduced and the Partnership was required to enter into new commodity swaps. The following table sets forth the consolidated weighted average derivative contract position as of July 29, 2009 for us and the Partnership:

		Fixed-Price Swaps
		Oil				Gas
Contract Period		Daily Volume (Bbl)		Swap Price		Daily Volume (Mmbtu)		Swap Price
	Q4 2009		1,355	$	68.90		13,981	$	4.50
	2010		1,158		73.28		11,258		5.73
	2011		1,035		76.61		9,580		6.52
	2012		946		70.89		8,303		6.77
	2013		705		80.79		5,962		6.84

When our derivative contract prices are higher than market prices, we will incur realized and unrealized gains on the derivative contracts and when contract prices are lower than market prices, we will incur realized and unrealized losses.

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 $7.5 million during the first six months of 2009 of which $3.1 million was by the Partnership and $4.4 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, if the Merger is not consummated, Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, sales of debt or equity securities, if available, and, if an appropriate opportunity presents itself, proceeds from the sale of properties. If the Merger is not consummated, 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. If the Merger is consummated, the Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement will be refinanced and terminated and our sources of capital going forward will primarily be cash from operating activities, funding under the new credit facility, cash on hand and, if an appropriate opportunity presents itself, proceeds from the sale of properties and sales of debt or equity securities.

At June 30, 2009, Abraxas had approximately $0.6 million of availability under the Credit Facility and the Partnership had approximately $4.4 million of availability under the Partnership Credit Facility. At July 31, 2009, in connection with the monetization and repayment of $28.7 million of indebtedness, Abraxas Energy had indebtedness of approximately $95.0 million and no availability under its credit facility. The Subordinated Credit Agreement currently matures on August 14, 2009. The Partnership has entered into discussions with the lenders under the Partnership Credit Facility and the Subordinated Credit Agreement to extend the maturity date and certain other items to September 14, 2009. The Partnership had intended to repay the Subordinated Credit Agreement with proceeds from its initial public offering. Under the terms of the Voting Agreement, the Partnership agreed to not file any further amendments to the registration statement for its initial public offering or take any actions intended to consummate the initial public offering and, as a result of executing the Merger Agreement, we and the Partnership are no longer pursuing the refinancing of the Subordinated Credit Agreement other than in connection with the new credit facility which is subject to the completion of the Merger. In connection with the Merger, we have received a non-binding term sheet for a new senior secured revolving credit facility of up to $300.0 million, of which $155.0 million is expected to be available to us at closing. If the Merger is not consummated, the Partnership would be in default under its Subordinated Credit Agreement and under the Partnership Credit

Facility. We cannot assure you that the new credit facility will be consummated. If an event of default were to occur under the Subordinated Credit Agreement or the Partnership Credit Facility, 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. Over the five years ended December 31, 2008, we drilled or participated in drilling 77 gross (34.8 net) wells, of which 94.8% resulted in commercially productive wells.

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, 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 $123.7 million under the Partnership Credit Facility and $40 million under its Subordinated Credit Agreement as of June 30, 2009. On July 31, 2009, the Partnership repaid $28.7 million of indebtedness after which, the Partnership had $95.0 million outstanding under the Partnership Credit Facility and no availability. At June 30, 2009, Abraxas had indebtedness of $5.9 million and availability of $575,000 under its Credit Facility. At July 31, 2009, in connection with the monetization and repayment of $28.7 million of indebtedness, Abraxas Energy had indebtedness of approximately $95.0 million and no availability 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 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%.

Recent Events

Merger Agreement

On July 17, 2009, Abraxas Petroleum and Abraxas Energy Partners, and, from and after its accession to the agreement, the Delaware limited liability company formed as a wholly-owned subsidiary of Abraxas (“Merger Sub”), entered into an Amended and Restated Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which Abraxas Energy Partners will, subject to the terms and conditions of the Merger Agreement, merge with and into Merger Sub, with Merger Sub surviving and continuing as a wholly-owned subsidiary of Abraxas Petroleum (the “Merger”).

As of July 17, 2009, Abraxas Petroleum and its subsidiaries beneficially own, within the meaning of Rule 13d-3 of the U.S. Securities and Exchange Act of 1934, as amended, 5,350,598 common units of Abraxas Energy Partners, representing approximately 46.7% of the outstanding Abraxas Energy Partners common units (the “Abraxas Energy Partners Common Units”).

The Merger Agreement contains (a) customary representations and warranties of Abraxas Petroleum, Abraxas Energy Partners and Merger Sub; (b) covenants of Abraxas Petroleum and Abraxas Energy Partners to conduct their respective businesses in the ordinary course until the Merger is completed; and (c) covenants of Abraxas Petroleum and Abraxas Energy Partners not to take certain actions during such period, including prohibitions on the declaration or payment of dividends and distributions.

Consummation of the Merger is subject to conditions set forth in the Merger Agreement, including, among others, (1) the approval of the issuance of Abraxas Petroleum common stock in the Merger (the “Stock Issuance”) by the affirmative vote of the holders of a majority of the Abraxas Petroleum common stock voting at a stockholders’ meeting, (2) the approval of an amendment to the Abraxas Petroleum 2005 Long-Term Equity Incentive Plan to increase the number of authorized shares for issuance under the plan (the “LTIP Amendment”) by the affirmative vote of the holders of a majority of the outstanding Abraxas Petroleum common stock voting at a stockholders’ meeting, (3) the receipt by Abraxas Petroleum of financing that is sufficient to consummate the Merger and repay all indebtedness outstanding under Abraxas Energy Partner’s credit agreement and subordinated credit agreement, and, (4) certain other customary closing conditions.

applicable to investors, or may have been used for the purpose of allocating risk between the parties rather than establishing matters as facts.

Voting Agreement

The Voting Agreement provides, among other things, that all of the limited partners that are party to the Voting Agreement will:

·	vote all of their outstanding common units of Abraxas Energy Partners in favor of the Merger;

·	vote against any other merger agreement, consolidation, combination, sale of substantial assets or similar transaction;

·	grant an irrevocable proxy to Abraxas Petroleum to vote all of their common units of Abraxas Energy Partners in favor of the Merger Agreement and against any other transaction;

·	agree to not, directly or indirectly, transfer any of such limited partners common units of Abraxas Energy Partners to any person (other than an affiliate of such limited partner who agrees to be bound by the terms of this agreement) other than pursuant to the Merger;

·	not directly, or indirectly permit any person on behalf of such limited partner, to effect any transactions in the securities of Abraxas Petroleum;

·	not exercise any of its rights or take any action under the Exchange and Registration Rights Agreement, dated as of May 25, 2007, as amended, by and among Abraxas Petroleum, Abraxas Energy Partners and the limited partners signatories thereto.

The Voting Agreement provides, among other things, that Abraxas Petroleum and Abraxas Energy Partners will:

·	not file any further amendments to the registration statement on Form S-1 (No. 333-144537) relating to the initial public offering of the common units of Abraxas Energy Partners; and

·	at the Effective Time increase the size of the Board of Directors of Abraxas Petroleum by two members and elect Ed Russell and Brian Melton to serve on the Board of Directors.

Amendments to the Credit Agreements

On July 22, 2009, Abraxas Energy Partners entered into Amendment No. 5 to the Partnership Credit Facility, dated as of January 31, 2008, by and among Abraxas Energy Partners, the lenders party thereto and Société Générale, as Administrative Agent, and Amendment No. 5 to the Subordinated Credit Agreement dated as of January 31, 2008, by and among Abraxas Energy Partners, the lenders party thereto and Société Générale, as Administrative Agent. Pursuant to these amendments, among other things, the lenders permitted the monetization of the Partnership’s existing commodity swaps. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Facility on July 31, 2009. In connection with the monetization and repayment, the Partnership was required to enter into new commodity swaps. The following table sets forth the consolidated weighted average derivative contract position as of July 29, 2009 for Abraxas Petroleum and the Partnership:

	Fixed-Price Swaps
	Oil		Gas
Contract Period	Daily Volume (Bbl)	Swap Price	Daily Volume (Mmbtu)	Swap Price
Q4 2009	1,355	$68.90	13,981	$4.50
2010	1,158	73.28	11,258	5.73
2011	1,035	76.61	9,580	6.52
2012	946	70.89	8,303	6.77
2013	705	80.79	5,962	6.84

Results of Operations

The following table sets forth certain of our operating data for the periods presented. The operating data represents the consolidated data for Abraxas Petroleum and Abraxas Energy Partners.

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008 (2)
	(in thousands)
Operating Revenue: (1)
Oil Sales	$	7,639	$	17,410	$	12,669	$	28,268
Gas Sales		4,480		16,673		10,046		27,678
Rig Operations		247		329		500		635
Other		2		11		3		12
	$	12,368	$	34,423	$	23,218	$	56,593


Operating Income (loss)	$	64	$	19,183	$	(1,759	)	$	29,048
Oil Production (MBbls)		147		148		290			264
Gas Production (MMcfs)		1,584		1,698		3,205			3,203
Average Oil Sales Price ($/Bbl)	$	52.05	$	117.94	$	43.69		$	107.25
Average Gas Sales Price ($/Mcf)	$	2.83	$	9.82	$	3.13		$	8.64

(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 through June 2008.

Comparison of Three Months Ended June 30, 2009 to Three Months Ended June 30, 2008

Operating Revenue. During the three months ended June 30, 2009, operating revenue from oil and gas sales decreased to $12.1 million compared to $34.1 million in the three months ended June 30, 2008. The decrease in revenue was due to significantly lower realized prices as well as a slight decrease in production volumes. Decreased commodity prices had a negative impact of $21.6 million on revenue from oil and gas sales while decreased production volumes had a negative impact of approximately $388,000 for the quarter ended June 30, 2009.

Oil production volumes decreased from 147.6 MBbls during the quarter ended June 30, 2008 to 146.8 MBbls for the same period of 2009. The decrease in oil sales volumes was primarily due to natural field declines partially offset by wells that were put on production in early 2009. New wells put on production contributed 7.9 MBbls during the second quarter of 2009. Gas production volumes decreased from 1,698 MMcf for the three months ended June 30, 2008 to 1,584 MMcf for the same period of 2009. The decrease in gas sales volumes was primarily due to natural field declines partially offset by wells that were put on production in early 2009. New wells put on production contributed 120.7 MMcf during the second quarter of 2009.

Average sales prices, before the impact of derivative activities, for the quarter ended June 30, 2009 were:

$ 52.05 per Bbl of oil, and

$ 2.83 per Mcf of gas

Average sales prices, before the impact of derivative activities, for the quarter ended June 30, 2008 were:

$ 117.94 per Bbl of oil, and

$ 9.82 per Mcf of gas

Lease Operating Expenses (“LOE”). LOE for the three months ended June 30, 2009 decreased to $6.0 million from $7.2 million for the same period in 2008. The decrease in LOE was primarily due to a decrease in production taxes as a result of lower commodity prices realized during the second quarter of 2009. LOE on a per BOE basis for the three months ended June 30, 2009 was $14.57 per BOE compared to $16.65 for the same period of 2008.

General and Administrative Expenses (“G&A”). G&A expenses excluding stock-based compensation increased to $1.3 million for the quarter ended June 30, 2009 from $1.2 million for the same period of 2008. The increase in G&A was primarily due to higher professional fees and consulting fees. G&A expense on a per BOE basis was $3.10 for the quarter ended June 30, 2009 compared to $2.84 for the same period of 2008. The increase in G&A expense on a per BOE basis was primarily due to increased cost and lower production volumes in the second quarter of 2009 compared to the same period in 2008.

For the quarters ended June 30, 2009 and 2008, equity based compensation was approximately $329,000 and $650,000 respectively. The decrease in 2009 as compared to 2008 was due to expenses related to higher valued options granted in prior years that have been fully amortized.

Depreciation, Depletion and Amortization Expenses (“DD&A”). DD&A expense decreased to $4.5 million for the three months ended June 30, 2009 from $6.0 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 June 30, 2009 was $10.98 per BOE compared to $13.95 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 increased to $3.1 million for the second quarter of 2009 compared to $2.7 million for the same period of 2008. The increase in interest expense was primarily due to higher interest rates during the second quarter of 2009 as compared to 2008. The interest rates on the Partnership Credit Agreement averaged approximately 5.5% and the interest rate on the Subordinated Credit Facility averaged approximately 12.0% for the quarter ended June 30, 2009 compared to 4.8% and 8.0% for the quarter ended June 30, 2008. In addition, the Abraxas Senior Secured Credit Facility had a balance of $5.9 million as of June 30, 2009 compared to zero at June 30, 2008. The interest rate on this credit facility was 2.8% at June 30, 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 are 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 $24.3 million as of June 30, 2009. For the quarter ended June 30, 2009, we realized a gain on these derivative contracts of $7.0 million.

Other expense. Other expense for the quarter ended June 30, 2009, consist primarily of fees and expenses, which were paid over the past two years, associated with the Partnerships initial public offering which it is no longer pursuing in accordance with the terms of the Voting Agreement.

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. Additionally, in accordance with generally accepted accounting principles in effect prior to the adoption of SFAS 160, 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 are charged to the earnings of the controlling interest. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the non-controlling interest exceeded the non-controlling interest equity capital by $28.2 million and, thus $28.2 million of the non-controlling interest loss in excess of equity was charged to earnings and is reflected as a reduction of the losses, realized and unrealized, applicable to the non-controlling interest. Under the provisions of SFAS 160, the non-controlling interest share of the loss for the period ended June 30, 2009 would have increased by $28.2 million, from $18.6 million to $46.8 million.

Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

Operating Revenue. During the six months ended June 30, 2009, operating revenue from oil and gas sales decreased to $22.7 million compared to $55.9 million in the six months ended June 30, 2008. The decrease in revenue was due to significantly lower commodity prices partially offset by increased production volumes. Decreased commodity prices had a negative impact of $34.4 million on revenue from oil and gas sales while increased production volumes contributed $1.2 million for the first six months of 2009.

Oil production volumes increased from 263.6 MBbls during the six months ended June 30, 2008 to 290.0 MBbls for the same period of 2009. The increase in oil sales volumes was primarily due to wells put on production during the first six months of 2009. New wells put on production contributed 11.7 MBbls during the six months ended June 30, 2009. In addition, production from properties acquired in

the St Mary acquisition in January 2008 contributed a full six months of production to the six month period ended June 30, 2009 compared to five months for the six month period ended June 30, 2008. Production from these properties was 161.1 MBbls for the period February through June 2008, compared to 171.5 MBbls for the six months ended June 30, 2009. Gas production increased to 3,205 MMcf for the six months ended June 30, 2009 from 3,203 MMcf for the same period of 2008.

Average sales prices, before the impact of derivative activities, for the six months ended June 30, 2009 were:

$ 43.69 per Bbl of oil, and

$ 3.13 per Mcf of gas

Average sales prices, before the impact of derivative activities, for the six months ended June 30, 2008 were:

$ 107.25 per Bbl of oil, and

$ 8.64 per Mcf of gas

Lease Operating Expenses. LOE for the six months ended June 30, 2009 decreased to $11.9 million from $12.4 million for the same period in 2008. The decrease in LOE was primarily due to a decrease in production taxes as a result of lower commodity prices realized during the six months ended June 30, 2009. LOE on a per BOE basis for the six months ended June 30, 2009 was $14.38 per BOE compared to $15.51 for the same period of 2008.

General and Administrative Expenses. G&A expenses, excluding stock-based compensation expense, increased from $2.8 million for the first six months of 2008 to $3.1 million for the same period of 2009. The increase in G&A was primarily due to higher professional fees. G&A expense on a per BOE basis was $3.80 for the six months ended June 30, 2009 compared to $3.48 for the same period of 2008. The increase in G&A expense on a per BOE basis was primarily due to increased cost offset by higher production volumes in the first six months 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 six months ended June 30, 2009 and 2008, equity based compensation was approximately $596,000 and $896,000 respectively. The decrease in 2009 as compared to 2008 was due to expenses related to higher valued options granted in prior years that have been fully amortized.

Depreciation, Depletion and Amortization Expenses (“DD&A”). DD&A expense decreased to $9.0 million for the six months ended June 30, 2009 from $11.1 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 six months ended June 30, 2009 was $10.91 per BOE compared to $13.92 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 increased to $5.6 million for the six months ended June 30, 2009 compared to $5.1 million for the same period of 2008. The increase in interest expense was primarily due to higher interest rates during the six months ended June 30, 2009 as compared to 2008. The interest rates on the Partnership Credit Agreement averaged approximately 5.5% and the interest rate on the Subordinated Credit Facility averaged approximately 11.0% for the six months ended June 30, 2009 compared to 5.4% and 8.5% for the six months ended June 30, 2008. In addition, the Abraxas Senior Secured Credit Facility had a balance of $5.9 million as of June 30, 2009 compared to zero at June 30, 2008. The interest rate on this credit facility was 2.8% at June 30, 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 $24.3 million as of June 30, 2009. For the six months ended June 30, 2009, we realized a gain on these derivative contracts of $14.0 million.

Other expense. Other expense for the six months ended June 30, 2009, consist primarily of fees and expenses which, were paid over the past two years, associated with the Partnerships initial public offering which it is no longer pursuing in accordance with the terms of the Voting Agreement.

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. Additionally, in accordance with generally accepted accounting principles in effect prior to the adoption of SFAS 160,, 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 are charged to the earnings of the controlling interest. During the six months ended June 30, 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the non-controlling interest exceeded the non-controlling interest equity capital by $28.2 million and, thus $28.2 million of the non-controlling interest loss in excess of equity was charged to earnings and is reflected as a reduction of the losses, realized and unrealized, applicable to the non-controlling interest. Under the provisions of SFAS 160, the non-controlling interest share of the loss for the period ended June 30, 2008 would have increased by $28.2 million, from $18.6 million to $46.8 million.

Recently Issued Accounting Pronouncements

In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry

Guide 2 in Regulation S-K. The new requirements provide for consideration of new technologies in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations. The final rules are effective for fiscal years ending on or after December 31, 2009.

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 have primarily been cash from operating activities, funding under the Credit Facility, cash distributions from the Partnership, cash on hand, and if an appropriate opportunity presents itself, proceeds from the sale of properties. The Partnership’s principal sources of capital have been cash from operating activities, borrowings under the Partnership Credit Facility and sales of debt or equity securities if available to it.

After the Merger is consummated, we expect that our principal sources of capital will be cash flow from operations, borrowings under our new credit facility and if an opportunity presents itself, the sale of debt or equity securities. We may also sell assets in order to provide us with capital.

Working Capital (Deficit). At June 30, 2009, our current liabilities of approximately $58.6 million exceeded our current assets of $27.7 million resulting in a working capital deficit of $30.9 million. This compares to a working capital deficit of approximately $26.0 million at December 31, 2008. Current liabilities at June 30, 2009 primarily consisted of the current portion of long-term debt consisting of $40.0 million outstanding under the Subordinated Credit Agreement and $5.9 million outstanding under the Credit Facility, the current portion of derivative liabilities of $2.7 million, trade payables of $5.2 million, revenues due third parties of $2.8 million, and other accrued liabilities of $1.6 million. . The Abraxas Senior Secured Credit Facility which is due on September 30, 2010 is classified as current maturities at June 30, 2009 as a result of continued non-compliance with the current ratio covenant as defined in the facility.

The Subordinated Credit Agreement currently matures on August 14, 2009 and currently requires that Abraxas Energy Partners receives $20.0 million of proceeds from an equity issuance on or before August 14, 2009. Abraxas Energy Partners has entered into discussions with the lenders to extend the maturity date and requirement for proceeds from an equity issuance to September 14, 2009. The Partnership had intended to repay the Subordinated Credit Agreement with proceeds from its initial public offering. Under the terms of the Voting Agreement, the Partnership agreed to not file any further amendments to the registration statement for its initial public offering or take any actions intended to consummate the initial public offering and, as a result of executing the Merger Agreement, we and the Partnership are no longer pursuing the refinancing of the Subordinated Credit Agreement other than in connection with the new credit facility which is subject to the completion of the Merger. In connection with the Merger, we have received a non-binding term sheet for a new senior secured revolving credit facility of up to $300.0 million, of which $155.0 million is expected to be available to us at closing. We cannot assure you that the Merger or new credit facility will be consummated. If the Merger is not consummated, the Partnership would likely be in default under the Partnership Credit Facility and the Subordinated Credit Agreement. Upon an event of default, the Partnership’s lenders could foreclose on its assets and exercise other customary remedies which would have a material adverse effect on us.

Capital expenditures. Capital expenditures during the first six months of 2009 were $7.5 million compared to $155.5 million during the same period of 2008. The table below sets forth the components of these capital expenditures on a historical basis for the six months ended June 30, 2009 and 2008.

	Six Months Ended June 30,
	2009		2008
	(in thousands)
Expenditure category:
Acquisitions	$	—	$	133,156
Development		7,380		16,341
Facilities and other		130		5,978
Total	$	7,510	$	155,475

During the six months ended June 30, 2009, capital expenditures were primarily for development of our existing properties. During the six months ended June 30, 2008, capital expenditures were primarily for the acquisition of properties from St. Mary as well as the development of our existing properties. Abraxas anticipates making capital expenditures of $20 million in 2009. The Partnership anticipates making capital expenditures in 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, after the consummation of the Merger, the new 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 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:

	Six Months Ended June 30,
	2009			2008
	(dollars in thousands)
Net cash provided by operating activities	$	9,456		$	30,487
Net cash used in investing activities		(7,510	)		(155,475	)
Net cash provided by financing activities		(2,080	)		118,762
Total	$	(134	)	$	(6,226	)

Operating activities during the six months ended June 30, 2009 provided us $9.5 million of cash compared to providing $30.5 in the same period in 2008. 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 used $2.1 million for the first six months of 2009 compared to providing $118.8 million for the same period of 2008. Funds provided in 2008 were primarily proceeds from the Partnership Credit Facility and Subordinated Credit Agreement in connection with the St. Mary property acquisition. Most of the funds provided in 2009 were proceeds from long-term debt offset by partnership distributions and deferred financing fees. Investing activities used $7.5 million during the six months ended June 30, 2009 compared to using $155.5 million for the six months ended June 30, 2008. Expenditures of $155.5 million during the six months ended June 30, 2008 were primarily for the acquisition of properties from St. Mary Land and Exploration as well as the development of our existing properties. For the first half of 2009, capital expenditures were primarily for the development of existing properties.

Future Capital Resources. Since the formation of the Partnership in May 2007, Abraxas’ sources of capital have primarily been cash from operating activities, funding under the Credit Facility and distributions from the Partnership. As a result of recent amendments to the Partnership Credit Facility and the Merger Agreement, Abraxas Energy Partners is precluded from declaring or paying cash distributions. In addition, under the terms of the Partnership Credit Facility, Abraxas was required to repay the distribution attributable to the fourth quarter of 2008 of approximately $1.9 million to the Partnership which, in turn, made a principal payment of approximately $1.9 million under the Partnership Credit Facility. Abraxas Energy Partners’ principal sources of capital have been cash from operating activities, (including realized gains and losses on its derivative contracts), borrowings under the Partnership Credit Facility and sales of equity securities.

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 continued to decline during the first part of 2009. Oil prices have strengthened during the second quarter of 2009 while gas prices have remained weak. 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 classified as 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 currently matures on August 14, 2009. The Partnership has entered into discussions with the lenders under the Partnership Credit Facility and the Subordinated Credit Agreement to extend the maturity date to September 14, 2009. The Partnership had intended to repay the Subordinated Credit Agreement with proceeds from its initial public offering. Under the terms of the Voting Agreement, the Partnership agreed to not file any further amendments to the registration statement for its initial public offering or take any actions intended to consummate the initial public offering and, as a result of executing the Merger Agreement, we and the Partnership are no longer pursuing the refinancing of the Partnership’s Subordinated Credit Agreement other than in connection with the new credit facility which is subject to the completion of the Merger.

In connection with the Merger, we have received a non-binding term sheet for a new senior secured revolving credit facility of up to $300.0 million, of which $155.0 million is expected to be available to us at closing. If the Merger is not consummated, the Partnership would be in default under the Subordinated Credit Agreement and under the Partnership Credit Facility. We cannot assure you that the

Merger or the new credit facility will be consummated. If an event of default were to occur under the Subordinated Credit Agreement or the Partnership Credit Facility, 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 counterparties performance risk. Current market conditions also elevate concern over counterparties risks related to our commodity derivative instruments. The Partnership has all of its commodity derivative instruments with two major financial institutions. Should these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts 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 counterparties, and we are not currently aware of any inability on the part of our counterparties to perform under our contracts. However, we are not able to predict sudden changes in the credit worthiness of our counterparties.

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 was deferred. In addition, under the amended terms of the Partnership Credit Facility, Abraxas Petroleum was required to repay the distribution for the fourth quarter of 2008 of approximately $1.9 million to the Partnership which, in turn, made a principal payment under the Partnership Credit Facility of approximately $1.9 million. In consideration of making this payment, Abraxas Petroleum was 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 if the Merger is not completed. Furthermore, under the Merger Agreement, the Partnership is precluded from declaring or paying cash distributions.

Both Abraxas Petroleum and the Partnership could also seek capital through the sale of debt and equity securities. 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

Operating leases for office facilities

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of June 30, 2009:

	Payments due in twelve month periods ending:
Contractual Obligations (dollars in thousands)	Total		June 30, 2010		June 30, 2011-2012		June 30, 2013-2014		Thereafter
Long-Term Debt (1)	$	174,905	$	40,138	$	129,903	$	347	$	4,517
Interest on long-term debt (2)		20,362		7,935		11,557		607		263
Total	$	195,267	$	48,073	$	141,460	$	954	$	4,780

(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 June 30, 2009, our reserve for these obligations totaled $10.2 million for which no contractual commitment exists.

Off-Balance Sheet Arrangements. At June 30, 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 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 June 30, 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:


	June 30, 2009			December 31, 2008
Partnership credit facility	$	123,675		$	125,600
Partnership subordinated credit agreement		40,000			40,000
Senior secured credit facility		5,924			—
Real estate lien note		5,306			5,369
		174,905			170,969
Less current maturities		(46,062	)		(40,134	)
	$	128,843		$	130,835

Abraxas Senior Secured Credit Facility

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 August 7, 2009, the interest rate on the Credit Facility was 2.8%. 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.

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.

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, May 7, 2009, June 30, 2009 and July 22, 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 August 7, 2009, was $95.0 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 June 30, 2009 of $128.1 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 June 30, 2009, the Partnership had a total of $123.7 million outstanding under the Partnership Credit Facility. On July 31, 2009, the Partnership repaid $28.7 million of indebtedness after which, the Partnership had $95.0 million outstanding under the Partnership Credit Facility. Simultaneously, the borrowing base under the Partnership Credit Facility was reduced to $95.0 million.

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 Abraxas Operating, 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 Abraxas Operating, 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 June 30, 2009, the Partnership’s current ratio was 23.74 to 1.00 and its interest coverage ratio was 3.85 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. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. In connection with the monetization and repayment, the Partnership’s borrowing base was reduced to $95.0 million and the Partnership was required to enter into new commodity swaps on approximately 85% of its estimated oil and gas production from its net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013.

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 was in compliance with all covenants as of June 30, 2009.

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, May 7, 2009, June 30, 2009 and July 22, 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) 12.0% or, if the Partnership elects, at the greater of (a) 2.0% and (b) the London Interbank Offered Rate, in each case, plus 13.0%. At August 7, 2009, the interest rate on the Subordinated Credit Agreement was 15.0%. 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. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. In connection with the monetization and repayment, the Partnership’s borrowing base was reduced to $95.0 million and the Partnership was required to enter into new commodity swaps on approximately 85% of its estimated oil and gas production from its net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013.

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 August 14, 2009. In addition, if the indebtedness under the Subordinated Credit Agreement has not been repaid on or before August 14, 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. The Subordinated Credit Agreement currently matures on August 14, 2009. The Partnership has entered into discussions with the lenders under the Partnership Credit Facility and the Subordinated Credit Agreement to extend the maturity date and the requirement for proceeds from an equity issuance and the warrant issuance to September 14, 2009. The Partnership had intended to repay the Subordinated Credit Agreement with proceeds from its initial public offering. Under the terms of the Voting Agreement, the Partnership agreed to not file any further amendments to the registration statement for its initial public offering or take any actions intended to consummate the initial public offering and, as a result of executing the Merger Agreement, we and the Partnership are no longer pursuing the refinancing of the Partnership’s Subordinated Credit Agreement other than in connection with the new credit facility which is subject to the completion of the Merger. In connection with the Merger, we have received a non-binding term sheet for a new senior secured revolving credit facility of up to $300.0 million, of which $155.0 million is expected to be available to us at closing. If the Merger is not consummated, the Partnership would be in default under its Subordinated Credit Agreement and under the Partnership Credit Facility. We cannot assure you that the new credit facility will be consummated. If an event of default were to occur under the Subordinated Credit Agreement or the Partnership Credit Facility, 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 Partnership was in compliance with all covenants as of June 30, 2009.

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 June 30, 2009, $5.3 million was outstanding on the 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 derivative contracts, which we sometimes refer to as hedging arrangements for specified volumes, which equated to approximately 80% of the estimated oil and gas production through December 31, 2012 from its net proved developed producing reserves. On July 29, 2009, the Partnership monetized all of its “in-the-money” commodity swaps for $26.7 million and together with the July 2009 settlement of its commodity swaps of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. In connection with the

monetization and repayment, the Partnership’s borrowing base was reduced to $95.0 million and the Partnership was required to enter into new commodity swaps on approximately 85% of its estimated oil and gas production from its net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013.

The following table sets forth the consolidated weighted average derivative contract position as of July 29, 2009 for Abraxas Petroleum and the Partnership:

	Fixed-Price Swaps
	Oil		Gas
Contract Period	Daily Volume (Bbl)	Swap Price	Daily Volume (Mmbtu)	Swap Price
Q4 2009	1,355	$68.90	13,981	$4.50
2010	1,158	73.28	11,258	5.73
2011	1,035	76.61	9,580	6.52
2012	946	70.89	8,303	6.77
2013	705	80.79	5,962	6.84

Our new credit facility will require us to enter into new hedging arrangements for specified volumes which are expected to equate to approximately 85% of the estimated oil and gas production from our net proved developed reserves through December 31, 2012. We expect that the derivative contracts that we entered into on July 29, 2009 will satisfy this requirement. These new hedging arrangements will be priced at then-current market prices and may be significantly lower than the existing derivative contracts we currently have in place. By removing a significant portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained, and in the future will sustain, realized and unrealized losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on our derivative contracts. For example, in 2007, Abraxas Energy sustained an unrealized loss of $6.3 million and a realized gain of $1.9 million and in 2008, Abraxas Energy incurred a realized loss of $9.3 million and an unrealized gain of $40.5 million. During the first six months of 2009, Abraxas Energy incurred a realized gain of approximately $16.2 million and an unrealized loss of approximately $14.5 million. If a disparity between our new contract prices and market prices develops, we will sustain realized and unrealized gains or losses on our derivative contracts. While unrealized gains and losses do not impact our cash flow from operations, realized gains and losses do impact our cash flow from operations. In addition as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than the derivative contracts we enter into at the closing of the new credit facility, our future cash flow from operations would likely be materially lower. In addition, the borrowings under our new credit facility will bear interest at floating rates. 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.

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 three and six month periods ended June 30, 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 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 June 30, 2009, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $2.3 million for the six months ended June 30, 2009, however, due to the derivative contracts that the Partnership has in place, it is unlikely that a10% 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 in current derivative income (loss).

The following table sets forth the Partnership’s derivative contract position at June 30, 2009:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2009	Gas	10,595 Mmbtu	$8.45
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
Year 2012	Gas	3,000 Mmbtu	$6.88
Year 2012	Oil	670 Bbl	$67.60

At June 30, 2009, the aggregate fair market value of our commodity derivative contracts was approximately $24.3 million.

On July 29, 2009, the derivative contracts for the periods 2009 through 2011 were monetized for $26.7 million. These funds, together with $2.0 million from the July 2009 settlement of its commodity swaps, were used by the Partnership to repay $28.7 million of outstanding indebtedness under the Partnership Credit Facility. In connection with the monetization and repayment, the Partnership was required to enter into new commodity swaps. The following table sets forth the consolidated weighted average derivative contract position as of July 29, 2009 for Abraxas Petroleum and the Partnership:

	Fixed-Price Swaps
	Oil		Gas
Contract Period	Daily Volume (Bbl)	Swap Price	Daily Volume (Mmbtu)	Swap Price
Q4 2009	1,355	$68.90	13,981	$4.50
2010	1,158	73.28	11,258	5.73
2011	1,035	76.61	9,580	6.52
2012	946	70.89	8,303	6.77
2013	705	80.79	5,962	6.84

For the six months ended June 30, 2009 we recognized a realized gain of $14.0 million and an unrealized loss of $14.8 million.

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 June 30, 2009, the Partnership had $123.7 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 August 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 $1.2 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 August 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 June 30, 2009 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

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.

At the Annual Meeting of Shareholders held on May 21, 2009, the following proposals were adopted by the margins indicated:

1.	Election of two directors for a term of three years, to hold office until the expiration of his term in 2012 or until a successor shall have been elected and qualified.

	Number of Shares
	For	Withheld
Franklin A. Burke	42,681,634	1,706,447
Paul A. Powell, Jr.	42,596,610	1,791,471

In addition, the terms of office of C. Scott Bartlett, Harold D. Carter, Ralph F. Cox, Dennis E. Logue, and Robert L.G. Watson continued.

Approval of the appointment of BDO Seidman, LLP as the Company’s independent registered public accountants.

Number of Shares
For	Against	Abstain
43,257,973	912,487	217,619

Item 5. Other Information.

None

Item 6. Exhibits.

(a) Exhibits

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

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: August 10, 2009 By:/s/ Robert L.G. Watson

ROBERT L.G. WATSON,

President and Chief

Executive Officer

Date: August 10, 2009 By:/s/ Chris E. Williford

CHRIS E. WILLIFORD,

Executive Vice President and

Principal Accounting Officer