ABRAXAS PETROLEUM CORP - Quarter Report: 2009 September (Form 10-Q)

axas10q093009.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 SEPTEMBER 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 November 6, 2009 was:

Class	Shares Outstanding
Common Stock, $.01 Par Value	76,099,117

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;

weather conditions and events;

·	the proximity, capacity, cost and availability of pipelines and other transportation facilities;

·	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 - September 30, 2009 (unaudited) and December 31, 2008	4
	Condensed Consolidated Statements of Operations – (unaudited) Three and Nine Months Ended September 30, 2009 and 2008	6
	Condensed Consolidated Statements of Cash Flows – (unaudited) Nine Months Ended September 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	24

ITEM 3 -	Quantitative and Qualitative Disclosures about Market Risk	40

ITEM 4 -	Controls and Procedures	40

PART II
OTHER INFORMATION
ITEM 1 -	Legal Proceedings	41
ITEM 1a -	Risk Factors	41
ITEM 2 -	Unregistered Sales of Equity Securities and Use of Proceeds	42
ITEM 3 -	Defaults Upon Senior Securities	42
ITEM 4 -	Submission of Matters to a Vote of Security Holders	42
ITEM 5 -	Other Information	42
ITEM 6 -	Exhibits	42
	Signatures	43

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)

	September 30,
	2009		December 31,
	(Unaudited)		2008 (1)
Assets
Current assets:
Cash and cash equivalents	$	474	$	1,924
Accounts receivable, net:
Joint owners		593		1,740
Oil and gas production		5,978		6,168
Other		22		58
		6,593		7,966

Derivative asset – current		459		22,832
Other current assets		472		572
Total current assets		7,998		33,294

Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved		452,734		440,712
Unproved properties excluded from depletion		—		—
Other property and equipment		11,180		10,986
Total		463,914		451,698
Less accumulated depreciation, depletion, and amortization		304,479		291,390
Total property and equipment – net		159,435		160,308

Deferred financing fees, net		3,933		1,443
Derivative asset – long-term		426		16,394
Other assets		2,066		400
Total assets	$	173,858	$	211,839

(1)	As adjusted for “Noncontrolling Interest in Consolidated Financial Statements” in accordance with ASC 810. (See Note 1)

See accompanying notes to condensed consolidated financial statements (unaudited)

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Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands, except share data)

	September 30,
	2009			December 31,
	(Unaudited)			2008 (1)
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	7,351		$	10,748
Oil and gas production payable		2,540			3,176
Accrued interest		615			350
Other accrued expenses		2,228			1,886
Derivative liability – current		4,710			3,000
Current maturities of long-term debt		8,140			40,134
Other current liabilities		19			—
Total current liabilities		25,603			59,294

Long-term debt, excluding current maturities		138,264			130,835

Derivative liability – long-term		7,096			—
Future site restoration		10,301			9,959
Total liabilities		181,264			200,088

Equity (Deficit)
Abraxas Petroleum stockholders’ equity (deficit):
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 49,899,056 and 49,622,423		499			496
Additional paid-in capital		188,225			187,243
Accumulated deficit		(193,146	)		(183,194	)
Accumulated other comprehensive income		215			113
Total Abraxas Petroleum stockholders’ equity (deficit)		(4,207	)		4,658
Non-controlling interest equity (deficit)		(3,199	)		7,093
Total stockholders’ equity (deficit)		(7,406	)		11,751
Total liabilities and stockholders’ equity (deficit)	$	173,858		$	211,839

(1)	As adjusted for “Non-controlling Interest in Consolidated Financial Statements” in accordance with ASC 810. (See Note 1)

See accompanying notes to condensed consolidated financial statements (unaudited)

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Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008 (1)			2009			2008 (1)
Revenue:
Oil and gas production revenues	$	13,215		$	28,910		$	35,930		$	84,856
Rig revenues		192			333			692			968
Other		2			3			5			15
		13,409			29,246			36,627			85,839
Operating costs and expenses:
Lease operating and production taxes		6,802			7,507			18,656			19,879
Depreciation, depletion, and amortization		4,126			5,806			13,120			16,904
Rig operations		178			241			577			644
General and administrative (including stock-based compensation of $264, $400, $860 and $1,297)		1,746			1,767			5,476			5,439
		12,852			15,321			37,829			42,866
Operating income (loss)		557			13,925			(1,202	)		42,973

Other (income) expense:
Interest income		(2	)		(47	)		(13	)		(174	)
Interest expense		3,276			2,720			8,883			7,858
Financing fees		—			—			362			—
Amortization of deferred financing fees		213			281			799			748
Loss (gain) on derivatives (unrealized $8,217, $(83,842), $22,676 and $16,751)		4,527			(77,756	)		6,222			30,337
Other		13			350			2,242			1,084
		8,027			(74,452	)		18,495			39,853
Consolidated net income (loss)		(7,470	)		88,377			(19,697	)		3,120
Less: Net (income) loss attributable to non-controlling interest		3,100			(17,622	)		9,745			956
Net income (loss) attributable to Abraxas Petroleum	$	(4,370	)	$	70,755		$	(9,952	)	$	4,076


Net income (loss) per common share – basic	$	(0.09	)	$	1.44		$	(0.20	)	$	0.08

Net income (loss) per common share – diluted	$	(0.09	)	$	1.43		$	(0.20	)	$	0.08

(1)	As adjusted for “Non-controlling Interest in Consolidated Financial Statements” in accordance with ASC 810. (See Note 1)

See accompanying notes to condensed consolidated financial statements (unaudited)

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Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2009			2008(1)
Operating Activities
Net income (loss)	$	(19,697	)	$	3,120
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Change in derivative fair value		20,411			14,877
Monetization of derivative contracts		26,736			—
Depreciation, depletion, and amortization		13,120			16,904
Amortization of deferred financing fees		799			748
Accretion of future site restoration		420			426
Stock-based compensation		860			1,297
Other non-cash expenses		141			63
Registration fees previously capitalized		2,210			—
Changes in operating assets and liabilities:
Accounts receivable		1,373			(9,554	)
Other		(1,485	)		(125	)
Accounts payable and accrued expenses		(3,521	)		16,621
Net cash provided by operating activities		41,367			44,377

Investing Activities
Capital expenditures, including purchases and development of properties		(12,214	)		(173,568	)
Proceeds from the sale of oil and gas properties		—			753
Net cash used in investing activities		(12,214	)		(172,815	)

Financing Activities
Proceeds from long-term borrowings		6,137			124,751
Payments on long-term borrowings		(30,702	)		—
Deferred financing fees		(3,289	)		(1,615	)
Proceeds from exercise of stock options		77			61
Partnership distributions to minority interest		(2,257	)		(7,622	)
Other		(569	)		—
Net cash provided by (used in) financing activities		(30,603	)		115,575
Decrease in cash		(1,450	)		(12,863	)
Cash, at beginning of period		1,924			18,936
Cash, at end of period	$	474		$	6,073

Supplemental disclosure of cash flow information:
Interest paid	$	8,463		$	7,470

(1) As adjusted for “Non-controlling Interest in Consolidated Financial Statements” in accordance with ASC 810. (See Note 1)

See accompanying notes to condensed consolidated financial statements (unaudited)

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Abraxas Petroleum Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(tabular amounts in thousands, except per share data)

Note 1. Basis of Presentation

The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K filed for the year ended December 31, 2008. Such policies have been continued without change. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All 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. 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 periods ended September 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.

Consolidation Principles

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.

On June 30, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Abraxas Merger Sub, LLC, which we refer to as Merger Sub, with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, which we refer to as the Effective Time, each common unit of Abraxas Energy Partners not owned by Abraxas Petroleum and its subsidiaries was converted into the right to receive 4.25 shares of Abraxas Petroleum common stock. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of Abraxas Energy Partners under the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan, or LTIP. See Note 2. Recent Events.

The Company consolidates based on the guidance of Accounting Standards Codification (“ASC”) 810. ASC 810 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

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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 ASC 810 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 ASC 810.

In accordance with generally accepted accounting principles in effect prior to the adoption of ASC 810, which codifies 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. For the year ended December 31, 2008, primarily as a result of the ceiling test impairment of the Partnership’s 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.

ASC 815, Determining Whether an Instrument (or Embedded Feature) is indexed to an Entity’s Own Stock. ASC 815 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. This standard 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 ASC 815-10-15 scope exception. The adoption of this standard has not had a significant impact on the Company’s consolidated financial position, results of operations or cash flows.

The following table illustrates the changes in stockholders’ equity (deficit):

				Abraxas Petroleum Corporation Stockholders’ Equity (Deficit) (in thousands)
	Comprehensive Income			Common Stock		Additional Paid-in Capital		Accumulated Deficit			Accumulated Other Comprehensive Income		Parent Equity (Deficit)			Non- Controll-ing Interest Equity (Deficit)
December 31, 2008	$	—		$	496	$	187,243	$	(183,194	)	$	113	$	4,658		$	7,093
Comprehensive income:
Net loss		(19,697	)		—		—		(9,952	)		—		(9,952	)		(9,745	)
Unrealized gain on securities		102			—		—		—			102		102			—
Equity based compensation		—			1		766		—			—		767			69
Partnership distributions		—			—		—		—			—		—			(2,257	)
Registration fees		—			—		—		—			—		—			1,385
Shares issued for compensation		—			—		54		—			—		54			—
Options exercised		—			1		78		—			—		79			—
Other		—			1		84		—			—		85			256
September 30, 2009	$	(19,595	)	$	499	$	188,225	$	(193,146	)	$	215	$	(4,207	)	$	(3,199	)

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.

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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 carrying value at September 30, 2009 approximated the fair value.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles 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 nine months ended September 30, 2009, the Company incurred $203,000 and $653,000, respectively, in equity-based compensation relating to stock options.

The following table summarizes the stock option activities for the nine months ended September 30, 2009. (in thousands, except per share data)

	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		967		$	0.99	$	0.70		679
Exercised		(95	)	$	0.82	$	0.60		(57	)
Expired or canceled		(75	)	$	4.01	$	2.13		(160	)
Outstanding, September 30, 2009		3,187		$	2.29	$	1.34	$	4,292

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		81.63	%
Risk free interest rate		2.35	%
Expected life		6.07
Fair value of options granted (in thousands)	$	679
Weighted average grant date fair value of options granted per share	$	0.70

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

	September 30,		December 31,
	2009		2008
Options exercisable (in thousands)		2,113		1,963

As of September 30, 2009, there was approximately $867,000 of unamortized compensation expense related to outstanding options that will be recognized in 2009 through 2013.

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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 nine months ended September 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		42,000			1.38
Vested/Released		(40,648	)		3.60
Forfeited		(1,712	)		4.24
Unvested September 30, 2009		163,920		$	2.78

For the three and nine months ended September 30, 2009, the Company incurred $38,000 and $113,000, respectively, 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 nine months ended September 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		(300	)		7.23
Unvested September 30, 2009		51,700		$	7.23

For the three and nine months ended September 30, 2009, the Partnership incurred $23,000 and $70,000, respectively, in equity-based compensation expense relating to restricted units. In connection with the closing of the Merger, the restricted unit awards were converted into restricted stock awards of the Company. See Note 2. Recent Events

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.

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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 nine months ended September 30, 2009, the Partnership incurred $0 and $25,000, respectively, in equity-based compensation expense relating to phantom units. In connection with the closing of the Merger, the phantom unit awards were converted into restricted stock awards of the Company. See Note 2. Recent Events

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 September 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 September 30, 2009, our current liabilities of approximately $25.6 million exceeded our current assets of $8.0 million resulting in a working capital deficit of $17.6 million. This compares to a working capital deficit of approximately $26.0 million at December 31, 2008. Current liabilities at September 30, 2009 primarily consisted of the current portion of long-term debt of $8.1 million, the current portion of derivative liabilities of $4.7 million, trade payables of $7.4 million, revenues due third parties of $2.5 million, and other accrued liabilities of $2.8 million. As a result of the Merger which closed on October 5, 2009, the Partnership Credit Facility the Subordinated Credit Agreement and the Credit Facility were refinanced and amended and restated by the new credit facility. See Note 2. Recent Events.

Recently Issued Accounting Pronouncements

In April 2009, the FASB amended authoritative guidance which addresses the initial recognition, measurement and subsequent accounting for assets and liabilities arising from contingencies in a business combination, and requires that such assets acquired or liabilities assumed be initially recognized at fair value at the acquisition date if fair value can be determined during the measurement period. If the fair value as of the acquisition date cannot be determined, the asset acquired or liability assumed arising from a contingency is recognized only if certain criteria are met. This guidance also requires that a systematic and rational basis for subsequently measuring and accounting for the assets or liabilities be developed depending on their nature. This guidance is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is during or after December 15, 2008. The Company does not anticipate the adoption of this guidance to have a material impact on its future consolidated financial statements, absent any material business combinations.

In May 2009, the FASB issued authoritative guidance establishing general standards of accounting and disclosure for events that occur subsequent to the balance sheet date but before financial statements are issued or are available to be issued, which the Company adopted on a prospective basis beginning April 1, 2009. The guidance requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for selecting that date. The Company has evaluated subsequent events through the time of filing these financial statements with the SEC on November 9, 2009. The events which occurred since September 30, 2009 have been disclosed on Note 2. Recent Events.

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In June 2009, the FASB issued authoritative guidance establishing the Hierarchy of Generally Accepted Accounting Principles. The guidance provides for the FASB Accounting Standards Codification (the “Codification”) to become the single official source of authoritative, nongovernmental GAAP. The Codification did not change GAAP but reorganizes the literature. The Company adopted the guidance for the interim period ended September 30, 2009. The application of this guidance did not have a material impact on the Company’s consolidated financial statements.

In August 2009, the FASB issued authoritative guidance that provides clarification for circumstances in which a quoted price in an active market for an identical liability is not available. The guidance is intended to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. The guidance is effective for the first interim reporting period beginning after issuance. The Company adopted the guidance for the interim period ended September 30, 2009. The application of this guidance did not have a material impact on the Company’s consolidated 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

On June 30, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Merger Sub with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, which we refer to as the Effective Time, each common unit of Abraxas Energy Partners not owned by Abraxas Petroleum and its subsidiaries was converted into the right to receive 4.25 shares of Abraxas Petroleum common stock. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of Abraxas Energy Partners under the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan, or LTIP.

New Credit Facility

Simultaneous with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the new credit facility. In connection with the Merger, we refinanced and amended and restated the Partnership Credit Facility, the Subordinated Credit Agreement and the Credit Facility and we borrowed approximately $145.0 million under the new credit facility, of which $135.0 million was borrowed under the revolving portion of the new credit facility and $10.0 million was borrowed under the term loan portion of the new credit facility.

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market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base of $145.0 million was determined based upon our reserve report dated June 1, 2009. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the revolving portion of the new 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 plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization of the borrowing base. At November 6, 2009, the interest rate on the revolving portion of the new credit facility was 5.75%.

We also borrowed $10.0 million under the term loan portion of the new credit facility at the closing of the Merger. Outstanding amounts under the term loan portion of the new 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 plus, in each case, (b) 4.75%, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 5.75%. At November 6, 2009, the interest rate on the term loan portion of the new credit facility was 7.75%. The term loan portion of the new credit facility is subject to amortization beginning on January 31, 2010. The first amortization installment of $1.0 million is due on January 31, 2010 and the second amortization installment of $3.0 million is due on March 31, 2010; thereafter, a quarterly amortization installment of $2.0 million is due at the end of each quarter until the term loan is repaid. It is anticipated that the term loan will be repaid on or before December 31, 2010, after which, it may not be redrawn.

Subject to earlier termination rights and events of default, the stated maturity date of the new credit facility is October 5, 2012. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate the new credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the new credit facility in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries (other than Canadian Abraxas Petroleum Corporation) has guaranteed our obligations under the new credit facility on a senior secured basis. Obligations under the new credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets.

Under the new credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter (beginning September 30, 2009) of not less than 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter (beginning September 30, 2009), of not less than 2.50 to 1.00. We are also required to maintain a total debt to EBITDAX ratio as of the last day of each quarter of not more than 4.50 to 1.00 for the quarter ending September 30, 2009 through the quarter ending September 30, 2010, and not more than 4.00 to 1.00 thereafter. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with or at the request of a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of SFAS 133 (which relates to derivative instruments and hedging activities and is now referred to as ASC 815) and SFAS 143 (which relates to asset retirement obligations and is now referred to as ASC 410-20) and current liabilities exclude 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 defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date after giving pro forma effect to the Merger. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, 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 and is now referred to as ASC 718), SFAS 133 and SFAS 143 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts or upon the termination of any hedge contract minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date after giving pro forma effect to the Merger. For the purposes of

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this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, and obligations with respect to surety bonds and hedge arrangements.

The new credit facility also required that we enter into hedging arrangements for specified volumes, which equate to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2012 and 70% for 2013. We satisfied this requirement by assuming all of the Partnership’s derivative contracts in connection with the Merger. See Note 7. Hedging Program and Derivatives.

The following table sets forth our derivative contract position as of November 6, 2009:

		Fixed Price Swap
		OIL				GAS
Contract Periods		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 addition to the foregoing and other customary covenants, the new credit facility contains a number of covenants that, among other things, restrict our ability to:

·	incur or guarantee additional indebtedness;

·	transfer or sell assets;

·	create liens on assets;

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

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

·	permit a change of control.

The new 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.

Voting, Registration Rights & Lock-Up Agreement

In connection with the Merger, Abraxas Petroleum agreed within 120 days of the Effective Time, to file a registration statement relating to the resale of the shares of Abraxas Petroleum common stock issued in the Merger, which we refer to as the Registration Statement, pursuant to the Securities Act of 1933, as amended, and to use commercially reasonable efforts to cause the Registration Statement to become effective and to keep the Registration Statement effective until the earlier of (A) January 3, 2013 and (B) the date that all shares of Abraxas Petroleum common stock covered by the prospectus have been sold or otherwise transferred pursuant to a registration statement or otherwise. As a result of Abraxas’ obligations in connection with the Merger, Abraxas filed a Registration Statement for the resale of a total of 25,234,467 shares of its common stock on October 19, 2009 and the Securities and Exchange Commission declared the Registration Statement effective on November 3, 2009.

In connection with the Merger, the former limited partners of Abraxas Energy Partners who are party to a Voting, Registration Rights & Lock-Up Agreement (who beneficially own a total of 24,796,879 of the 26,174,061 shares of Abraxas Petroleum common stock issued in the Merger) agreed not to offer for sale, sell, pledge, or otherwise dispose of the Abraxas Petroleum common stock received in the Merger for the 90-day

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period immediately following the Effective Time, which we refer to as the Lock-Up Period. Upon the expiration of the Lock-Up Period, one-third of the Abraxas Petroleum common stock held by these former Abraxas Energy Partners unitholders will be unrestricted and freely-tradable, subject to applicable securities laws. From and after the date which is 12 months after the end of the Lock-Up Period, an additional one-third (or a total of two-thirds) of the Abraxas Petroleum common stock held by these former Abraxas Energy Partners unitholders will become unrestricted and freely-tradable and after the expiration of a total of 24 months following the end of the Lock-Up Period, all remaining shares of the Abraxas Petroleum common stock held by these former Abraxas Energy Partners unitholders will become unrestricted and freely-tradable.

Note 3. Acquisition

On January 31, 2008, Abraxas Operating, 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 for a purchase price of approximately $126.0 million. The properties are primarily located in the Rockies and Mid-Continent regions of the United States.

Simultaneously, Abraxas Petroleum announced that it had completed the acquisition of certain oil and gas properties from St. Mary 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
	Nine months ended September 30, 2008
	(in thousands)
Revenue	$	88,501
Net Income		6,198
Earnings per share - basic		0.125

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 nine month periods ended September 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 ASC 740-10. ASC 740-10 did not have any effect on the Company’s financial position or results of operations for the nine months ended September 30, 2009 and 2008. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 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:

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	September 30, 2009			December 31, 2008
	(in thousands)
Partnership credit facility	$	95,000		$	125,600
Partnership subordinated credit agreement		40,213			40,000
Senior secured credit facility		5,924			—
Real estate lien note		5,267			5,369
		146,404			170,969
Less current maturities		(8,140	)		(40,134	)
	$	138,264		$	130,835

Abraxas Senior Secured Credit Facility

On June 27, 2007, Abraxas entered into a senior secured revolving credit facility, which we refer to as the Credit Facility, which was amended on February 4, 2009, May 13, 2009 and August 7, 2009. The Credit Facility was refinanced and amended and restated by the new credit facility. See Note 2. Recent Events.

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 was refinanced and amended and restated by the new credit facility. See Note 2. Recent Events.

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, July 22, 2009, August 13, 2009 and August 31, 2009, which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement was refinanced and amended and restated by the new credit facility. See Note 2. Recent Events.

New Credit Facility

On October 5, 2009, in connection with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the new credit facility. In connection with the Merger, we refinanced and amended and restated the Partnership Credit Facility, the Subordinated Credit Agreement and the Credit Facility and we borrowed approximately $145.0 million under the new credit facility, of which $135.0 million was borrowed under the revolving portion of the new credit facility and $10.0 million was borrowed under the term loan portion of the new credit facility.

The revolving portion of the new credit facility has a maximum commitment of $300.0 million and availability under the revolving portion of the new credit facility will be subject to a borrowing base. The borrowing base under the new credit facility is currently $145.0 million and will be 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 will be 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, will be able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we will be able to request one redetermination during any six-month period between scheduled redeterminations. The lenders will also be able to make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base of $145.0 million was determined based upon our reserve report dated June 1, 2009. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the revolving portion of the new 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 plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization

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of the borrowing base. At November 6, 2009, the interest rate on the revolving portion of the new credit facility was 5.75%.

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The following table sets forth our derivative contract position as of November 6, 2009:

		Fixed Price Swap
		OIL				GAS
Contract Periods		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 addition to the foregoing and other customary covenants, the new credit facility contains a number of covenants that, among other things, restrict our ability to:

·	incur or guarantee additional indebtedness;

·	transfer or sell assets;

·	create liens on assets;

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

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

·	permit a change of control.

We were in compliance with all covenants as of September 30, 2009. As of September 30, 2009, the current ratio was 1.38 to 1.00, the interest coverage ratio was 5.15 to 1.00 and the total debt to EBITDAX ratio was 2.2 to 1.00, after giving pro forma effect to the Merger.

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

Note 6. Earnings (Loss) Per Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
	(In thousands, except per share data)
Numerator:
Net income (loss) available to common stockholders	$	(4,370	)	$	70,755	$	(9,952	)	$	4,076

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Denominator:
Denominator for basic earnings (loss) per share -
Weighted-average shares		49,672			49,043		49,600			48,955

Effect of dilutive securities:
Stock options and warrants		—			355		—			454

Dilutive potential common shares
Denominator for diluted earnings (loss) per share -
Weighted-average shares and assumed conversions		49,672			49,398		49,600			49,409

Net earnings (loss) per common share – basic	$	(0.09	)	$	1.44	$	(0.20	)	$	0.08

Net earnings (loss) per common share – diluted	$	(0.09	)	$	1.43	$	(0.20	)	$	0.08

For the three and nine months ended September 30, 2009, 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 405,052 and 338,043 shares for the three and nine months ended September 30, 2009, respectively.

Note 7. Hedging Program and Derivatives

The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivate instruments to qualify for hedge accounting rules as prescribed by ASC 815. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead record their fair value on the balance sheet with adjustments to the carrying value of the instruments being recognized as a gain or loss on derivative contracts in the current period.

Under the terms of the Partnership Credit Facility, Abraxas Energy Partners entered into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 and 60% for the year 2012. 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 commodity swap settlement 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 Company and the Partnership entered into new commodity swaps. The following table sets forth our consolidated weighted average derivative contract position as of November 6, 2009:

		Fixed-Price Swaps
		Oil				Gas
Contract Periods		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

At September 30, 2009, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $8.5 million.

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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 September 30, 2009 was a liability of approximately $2.4 million.

As a result of the Merger, all of the Partnership’s derivative contracts were assumed by Abraxas Petroleum as required by the new credit facility.

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

	September 30, 2009			December 31, 2008
	Balance Sheet Location	Fair Value (thousands)		Balance Sheet Location	Fair Value (thousands)
NYMEX-based fixed price derivative contracts	Derivative asset - current	$	459	Derivative asset - current	$	22,832
NYMEX-based fixed price derivative contracts	Derivative asset – long-term	$	426	Derivative asset – long-term	$	16,394
NYMEX-based fixed price derivative contracts	Derivative liability - current	$	2,275	—		—
NYMEX-based fixed price derivative contracts	Derivative liability – Long-term	$	7,096	—		—
Interest rate swap	Derivative liability - current	$	2,435	Derivative liability - current	$	3,000

Gains and losses from derivative activities are reflected as “Loss (gain) on derivatives” in the accompanying Condensed Consolidated Statement of Operations.

Note 8. Financial Instruments

The Company holds certain financial assets which are required to be measured at fair value on a recurring basis in accordance with ASC 820-10. Accounting guidance establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The following table presents the Company’s fair value hierarchy for financial assets measured as of September 30, 2009: (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 September 30, 2009
Assets
Investment in common stock	$	215	$	—	$	—	$	215
NYMEX-based fixed price derivative contracts		—		885		—		885
Total assets	$	215	$	885	$	—	$	1,100

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Liabilities
NYMEX-based fixed price derivative contracts		—		9,372		—		9,372
Interest Rate Swap	$	—	$	—	$	2,434	$	2,434
Total Liabilities	$	—	$	9,372	$	2,434	$	11,806

The Company has an investment in a former subsidiary which merged with Insignia Energy Ltd. on July 24, 2009 which consists 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 September 30, 2009 in US dollars. Accordingly this investment is characterized as Level 1.

The Company’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 was $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 recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the three and nine months ended September 30, 2009 is as follows: (in thousands)

	Derivative Assets and (Liabilities) - net
	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
Balance beginning of period	$	(2,697	)	$	(3,000	)
Total realized and unrealized losses included in change in net liability		(413	)		(1,283	)
Settlements during the period		676			1,849
Ending balance September 30, 2009	$	(2,434	)		(2,434	)

Note 9. Contingencies - Litigation

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At September 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.

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

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K filed for the year ended December 31, 2008 filed with the Securities and Exchange Commission on February 24, 2009. The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership,” and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 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.

On January 1, 2009, the Company adopted Accounting Standards Codification 810, previously Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51” (“ASC 810”). ASC 810 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 ASC 810 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.

In June 2008, the FASB ratified ASC 815, Determining Whether an Instrument (or Embedded Feature) is indexed to an Entity’s Own Stock. ASC 815 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. This 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 ASC 815-10-15 scope exception. The adoption of this standard has not had a significant impact on the Company’s consolidated financial position, results of operations or cash flows.

General

We are an independent energy company primarily engaged in the development and production of oil and gas. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of oil fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys, horizontal drilling and modern completion techniques. 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. These anticipated development activities are subject to adequate cash flow from operations and availability under our new credit facility. 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 for the three and nine months ended September 30, 2009 and we cannot assure you that we can achieve positive operating income and net income in the

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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 rose to record or near-record levels, however during the third quarter of 2008, and subsequently, there was a significant drop in prices. New York Mercantile Exchange (NYMEX) spot prices for West Texas Intermediate (WTI) crude oil averaged $113.45 per barrel (Bbl) for the nine month period ended September 30, 2008. WTI ended the quarter at $100.64 per barrel. NYMEX Henry Hub spot prices for natural gas averaged $9.68 per million British thermal units (MMBtu) during first nine months of 2008 and ended the quarter at $7.21. During the first nine months of 2009, prices of oil and gas declined significantly from the levels experienced during the first nine months of 2008. During the first nine months of 2009, WTI averaged $57.18 per Bbl and Henry Hub averaged $3.80 per MMBtu. Prices closed the quarter at $70.61 per Bbl of oil and $3.38 per MMBtu of gas and continue to be significantly lower when compared to the same period of 2008. Subsequent to the end of the third quarter, both oil and gas prices have improved. As of November 6, 2009, WTI and Henry Hub were $ 77.43 per Bbl and $4.60 per MMBtu, respectively. If commodity prices 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 gas 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 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 stockholders’ equity and earnings. The risk that we will be required to write-down the carrying value of our 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 oil and gas prices may have increased the ceiling applicable to the subsequent period.

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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 locations;

adjustments for BTU content and quality; and

gathering, processing and transportation costs.

During the first nine months of 2009, differentials averaged $7.55 per Bbl of oil and $0.78 per Mcf of gas as compared to $5.02 per Bbl of oil and $1.23 per Mcf of gas during the first nine months of 2008. We are realizing greater differentials in oil prices 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 entered into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production from its net estimated proved developed producing reserves through December 31, 2011 and 60% for year 2012. 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 commodity swap settlement 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 Company and the Partnership entered into new commodity swaps. The following table sets forth our consolidated weighted average derivative contract position as of November 6, 2009:

		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

We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

We intend to enter into derivative contracts in the future to reduce the impact of price volatility on our 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. 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.

At September 30, 2009, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $8.5 million. As a result of the Merger, all of the Partnership’s derivative contracts were assumed by Abraxas Petroleum as required by the new credit facility.

Production Volumes. Because our proved reserves 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 92% of the original estimated ultimate recovery of our consolidated proved developed producing reserves as of December 31,

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2008 had been produced. Based on the consolidated reserve information set forth in our reserve estimates as of December 31, 2008, our average annual estimated decline rate for our net proved developed producing reserves is 13% during the first five years, 9% in the next five years, and approximately 8% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and prior property sales. For example, in 2006, we replaced only 7% of the reserves we produced. 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 $12.2 million during the first nine months of 2009 and our capital budget for 2009 is approximately $32.0 million; however, we do not anticipate spending the full $32.0 million. 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. Upon the closing of the Merger on October 5, 2009, the Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement were amended and restated into the new credit facility 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. As of November 6, 2009, we had $10.0 million of availability under the new credit facility.

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. 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 numerous 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. During the five years ended December 31, 2008, we drilled or participated in 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, we replaced only 7% of the reserves we produced. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations, and the amount that we will be able to borrow under the new credit facility will also decline. In addition, approximately 46% of our 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. At September 30, 2009, we and the Partnership had a total of $141.1 million outstanding under the Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement. Upon the closing of the Merger on October 5, 2009, the Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement were refinanced and amended and restated by the new credit facility. We borrowed $145.0 million under the new credit facility in connection with the Merger and at October 5, 2009 had availability of $10.0 million. 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

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August 12, 2010. This interest rate swap was amended in February 2009 lowering the Partnership’s fixed rate to 2.95%. The interest rate swap was assumed by us on October 29, 2009.

Recent Events

Merger

On June 30, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Merger Sub with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, which we refer to as the Effective Time, each common unit of Abraxas Energy Partners not owned by Abraxas Petroleum and its subsidiaries was converted into the right to receive 4.25 shares of Abraxas Petroleum common stock. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of Abraxas Energy Partners under the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan, or LTIP.

New Credit Facility

Simultaneous with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the new credit facility. In connection with the Merger, we refinanced and amended and restated the Partnership Credit Facility, the Subordinated Credit Agreement and the Credit Facility and we borrowed approximately $145.0 million under the new credit facility, of which $135.0 million was borrowed under the revolving portion of the new credit facility. For more information on the new credit facility, please see “—Liquidity and Capital Resources—Long-Term Indebtedness.”

Voting, Registration Rights & Lock-Up Agreement

In connection with the Merger, the former limited partners of Abraxas Energy Partners party to a Voting, Registration Rights & Lock-Up Agreement (who beneficially own a total of 24,796,879 of the 26,174,061 shares of Abraxas Petroleum common stock issued in the Merger) agreed not to offer for sale, sell, pledge, or otherwise dispose of the Abraxas Petroleum common stock received in the Merger for the 90-day period immediately following the Effective Time, which we refer to as the Lock-Up Period. Upon the expiration of the Lock-Up Period, one-third of the Abraxas Petroleum common stock held by these former Abraxas Energy Partners unitholders will be unrestricted and freely-tradable, subject to applicable securities laws. From and after the date which is 12 months after the end of the Lock-Up Period, an additional one-third (or a total of two-thirds) of the Abraxas Petroleum common stock held by these former Abraxas Energy Partners unitholders will become unrestricted and freely-tradable and after the expiration of a total of 24 months following the end of the Lock-Up Period, all remaining shares of the Abraxas Petroleum common stock held by these former Abraxas Energy Partners unitholders will become unrestricted and freely-tradable.

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Results of Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2009		2008		2009			2008 (2)
Operating Revenue (1):
Crude Oil Sales	$	8,837	$	15,469	$	21,506		$	43,737
Natural Gas Sales		4,378		13,441		14,424			41,119
Rig Operations		192		333		692			968
Other		2		3		5			15
	$	13,409	$	29,246	$	36,627		$	85,839

Operating income (loss)	$	557	$	13,925	$	(1,202	)	$	42,973
Crude Oil Production (MBbls)		146		140		436			403
Natural Gas Production (MMcfs)		1,572		1,663		4,777			4,865
Average Crude Oil Sales Price ($/Bbl) (1)	$	60.70	$	110.66	$	49.37		$	108.43
Average Natural Gas Sales Price ($/Mcf) (1)	$	2.79	$	8.08	$	3.02		$	8.45

(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 September 2008.

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

Operating Revenue. During the three months ended September 30, 2009, operating revenue from oil and gas sales decreased by $15.7 million to $13.2 million compared to $28.9 million during the same period of 2008. The decrease in revenue was primarily due to significantly lower commodity prices during the third quarter of 2009 as compared to the same period of 2008. The decrease in commodity prices had a negative impact of $15.8 million to revenue. An increase in oil production contributed $353,000 to revenue which was partially offset by a decrease in gas production, which had a negative impact on revenue of $254,000. Oil production volumes increased from 140 MBbls for the quarter ended September 30, 2008 to 146 MBbls for the same period of 2009. The increase in oil production was primarily from new wells brought on production during 2009 partially offset by natural field declines. Gas production volumes decreased from 1,663 MMcf for the three months ended September 30, 2008 to 1,572 MMcf. The decrease in gas production was primarily due to natural field declines partially offset by new production.

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

$60.70 per Bbl of crude oil, and

$2.79 per Mcf of natural gas

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

$110.66 per Bbl of crude oil, and

$8.08 per Mcf of natural gas

Lease Operating Expenses (“LOE”). LOE for the three months ended September 30, 2009 decreased to $6.8 million compared to $7.5 million for the same period of 2008. The decrease in LOE was primarily due to a decrease in production taxes as a result of lower commodity prices. LOE per BOE for the three

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months ended September 30, 2009 was $16.69 per BOE compared to $18.01 for the same period of 2008, primarily due to lower overall costs.

General and Administrative (“G&A”) Expenses. G&A expenses, excluding stock-based compensation, increased to $1.5 million for the quarter ended September 30, 2009 from $1.4 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 per BOE was $3.64 for the third quarter of 2009 compared to $3.28 for the same period of 2008. The per BOE increase was attributable to the higher G&A expense as well as lower production volumes during the third quarter of 2009 as compared to the same period of 2008.

Equity-based Compensation. Options granted to employees and directors 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 three months ended September 30, 2009 and 2008, equity-based compensation was approximately $264,000 and $400,000 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 (“DD&A”) Expenses. DD&A expense decreased to $4.1 million for the three months ended September 30, 2009 as compared to $5.8 million for the same period of 2008. The decrease in DD&A was primarily the result of an increase in the reserve base for the quarter ended September 30, 2009 as compared to 2008 as well as a decrease in production. Our DD&A per BOE for the three months ended September 30, 2009 was $10.12 per BOE compared to $13.92 per BOE in 2008.

Interest Expense. Interest expense increased to $3.3 million for the third quarter of 2009 compared to $2.8 million for the same period of 2008. The increase in interest expense was primarily due to higher interest rates during the third quarter of 2009 as compared to 2008.

Income (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 ASC 815; therefore, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The estimated unearned value of our derivative contracts is a net liability of approximately $10.9 million as of September 30, 2009. For the quarter ended September 30, 2009, we realized a gain on our derivative contracts of $3.7 million. For the quarter ended September 30, 2009, we incurred an unrealized loss on our derivative contracts of $8.2 million. The realized gain on the commodity swaps of $4.4 million for the quarter ended September 30, 2009 was the result of the commodity swap settlement for July 2009 and the monetization of certain derivative contracts on July 29, 2009 and the realized loss on the interest rate swap of $680,000 was the result of floating interest rates being lower than our fixed contract rates. The unrealized loss of $8.4 million on the commodity swaps was due to the contract prices of the new derivative contracts being lower than the market prices at the end of the quarter. The unrealized gain of $268,000 on the interest rate swap was due to a change in floating interest rates from the prior period end.

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.

Income taxes. There is no current or deferred income tax expense or benefit due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits.

Comparison of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2008

Operating Revenue. During the nine months ended September 30, 2008, operating revenue from oil and gas sales decreased from $84.9 million to $35.9 million in the nine months ended September 30, 2009. The decrease in revenue was primarily due to lower commodity prices during the nine months ended September 30, 2009 as compared to the same period of 2008. Lower commodity prices had a negative impact of $50.2 million to revenue for the nine months ended September 30, 2009, while increased oil production contributed $1.6 million to revenue which was partially offset by a slight decline in gas production.

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Oil production volumes increased from 403 MBbls during the nine months ended September 30, 2008 to 436 MBbls for the same period of 2009. The increase in oil production volumes was primarily due to wells put on production during the first nine months of 2009. New wells put on production contributed 18 MBbls during the nine months ended September 30, 2009. In addition, production from properties acquired in the St. Mary acquisition in January 2008 contributed a full nine months of production to the nine month period ended September 30, 2009 compared to eight months for the nine month period ended September 30, 2008. Production from these properties was 254 MBbls for the period February through September 2008, compared to 265 MBbls for the nine months ended September 30, 2009.

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

$49.37 per Bbl of crude oil, and

$3.02 per Mcf of natural gas

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

$108.43 per Bbl of crude oil, and

$8.45 per Mcf of natural gas

Lease Operating Expenses. LOE for the nine months ended September 30, 2009 decreased to $18.7 million from $19.9 million for the same period of 2008. The decrease in LOE was primarily due to a decrease in production taxes as a result of lower commodity prices realized during the nine months ended September 30, 2009 as compared to the same period of 2008. LOE per BOE for the nine months ended September 30, 2009 was $15.15 per BOE compared to $16.37 for the same period of 2008.

G&A Expenses. G&A expenses, excluding stock-based compensation, increased to $4.6 million for the nine months ended September 30, 2009 from $4.1 million for the same period of 2008. The increase in G&A was primarily due to higher professional and consulting fees in 2009. G&A expense per BOE was $3.75 for the nine months ended September 30, 2009 compared to $3.41 for the same period of 2008.

Equity-based Compensation. Options granted to employees and directors 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 nine months ended September 30, 2009 and 2008, equity-based compensation was approximately $860,000 and $1.3 million, 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.

DD&A Expenses. DD&A expense decreased to $13.1 million for the nine months ended September 30, 2009 from $16.9 million for the same period of 2008. The decrease in DD&A was primarily the result of an increase in the reserve base for the nine months ended September 30, 2009 as compared to 2008. Our DD&A per BOE for the nine months ended September 30, 2009 was $10.65 per BOE compared to $13.92 per BOE in 2008.

Interest Expense. Interest expense increased to $8.9 million for the nine months ended September 30, 2009 compared to $8.2 million for the same period of 2008. The increase in interest expense is due to higher levels of long-term debt during the nine months ended September 30, 2009 as compared to 2008 as well as higher interest rates.

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we realized a gain on our derivative contracts of $16.5 million. For the nine months ended September 30, 2009, we incurred an unrealized loss on our derivative contracts of $22.7 million. The realized gain on the commodity swaps of $18.4 million for the nine months ended September 30, 2009 was the result of commodity swap settlements for January through July 2009 and the monetization of certain derivative contracts on July 29, 2009 and the realized loss on the interest rate swap of $1.9 million was the result of floating interest rates being lower than our fixed contract rates. The unrealized loss of $23.3 million on the commodity swaps was due to the changes in market prices since the prior period end. The unrealized gain of $634,000 on the interest rate swap was due to changes in floating interest rates from the prior period end.

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.

Income taxes. There is no current or deferred income tax expense or benefit due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits.

Recently Issued Accounting Pronouncements

In April 2009, the FASB amended authoritative guidance which addresses the initial recognition, measurement and subsequent accounting for assets and liabilities arising from contingencies in a business combination, and requires that such assets acquired or liabilities assumed be initially recognized at fair value at the acquisition date if fair value can be determined during the measurement period. If the fair value as of the acquisition date cannot be determined, the asset acquired or liability assumed arising from a contingency is recognized only if certain criteria are met. This guidance also requires that a systematic and rational basis for subsequently measuring and accounting for the assets or liabilities be developed depending on their nature. This guidance is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is during or after 2010. The Company does not anticipate the adoption of this guidance to have a material impact on its future consolidated financial statements, absent any material business combinations.

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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.

Historically, Abraxas’ sources of capital had primarily been cash from operating activities, funding under its 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 had been cash from operating activities, borrowings under the Partnership Credit Facility and sales of debt or equity securities if available to it.

Since the closing of the Merger, our principal sources of capital are cash flow from operations, borrowings under our new credit facility, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities.

Working Capital (Deficit). At September 30, 2009, our current liabilities of approximately $25.6 million exceeded our current assets of $8.0 million resulting in a working capital deficit of $17.6 million. This compares to a working capital deficit of approximately $26.0 million at December 31, 2008. Current liabilities at September 30, 2009 primarily consisted of the current portion of long-term debt of $8.1, the current portion of derivative liabilities of $4.7 million, trade payables of $7.4 million, revenues due third parties of $2.5 million, and other accrued liabilities of $2.8 million. The Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement were refinanced and amended and restated into a new credit facility.

Capital expenditures. Capital expenditures during the first nine months of 2009 were $12.2 million compared to $173.6 million during the same period of 2008. The table below sets forth the components of these capital expenditures.

	Nine Months Ended September 30,
	2009			2008
	(in thousands)
Expenditure category:
Acquisitions		$	—		$	137,211
Development			12,021			29,789
Facilities and other			193			6,568
Total		$	12,214		$	173,568

During the nine months ended September 30, 2009, capital expenditures were primarily for the development of our existing properties. For the nine months ended September 30, 2008, capital expenditures were primarily for the acquisition of properties from St. Mary, the development of our existing properties and the acquisition of an office building for our corporate headquarters. Our capital budget for 2009 is $32.0 million; however, we do not anticipate spending the full $32.0 million. These anticipated expenditures are subject to adequate cash flow from operations and availability under our 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.

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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:

	Nine Months Ended September 30,
	2009				2008
	(in thousands)
Net cash provided by operating activities		$	41,367			$	44,377
Net cash used in investing activities			(12,214	)			(172,815	)
Net cash provided by (used in) financing activities			(30,603	)			115,575
Total		$	(1,450	)		$	(12,863	)

Operating activities during the nine months ended September 30, 2009 provided $41.4 million in cash compared to $44.4 million in the same period in 2008. Net loss plus non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds. Financing activities used $30.6 million for the nine months ended September 30, 2009 compared to providing $115.6 million for the same period of 2008. Funds used during the nine months ended September 30, 2009 were used primarily for the payment of long-term debt. Funds provided in 2008 were primarily proceeds from the Partnership Credit Facility and the Subordinated Credit Agreement in connection with the St. Mary property acquisition. Investing activities used $12.2 million during the nine months ended September 30, 2009 compared to $172.8 million for the same period of 2008. Expenditures during the nine months ended September 30, 2009 were primarily for the development of our existing properties. Expenditures during the nine months ended September 30, 2008 were primarily for the acquisition of properties from St. Mary Land and Exploration as well as the development of our properties.

Future Capital Resources. Since the closing of the Merger, our principal sources of capital are cash flow from operations, borrowings under our new credit facility, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or 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 third quarter of 2009 and while gas prices have strengthened somewhat, they remain 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, we replaced only 7% of the reserves we produced. 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 and the amount that we are able to borrow under our new credit facility will also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 46% of our total estimated proved reserves at December 31, 2008 were classified as undeveloped.

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We 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 September 30, 2009:

	Payments due in twelve month periods ending:
Contractual Obligations (in thousands)	Total		September 30, 2010		September 30, 2011-2012		September 30, 2013-2014		Thereafter
Long-Term Debt (1)	$	146,404	$	46,276	$	95,310	$	353	$	4,465
Interest on long-term debt (2)		14,178		5,710		7,654		601		213
Lease obligations (3)		119		62		57
Total	$	160,701	$	52,048	$	103,021	$	954	$	4,678

____________

(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. The payment obligations indicated do not take into account the reclassification of the current maturity of the Credit Facility and the Subordinated Credit Agreement to long-term for balance sheet purposes. As a result of the Merger which closed on October 5, 2009, the Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement were refinanced and amended and restated into a new credit facility. See Note 2. Recent Events.

(2)

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

(3)	Lease on office space in Calgary, Canada, which expires on August 31, 2011.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At September 30, 2009, our reserve for these obligations totaled $10.3 million for which no contractual commitment exists.

Off-Balance Sheet Arrangements. At September 30, 2009, we had no existing off-balance sheet arrangements, as defined under SEC regulations, which 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 September 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 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.

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Long-Term Indebtedness

Long-term debt consisted of the following:


	September 30, 2009			December 31, 2008
Partnership credit facility	$	95,000		$	125,600
Partnership subordinated credit agreement		40,213			40,000
Senior secured credit facility		5,924			—
Real estate lien note		5,267			5,369
		146,404			170,969
Less current maturities		(8,140	)		(40,134	)
	$	138,264		$	130,835

Abraxas Senior Secured Credit Facility

Amended and Restated Partnership Credit Facility

Subordinated Credit Agreement

New Credit Facility

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and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base of $145.0 million was determined based upon our reserve report dated June 1, 2009. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the revolving portion of the new 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 plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization of the borrowing base. At November 6, 2009, the interest rate on the revolving portion of the new credit facility was 5.75%.

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The following table sets forth our derivative contract position as of November 6, 2009:

		Fixed Price Swap
		OIL				GAS
Contract Periods		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 addition to the foregoing and other customary covenants, the new credit facility contains a number of covenants that, among other things, restrict our ability to:

·	incur or guarantee additional indebtedness;

·	transfer or sell assets;

·	create liens on assets;

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

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

·	permit a change of control.

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

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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 entered 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 derivative contracts for the periods 2009 through 2011 were monetized for $26.7 million and together with the July 2009 commodity swap settlement of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. Simultaneously, the Partnership entered into new commodity swaps on approximately 85% of our estimated oil and gas production from our net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013. As a result of the Merger, all of the Partnership’s derivative contracts were assumed by Abraxas Petroleum

The following table sets forth our consolidated weighted average derivative contract position as of November 6, 2009:

		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

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 nine months ended September 30, 2009, Abraxas Energy incurred a realized gain of approximately $16.2 million and an unrealized loss of approximately $22.7 million on all of our derivative contracts. If the disparity between our new contract prices and market prices continues, 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 our existing derivative contracts, 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, $182.3 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 ACS 740-10. Therefore, we have established a valuation allowance of $60.8 million for deferred tax assets at December 31, 2008.

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We account for uncertain tax positions under provisions of ASC 740-10. ASC 740-10 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 nine month periods ended September 30, 2009. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 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.

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 nine months ended September 30, 2009, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $3.7 million for the nine months ended September 30, 2009, however, due to the derivative contracts that we have in place, it is unlikely that a 10% decline in commodity prices from their current levels would significantly impact our operating revenue, cash flow and net income.

Derivative Instrument Sensitivity

We account for our derivative instruments in accordance with ACS 815, 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).

On July 29, 2009, our commodity based 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 commodity swap settlement, 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. As a result of the Merger, all of the Partnership’s derivative contracts were assumed by Abraxas Petroleum.

The following table sets forth our consolidated weighted average derivative contract position as of November 6, 2009:

		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 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 fixed rate from 3.367% to 2.95%. The notional amount of the interest rate swap is $100.0 million.

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At September 30, 2009, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $8.5 million and the aggregate fair market value of our interest rate swap was a liability of approximately $2.4 million.

For the nine months ended September 30, 2009 we recognized a realized gain of $18.4 million and an unrealized loss of $23.3 million on our commodity derivative contracts and we recognized a realized loss of $1.9 million and an unrealized gain of $634,000 on our interest rate swap.

Interest Rate Risk

We are subject to interest rate risk associated with borrowings under the new credit facility. As of the closing of the Merger on October 5, 2009, we have $145.0 million of outstanding indebtedness under the new credit facility. Outstanding amounts ($135.0 million) under the revolving portion of the new 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 plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization of the borrowing base. At November 6, 2009, the interest rate on the revolving portion of the new credit facility was 5.75%. Outstanding amounts ($10.0 million) under the term loan portion of the new 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 plus, in each case, (b) 4.75%, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 5.75%. At November 6, 2009, the interest rate on the term loan portion of the new credit facility was 7.75%. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.5 million 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 fixed rate from 3.367% to 2.95%. The notional amount of the interest rate swap is $100.0 million.

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 September 30, 2009 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

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ABRAXAS PETROLEUM CORPORATION

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

There have been no changes in legal proceedings from that described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, and in Note 9 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 risk factors discussed below and the risk 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 this report and 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.

We incurred substantial new indebtedness in order to close the Merger, which may adversely affect our cash flow and business operations.

In connection with closing the Merger, we incurred a total of $145.0 million of indebtedness under the new credit facility which was used to refinance and amend and restate the Partnership Credit Facility, the Subordinated Credit Agreement and the Credit Facility and pay certain fees and expenses related to the Merger. Immediately prior to the Merger, Abraxas Energy had outstanding indebtedness of $135.0 million and Abraxas Petroleum had outstanding indebtedness of $5.9 million, for a total of $140.9 million, excluding the mortgage on our office building.

Our future indebtedness could have important consequences to us, including:

·	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

·	covenants contained in our new credit facility and future debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

·	we may need a substantial portion of our cash flow from operations to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and

·	our level of debt will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally, than our competitors with less debt.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying acquisitions and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional debt or equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

A breach of the terms and conditions of the new credit facility, including the inability to comply with the required financial covenants, could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders would be entitled to terminate any commitment to make further extensions of credit under the new credit facility and to accelerate the repayment of

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amounts outstanding (including accrued and unpaid interest and fees). Upon a default under the new credit facility, the lenders could also foreclose against any collateral securing such obligations, which may be all or substantially all of our assets. If that occurred, we may not be able to continue to operate as a going concern.

Use of our net operating loss carryforwards may be limited.

The use of our net operating loss carryforwards may be limited if an “ownership change” of over 50 percentage points occurs during any three-year period. Based on current estimates, we believe that we have not surpassed this threshold. With respect to any remaining net operating loss carryforwards following the Merger, it is feasible that even a modest change of ownership (including, but not limited to, a shift in common stock ownership by one reasonably large stockholder or any offering of common stock) during the three-year period following the Merger could trigger a significant limitation of the amount of such net operating loss carryforwards available to offset future taxable income.

Additionally, 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 $66.9 million for deferred tax assets at December 31, 2006, $47.2 million at December 31, 2007 and $60.8 million at December 31, 2008.

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

None

Item 3. Defaults Upon Senior Securities.

None

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

None

Item 5. Other Information.

None

Item 6. Exhibits.

(a) Exhibits

Exhibit 31.1 Certification – Robert L.G. Watson, CEO

Exhibit 31.2 Certification – Chris E. Williford, CFO

Exhibit 32.1 Certification pursuant to 18 U.S.C. Section 1350 – Robert L.G. Watson, CEO

Exhibit 32.2 Certification pursuant to 18 U.S.C. Section 1350 – Chris E. Williford, CFO

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ABRAXAS PETROLEUM CORPORATION

SIGNATURES

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

Date: November 9, 2009	By:/s/ Robert L.G. Watson ROBERT L.G. WATSON, President and Chief Executive Officer

Date: November 9, 2009	By:/s/ Chris E. Williford CHRIS E. WILLIFORD, Executive Vice President and Principal Accounting Officer

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