Edgar Filing: ABRAXAS PETROLEUM CORP

axasq32011.htm

UNITED STATES

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, 2011

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 x 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 4, 2011 was 92,214,358 shares.

Forward-Looking Information

We make forward-looking statements throughout this report. Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “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 report 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 success in development, exploitation and exploration activities;

our ability to procure services and equipment for our drilling and completion activities;

the prices we receive for our production and the effectiveness of our hedging activities;

our ability to make planned capital expenditures;

declines in our production of oil and gas;

the availability of capital;

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

price 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; and

other factors discussed elsewhere in this report.

GLOSSARY OF TERMS

Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit. Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

Terms used to describe our interests in wells and acreage:

“Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells.

“Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting reserves.

“Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion.

“Exploratory well” is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be producing in another reservoir, or to extend a known reservoir.

“Gross acres” are the number of acres in which we own a working interest.

“Gross well” is a well in which we own an interest.

“Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross acres is equivalent to 160 net acres).

“Net well” is the sum of fractional ownership working interests in gross wells.

“Productive well” is an exploratory or a development well that is not a dry hole.

“Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

Terms used to assign a present value to or to classify our reserves:

“Proved reserves” are those quantities of oil and gas reserves, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable - from a given date forward, from known reservoirs, and under defined economic conditions, operating methods, and government regulations.

“Proved developed reserves” are those quantities of oil and gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved developed non-producing reserves” are those quantities of oil and gas reserves that are developed behind pipe in an existing well bore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

“Proved undeveloped reserves” are those quantities of oil and gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same reservoir.

“Probable reserves” are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves.

“Possible reserves” are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

“PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”).

“Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation or de-escalation, calculated in accordance with Accounting Standards Codifications (“ASC”) 932, “Disclosures About Oil and Gas Producing Activities.”

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

PART I
FINANCIAL INFORMATION

ITEM 1 -	Financial Statements
	Condensed Consolidated Balance Sheets - September 30, 2011 (unaudited) and December 31, 2010	6
	Condensed Consolidated Statements of Operations – (unaudited) Three and Nine Months Ended September 30, 2011 and 2010	8
	Condensed Consolidated Statements of Cash Flows – (unaudited) Nine Months Ended September 30, 2011 and 2010	9
	Notes to Condensed Consolidated Financial Statements (unaudited)	10

ITEM 2 -	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

ITEM 3 -	Quantitative and Qualitative Disclosures about Market Risk	38

ITEM 4 -	Controls and Procedures	39

PART II
OTHER INFORMATION
ITEM 1 -	Legal Proceedings	40
ITEM 1A-	Risk Factors	40
ITEM 2 -	Unregistered Sales of Equity Securities and Use of Proceeds	40
ITEM 3 -	Defaults Upon Senior Securities	40
ITEM 4 -	[Removed and Reserved]	40
ITEM 5 -	Other Information	40
ITEM 6 -	Exhibits	40
	Signatures	41

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)

	September 30,			December 31,
	2011			2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	14		$	99
Accounts receivable, net:
Joint owners		1,241			5,145
Oil and gas production		7,425			6,958
Other		350			642
		9,016			12,745

Derivative asset – current		8,727			6,941
Assets held for sale		—			8,457
Other current assets		530			396
Total current assets		18,287			28,638

Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved		468,385			434,858
Unproved properties excluded from depletion		8,005			1,085
Other property and equipment		23,435			11,536
Total		499,825			447,479
Less accumulated depreciation, depletion, and amortization		(341,367	)		(330,231	)
Total property and equipment – net		158,458			117,248

Investment in joint venture		26,091			24,027

Deferred financing fees, net		3,720			3,494
Derivative asset – long-term		6,443			8,674
Other assets		796			828
Total assets	$	213,795		$	182,909

See accompanying notes to condensed consolidated financial statements (unaudited)

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands, except share data)

	September 30,			December 31,
	2011			2010
	(Unaudited)
Liabilities and Stockholders’ Equity (Deficit)
Current liabilities:
Accounts payable	$	22,147		$	23,589
Oil and gas production payable		5,136			3,000
Accrued interest		204			277
Other accrued expenses		1,727			779
Derivative liability – current		5,099			9,742
Current maturities of long-term debt		160			152
Total current liabilities		34,473			37,539

Long-term debt, excluding current maturities		101,888			140,940

Derivative liability – long-term		1,849			11,672
Future site restoration		8,188			7,734
Total liabilities		146,398			197,885

Stockholders’ Equity (Deficit)
Preferred stock, par value $.01 per share, authorized 1,000,000 shares; -0- issued and outstanding		—			—
Common stock, par value $.01 per share, authorized 200,000,000 shares;92,161,141 and 76,427,561 issued and outstanding		922			764
Additional paid-in capital		247,995			184,223
Accumulated deficit		(181,205	)		(200,208	)
Accumulated other comprehensive (loss) income		(315	)		245
Total stockholders’ equity (deficit)		67,397			(14,976	)
Total liabilities and stockholders’ equity	$	213,795		$	182,909

See accompanying notes to condensed consolidated financial statements (unaudited)

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenue:
Oil and gas production revenues	$	17,665		$	13,709		$	48,165		$	44,218
Rig revenues		354			259			846			779
Other		1			1			5			7
		18,020			13,969			49,016			45,004
Operating costs and expenses:
Lease operating expenses		5,742			5,266			15,364			14,893
Production taxes		1,549			1,292			4,229			4,519
Depreciation, depletion, and amortization		4,161			3,821			11,371			12,495
Rig operations		282			223			733			613
General and administrative (including stock-based compensation of $430, $358, $1,499 and $1,205)		2,061			2,094			7,153			6,426
		13,795			12,696			38,850			38,946
Operating income		4,225			1,273			10,166			6,058

Other (income) expense:
Interest income		(2	)		(2	)		(6	)		(6	)
Interest expense		983			2,271			3,924			6,857
Amortization of deferred financing fee		245			515			1,515			1,837
Gain on derivative contracts (unrealized $(16,450), $(332), $(13,431) and $(17,968))		(16,641	)		(831	)		(12,394	)		(18,358	)
Equity in (income) loss of joint venture		(546	)		237			(2,064	)		237
Other		101			(61	)		188			(136	)
		(15,860	)		2,129			(8,837	)		(9,569	)
Net income (loss)	$	20,085		$	(856	)	$	19,003		$	15,627

Net income (loss) per common share – basic	$	0.22		$	(0.01	)	$	0.21		$	0.21

Net income (loss) per common share – diluted	$	0.21		$	(0.01	)	$	0.21		$	0.20

See accompanying notes to condensed consolidated financial statements (unaudited)

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2011			2010
Operating Activities
Net income	$	19,003		$	15,627
Adjustments to reconcile net income to net
cash provided by operating activities:
Equity in (income) loss of joint venture		(2,064	)		237
Change in derivative fair value		(14,021	)		(18,936	)
Depreciation, depletion, and amortization		11,371			12,495
Amortization of deferred financing fees		1,515			1,837
Accretion of future site restoration		335			399
Stock-based compensation		1,499			1,205
Other non-cash expenses		—			24
Changes in operating assets and liabilities:
Accounts receivable		3,709			1,984
Other		(150	)		(314	)
Accounts payable and accrued expenses		1,838			(260	)
Net cash provided by operating activities		23,035			14,298

Investing Activities
Capital expenditures, including purchases and development of properties		(53,155	)		(20,362	)
Proceeds from sale of oil and gas properties		8,457			18,063
Net cash used in investing activities		(44,698	)		(2,299	)

Financing Activities
Proceeds from long-term borrowings		24,069			2,000
Payments on long-term borrowings		(63,113	)		(13,604	)
Deferred financing fees		(1,741	)		(169	)
Proceeds from issuance of common stock, net of offering costs		62,428			—
Other		(65	)		(27	)
Net cash provided by (used in) financing activities		21,578			(11,800	)

Effect of exchange rate changes on cash		—			—
(Decrease) increase in cash		(85	)		199
Cash and equivalents, at beginning of period		99			1,861
Cash and equivalents, at end of period	$	14		$	2,060

Supplemental disclosure of cash flow information:
Interest paid	$	3,663		$	6,683

See accompanying notes to condensed consolidated financial statements (unaudited)

Abraxas Petroleum Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(tabular amounts in thousands, except per share data)

Note 1. Basis of Presentation

The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on March 16, 2011, as amended. 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 our 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 SEC. The results of operations and the cash flows for the periods ended September 30, 2011 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, 2010.

Consolidation Principles

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries, including its wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC (“Canadian Abraxas”).

Canadian Abraxas’ assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of stockholders’ equity.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 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.

Stock-based Compensation, Option Plans and Warrants

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 and directors.

The following table summarizes the Company’s stock-based compensation expense related to stock options for the periods presented:

Three Months Ended September 30,				Nine Months Ended September 30,
2011		2010		2011		2010
$	303	$	260	$	1,169	$	897

The following table summarizes the Company’s stock option activity for the nine months ended September 30, 2011:

	Number of Shares			Weighted Average Option Exercise Price Per Share		Weighted Average Grant Date Fair Value Per Share		Aggregate Fair Value
Outstanding, December 31, 2010		4,820		$	2.23	$	1.60	$	6,880
Granted		807		$	4.37	$	3.11		2,506
Exercised		(364	)	$	1.77	$	1.10		(400	)
Expired or canceled		(225	)	$	2.27	$	1.64		(370	)
Outstanding, September 30, 2011		5,038		$	2.60	$	1.71	$	8,616

The following table shows the weighted average assumptions used in the Black-Scholes valuation of the fair value of stock option grants for the nine months ended September 30, 2011:

Expected dividend yield		0	%
Volatility		79.95	%
Risk free interest rate		2.21	%
Expected life		6.4	Years
Fair value of options granted (in thousands)	$	2,506
Weighted average grant date fair value per share of options granted	$	3.11

Additional information related to stock options is as follows:

	September 30,		December 31,
	2011		2010
Options exercisable		2,515		2,288

As of September 30, 2011, there was approximately $3.5 million of unamortized compensation expense related to outstanding stock options that will be recognized in 2011 through 2015.

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 was determined using the market price on the grant date and compensation expense is recorded over the applicable vesting periods.

The following table summarizes the Company’s restricted stock activity for the nine months ended September 30, 2011:

	Number of Shares			Weighted Average Grant Date Fair Value Per Share
Unvested, December 31, 2010		400		$	2.02
Granted		409			3.67
Vested/Released		(157	)		2.24
Forfeited		(22	)		2.27
Unvested, September 30, 2011		630		$	3.03

The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented:

Three Months Ended September 30,				Nine Months Ended September 30,
2011		2010		2011		2010
$	127	$	98	$	330	$	308

As of September 30, 2011, there was approximately $1.5 million of unamortized compensation expense related to outstanding restricted stock that will be recognized in 2011 through 2015.

Warrants

On May 25, 2007, the Company entered into a Securities Purchase Agreement with certain accredited investors pursuant to which the Company issued warrants to purchase 1,174,938 shares of common stock. The warrants expire on May 25, 2012 and are exercisable at a price of $3.83 per share, subject to certain adjustments. No warrants were exercised during the nine months ended September 30, 2011 and 2010. As of September 30, 2011 there were 878,000 warrants outstanding.

Oil and Gas Properties

The Company follows the full cost method of accounting for our properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of properties, less related deferred taxes, are limited to the lower of unamortized cost or the cost ceiling, defined as the sum of the PV-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. Costs in excess of the present value of estimated future net revenues are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of properties, except in unusual circumstances. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.

The estimates of our reserves as of December 31, 2010 are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. Estimates of our reserves, future net revenue and the PV-10 thereof are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average prices for the twelve months ended December 31, 2010. The average realized prices used for the estimates were $3.91 per Mcf of gas, $70.72 per Bbl of oil and $53.79 per Bbl of NGL. As of December 31, 2010, the net capitalized costs of our properties in the United States did not exceed the PV-10 of our estimated proved reserves; however, the net capitalized costs of our properties in Canada exceeded the PV-10 of our estimated proved reserves by $4.8 million, resulting in a write down for the year ended December 31, 2010. As of September 30, 2011, the net capitalized costs of our properties in the United States and Canada did not exceed the PV-10 of our estimated proved reserves.

PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing Standardized Measure. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as Standardized Measure but without deducting income taxes.

Restoration, Removal and Environmental Liabilities

The Company is subject to extensive Federal, provincial, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable.

The Company accounts for asset retirement obligations based on the guidance of Accounting Standards Codification (“ASC”) 410 which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This ASC requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the condensed consolidated financial statements.

The following table summarizes the Company’s asset retirement obligation transactions for the nine months ended September 30, 2011 and the year ended December 31, 2010:

	September 30, 2011			December 31, 2010
Beginning asset retirement obligation	$	7,734		$	10,326
Settled		(71	)		(290	)
Revisions		(8	)		(83	)
New wells placed on production and other		199			64
Deletions related to property disposals		(1	)		(2,799	)
Accretion expense		335			516
Ending asset retirement obligation	$	8,188		$	7,734

Working Capital (Deficit)

At September 30, 2011, our current liabilities of approximately $34.5 million exceeded our current assets of $18.3 million resulting in a working capital deficit of $16.2 million. This compares to a working capital deficit of approximately $8.9 million at December 31, 2010. Current liabilities at September 30, 2011 primarily consisted of the current portion of derivative liabilities of $5.1 million, trade payables of $22.1 million, revenues due third parties of $5.1 million, and other accrued liabilities of $1.7 million.

Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs.” This ASU expands existing disclosure requirements for fair value measurements and provides additional information on how to measure fair value. The Company is required to apply this ASU prospectively for interim and annual periods beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income.” This ASU will require companies to present the components of net and comprehensive income in either one or two consecutive financial statements and eliminates the option to present other comprehensive income in the statement of changes in stockholders’ equity. This ASU is effective for fiscal years and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the potential impact of this adoption on its consolidated financial statements.

Note 2. Joint Venture

On August 18, 2010, Abraxas Petroleum and its wholly-owned subsidiary, Abraxas Operating, LLC, contributed 8,333 net acres in the Eagle Ford Shale play to Blue Eagle Energy, LLC (“Blue Eagle”) and received a $25.0 million equity interest in Blue Eagle pursuant to the terms of the Subscription and Contribution Agreement among Abraxas Petroleum, Abraxas Operating, Blue Eagle and Rock Oil Company, LLC (“Rock Oil”) formerly known as Blue Stone Oil & Gas, LLC. Simultaneously, Rock Oil contributed $25.0 million in cash to Blue Eagle for a $25.0 million equity interest in Blue Eagle. Rock Oil committed to contribute an additional $50.0 million to Blue Eagle and upon full funding, Abraxas Petroleum will own a 25% equity interest and Rock Oil will own a 75% equity interest.

Blue Eagle’s subject area encompasses 12 counties across the Eagle Ford Shale play. Abraxas Petroleum operates the wells owned by Blue Eagle and Rock Oil and Abraxas jointly manage the day-to-day business affairs of Blue Eagle. Robert L. G. Watson, our President and CEO, serves as one of the three members of the Board of Managers of Blue Eagle.

At formation and through June 29, 2011, we owned a non-controlling 50.0% interest in the joint venture. On June 29, 2011, Rock Oil contributed $11.0 million to Blue Eagle to purchase approximately 2,487 net acres in northern McMullen County, Texas, which reduced our equity interest to 41.0%. As of September 30, 2011, we owned a non-controlling 41.0% interest in the joint venture. We account for the joint venture under the equity method of accounting. Under this method, Abraxas’ share of net income (loss) from the joint venture is reflected as an increase (decrease) in its investment account in “Investment in joint venture” and is also recorded as equity investment income (loss) in “Equity in loss (income) of joint venture.” For the three and nine months ended September 30, 2011, we reported a gain of $546,000 and $2.1 million, respectively, related to Blue Eagle.

The following table summarizes certain financial data from Blue Eagle’s September 30, 2011 and December 31, 2010 financial statements:

Balance Sheet:	As of September 30, 2011		As of December 31, 2010
Assets:
Current assets	$	6,361	$	19,625
Oil and gas properties		63,275		31,753
Other assets		38		45
Total assets	$	69,674	$	51,423

Liabilities and Member Capital:
Current liabilities	$	5,996	$	3,368
Other liabilities		16		—
Member capital		63,662		48,055
Total liabilities and member capital	$	69,674	$	51,423

Statement of Operations:	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenue	$	3,024		$	—		$	9,880		$	—
Operating expenses		1,695			474			4,843			474
Other (income) expense		(2	)		—			(10	)		—
Net income (loss)	$	1,331		$	(474	)	$	5,047		$	(474	)

Note 3. Income Taxes

The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates expected to be in effect when the differences are expected to reverse.

For the three and nine months ended September 30, 2011, there were no current or deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowances which have been recorded against such benefits.

The Company accounts for uncertain tax positions under provisions ASC 740-10. This ASC did not have any effect on the Company’s financial position or results of operations for the three and nine months ended September 30, 2011 and 2010. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2011, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 2000 through 2010 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and Abraxas Energy Partners, L.P., which was merged into a wholly-owned subsidiary of Abraxas in 2009, are currently undergoing an Internal Revenue Service audit of their 2009 Federal income tax returns.

Note 4. Long-Term Debt

The following table summarizes the Company’s long-term debt:

	September 30, 2011			December 31, 2010
Credit facility	$	93,000		$	136,000
Rig loan agreement		4,069			—
Real estate lien note		4,979			5,092
		102,048			141,092
Less current maturities		(160	)		(152	)
	$	101,888		$	140,940

Credit Facility

On June 30, 2011, we entered into a second 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 credit facility. As of September 30, 2011, $93.0 million was outstanding under the credit facility.

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. The borrowing base is currently $125.0 million and is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. The borrowing base will be automatically reduced 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 $125.0 million was determined based upon our reserve report dated June 30, 2011. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the 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 (b) 1.25—2.25%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus 2.25%—3.25%, depending on the utilization of the borrowing base. At September 30, 2011, the interest rate on the credit facility was 2.99% based on 1-month LIBOR borrowings.

Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2015. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets, other than our wholly owned subsidiary, Raven Drilling, LLC (“Raven Drilling”).

calculation date. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts 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 ASC 815 and ASC 410-20; provided that net income shall be adjusted to negate the effect of non-cash gain or loss attributable to Blue Eagle. 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. For the purposes of 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. We were in compliance with all covenants as of September 30, 2011.

As of September 30, 2011, the current ratio was 1.65 to 1.00, the interest coverage ratio was 3.73 to 1.00 and the total debt to EBITDAX ratio was 3.24 to 1.00.

In addition to the foregoing and other customary covenants, the 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 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.

Rig Loan Agreement

On September 19, 2011, Raven Drilling entered into a rig loan agreement with RBS Asset Finance, Inc. to finance certain cost incurred in purchasing and refurbishing an Oilwell 2000 hp diesel electric drilling rig (the “Collateral”). The rig loan agreement provides for interim borrowings payable to Raven Drilling or certain vendors on behalf of Raven Drilling until the final amount of the loan is determined. The rig loan agreement further provides for multiple notes in quantities of not less than $100,000 each with a maximum total of $7.0 million. Outstanding amounts under the interim borrowings will bear interest at LIBOR plus 3.50% and outstanding amounts under each note will bear interest at the four-year interest swap rate, published by the Federal Reserve, plus 3.50%, as determined at closing of each note. Upon closing of each note, interest only is due for the first 18-months (approximately) and thereafter, each note will amortize in full over the remaining life of the note. Interest and principal, when required, is payable monthly. Subject to earlier prepayment provisions and events of default, the stated maturity date of each note will be 60 months after the closing of the note. At September 30, 2011, the interest rate on the rig loan agreement was 3.74% based on 1-month LIBOR borrowings.

We have guaranteed Raven Drilling’s obligations under the rig loan agreement and associated notes. Obligations under the rig loan agreement are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in the Collateral.

As of September 30, 2011, $4.1 million was outstanding under the rig loan agreement.

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 building to serve as its corporate headquarters. This note was refinanced in November 2008. The 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, 2011, $5.0 million was outstanding on the note.

Note 5. Income (Loss) Per Share

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
Numerator:
Net income (loss)	$	20,085	$	(856	)	$	19,003	$	15,627
Denominator:
Denominator for basic income (loss) per share
Weighted-average shares		91,509		75,972			89,663		75,893

Effect of dilutive securities:
Stock options and warrants		2,107		—			2,497		1,226

Denominator for diluted income (loss) per share - adjusted weighted-average shares and assumed conversions		93,616		75,972			92,160		77,119

Net income (loss) per common share – basic	$	0.22	$	(0.01	)	$	0.21	$	0.21

Net income (loss) per common share – diluted	$	0.21	$	(0.01	)	$	0.21	$	0.20

For the three months ended September 30, 2010, none of the shares issuable in connection with stock options or warrants are included in diluted shares as inclusion of these shares would be antidilutive due to the loss incurred in the period. Had there not been a loss for the period, dilutive shares would have been 898.

Note 6. 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. As a result, our derivative contracts do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of our derivative contracts are recognized in earnings during the current period.

The following table sets forth our derivative contract position as of September 30, 2011:

	Fixed Price Swap
	Oil				Gas
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)		Daily Volume (MMBtu)		Swap Price (per MMBtu)
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, 2011, the aggregate fair market value of our commodity derivative contracts was an asset of approximately $10.3 million.

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 interest rate swap arrangement for $100 million at a fixed rate of 3.367% originally was set to expire on August 12, 2010. The swap was amended in February 2009 lowering our fixed rate to 2.95% and further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012. At September 30, 2011, the aggregate fair value of our interest rate swap was a liability of approximately $2.1 million.

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

	September 30, 2011			December 31, 2010
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
NYMEX-based fixed price derivative contracts	Derivative asset - current	$	8,727	Derivative asset - current	$	6,941

NYMEX-based fixed price derivative contracts	Derivative asset – long-term	$	6,443	Derivative asset – long-term	$	8,674

NYMEX-based fixed price derivative contracts	Derivative liability - current	$	3,006	Derivative liability - current	$	6,394

NYMEX-based fixed price derivative contracts	Derivative liability – long-term	$	1,849	Derivative liability – long-term	$	11,672

Interest rate swap	Derivative liability - current	$	2,093	Derivative liability - current	$	3,348

Gains and losses from derivative activities are reflected as “Gain on derivative contracts” in the condensed consolidated statements of operations.

Note 7. Fair Value

Fair Value Hierarchy—ASC 820-10 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

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

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

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

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument.

The following tables set forth information about the Company’s assets and liabilities measured at fair value as of September 30, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation methodologies utilized by the Company to determine such fair value:

	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, 2011
Assets:
Investment in common stock	$	135	$	—	$	—	$	135
NYMEX Fixed Price Derivative contracts		—		15,170		—		15,170
Total Assets	$	135	$	15,170	$	—	$	15,305
Liabilities:
NYMEX Fixed Price Derivative contracts	$	—	$	4,855	$	—	$	4,855
Interest Rate Swaps		—		—		2,093		2,093
Total Liabilities	$	—	$	4,855	$	2,093	$	6,948

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010
Assets:
Investment in common stock	$	181	$	—	$	—	$	181
NYMEX Fixed Price Derivative contracts		—		15,615		—		15,615
Total Assets	$	181	$	15,615	$	—	$	15,796
Liabilities:
NYMEX Fixed Price Derivative contracts	$	—	$	18,066	$	—	$	18,066
Interest Rate Swaps		—		—		3,348		3,348
Total Liabilities	$	—	$	18,066	$	3,348	$	21,414

The Company has an investment in Insignia Energy Ltd, the surviving entity in the merger with a former subsidiary, consisting of shares of common stock. The stock is actively traded on the Toronto Stock Exchange. This investment is valued at its quoted price as of September 30, 2011 and December 31, 2010 in U.S. 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. 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 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 interest rate swap arrangement for $100 million at a fixed rate of 3.367% originally was set to expire on August 12, 2010. The swap was amended in February 2009 lowering our fixed rate to 2.95% and further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012. As there are no observable market parameters for this type of swap, these derivative contracts are classified as Level 3.

Additional information for the Company’s recurring fair value measurements using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2011 is as follows:

	Derivative Assets (Liabilities) - net
	Three Months Ended September 30, 2011			Nine Months Ended September 30, 2011
Balance, Beginning of period	$	(2,638	)	$	(3,348	)
Settlements during the period		603			1,761
Total realized and unrealized gains included in change in net liability		(58	)		(506	)
Balance, September 30, 2011	$	(2,093	)	$	(2,093	)

Note 8. Business Segments

The following table provides the Company’s geographic operating segment data for the three and nine months ended September 30, 2011:

	Three Months Ended September 30, 2011
	U.S		Canada			Corporate			Total
Revenues:
Oil and gas production	$	17,269	$	396		$	—		$	17,665
Rig revenue		354		—			—			354
Other		—		—			1			1
		17,623		396			1			18,020

Expenses (income):
Lease operating		5,606		136			—			5,742
Production taxes		1,549		—			—			1,549
Depreciation, depletion and amortization		3,892		207			62			4,161
General and administrative		374		133			1,554			2,061
Rig operations		282		—			—			282
Net interest		113		1			867			981
Amortization of deferred financing fees		—		—			245			245
Equity in income of joint venture		—		—			(546	)		(546	)
Gain on derivative contracts		—		—			(16,641	)		(16,641	)
Other		—		—			101			101
		11,816		477			(14,358	)		(2,065	)
Net income (loss)	$	5,807	$	(81	)	$	14,359		$	20,085

	Nine Months Ended September 30, 2011
	U.S		Canada			Corporate			Total
Revenues:
Oil and gas production	$	47,063	$	1,102		$	—		$	48,165
Rig revenue		846		—			—			846
Other		—		—			5			5
		47,909		1,102			5			49,016

Expenses (income):
Lease operating		14,902		462			—			15,364
Production taxes		4,229		—			—			4,229
Depreciation, depletion and amortization		10,653		531			187			11,371
General and administrative		1,285		511			5,357			7,153
Rig operations		733		—			—			733
Net interest		333		2			3,583			3,918
Amortization of deferred financing fees		—		—			1,515			1,515
Equity in income of joint venture		—		—			(2,064	)		(2,064	)
Gain on derivative contracts		—		—			(12,394	)		(12,394	)
Other		—		—			188			188
		32,135		1,506			(3,628	)		30,013
Net income (loss)	$	15,774	$	(404	)	$	3,633		$	19,003

The following table provides the Company’s geographic asset data as of September 30, 2011 and December 31, 2010:

Segment Assets:	September 30, 2011		December 31, 2010
United States	$	150,182	$	152,599
Canada		12,042		4,393
Corporate		51,571		25,917
	$	213,795	$	182,909

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, 2011, 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.

Note 10. Subsequent Event

On October 25, 2011, the Company purchased 1,769 acres of land (surface only) in its Portilla field which is located in San Patricio County, Texas for $3.5 million.

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 for the year ended December 31, 2010 filed with the SEC on March 16, 2011, as amended, by our Annual Report on Form 10-K/A Number 1 filed with the SEC on October 13, 2011.

The results of operations set forth below do not include our interest in the operations of Blue Eagle.

Except as otherwise noted, all tabular amounts are in thousands except per unit values.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2010.

General

We are an independent energy company engaged in the development and production of oil and gas in the United States and Canada. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.

Factors Affecting Our Financial Results

While we have attained positive net income in three of the last five years, we cannot assure you that we can achieve positive net income in the future. Our financial results depend upon many factors which significantly affect our results of operations including the following:

commodity prices and the effectiveness of our hedging arrangements;

total sales volumes of our production;

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

interest rates on borrowings; and

the level and success of exploration and development activity.

Commodity Prices and Hedging Activities

The results of our operations are highly dependent upon the prices received for our production. The prices we receive are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales 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 production are dependent upon numerous factors beyond our control. Significant declines in commodity prices could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis.

During the first nine months of 2011, the price of oil increased significantly while the price of gas decreased from the levels experienced during the first nine months of 2010. During the first nine months of 2011, the New York Mercantile (NYMEX) price for West Texas Intermediate (WTI) averaged $95.41 per Bbl compared to $77.69 per Bbl for the same period of

2010. NYMEX Henry Hub spot price for gas averaged $4.40 per MMBtu for the first nine months of 2011 compared to $4.57 for the same period of 2010. Prices closed on September 30, 2011 at $79.20 per Bbl of oil and $3.66 per MMBtu of gas. The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:

basis differentials which are dependent on actual delivery location;

adjustments for BTU content;

quality of the hydrocarbons; and

gathering, processing and transportation costs.

The following table sets forth our average differentials for the nine months ended September 30, 2011 and 2010:

	Oil - WTI						Gas – Henry Hub
	2011			2010			2011			2010
Average realized price	$	89.19		$	70.58		$	3.75		$	4.14
Average NYMEX price	$	95.41		$	77.69		$	4.40		$	4.57
Differential	$	(6.22	)	$	(7.11	)	$	(0.65	)	$	(0.43	)

Increases in the differential between the NYMEX price and the realized price we receive have in the past and could in the future significantly reduce our revenues and cash flow from operations.

We have entered into hedging arrangements for specified volumes, which equated to approximately 80% of the estimated production from our net proved developed producing reserves (as of December 31, 2010) through December 31, 2012 and 67% for 2013. By removing a significant portion of price volatility on our future production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods. 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 when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will recognize realized and unrealized gains on our commodity derivative contracts. In the first nine months of 2011, we recognized a realized gain of $726,000 and an unrealized gain of $12.2 million on our commodity swaps. In the first nine months of 2010, we recognized a realized gain of $2.1 million and an unrealized gain of $19.6 million on our commodity swaps. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

The following table sets forth our derivative position as of September 30, 2011:

	Fixed Price Swap
	Oil				Gas
Contract Periods	Daily Volume (Bbl)		Swap Price (per Bbl)		Daily Volume (MMBtu)		Swap Price (per MMBtu)
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, 2011, the aggregate fair market value of our oil and gas derivative contracts was an asset of approximately $10.3 million.

Production Volumes

Because our proved reserves will decline as oil and gas are produced, or not developed it a timely manner, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Based on the reserve information set forth in our reserve estimates as of December 31, 2010, the average annual decline rate for our net proved developed producing reserves is 12% during the first five years, 8% in the next five years, and

approximately 7% 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. Our ability to acquire or find additional reserves will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. We had capital expenditures of $53.2 million during the nine months ended September 30, 2011, which included $11.3 million associated with the rig purchase and refurbishment. We have a capital expenditure budget for 2011 of approximately $60.0 million, excluding the cost associated with the purchase and refurbishment of the drilling rig and the purchase of 1,769 acres of land (surface only) in San Patricio County, Texas, which closed in the fourth quarter. The 2011 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated commodity prices, the availability of sufficient capital resources, the results of our exploitation efforts, and our ability to obtain permits for drilling locations. With the increased number of drilling rigs running, particularly in the Williston Basin and in the Eagle Ford Shale play, together with the increased number of stages on a given frac job, frac crews and equipment are in short supply. As a result, we have experienced and may in the future experience delays in procuring services for the multi-stage frac jobs that we have planned for our operated wells, which would delay the completion of successfully drilled wells. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should commodity prices 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 expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset production decreases caused by natural field declines.

Availability of Capital

As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating activities, borrowings under our credit facility and the rig loan agreement, cash on hand, proceeds from the sale of properties and, if an appropriate opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. As of September 30, 2011, we had $32.0 million of availability under our credit facility and $2.9 million under our rig loan agreement.

On February 1, 2011, we closed a public offering of 23.6 million shares of common stock (of which 8.5 million shares were sold by certain selling stockholders) at a public offering price of $4.40 per share for total net proceeds to us of approximately $62.2 million, after fees and expenses. We used the net proceeds from the offering to repay indebtedness outstanding under our credit facility, to increase our 2011 capital expenditure budget and for general corporate purposes. We did not receive any proceeds from the sale of shares by the selling stockholders.

Exploration and Development Activity

We believe that our high quality asset base, high degree of operational control and large inventory of drilling projects position us for future growth. At December 31, 2010, we operated properties accounting for approximately 80% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations (of which 154 were classified as proved undeveloped at December 31, 2010) on our existing leasehold, the successful development of which we believe could significantly increase our production and proved reserves.

Our future 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 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. 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 are able to borrow under our credit facility will also decline. In addition, approximately 49% of our estimated proved

reserves at December 31, 2010 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.

Operational Update

Rocky Mountain – North Dakota / Montana

In various counties in North Dakota and Montana, during the third quarter five gross (0.21 net) non-operated horizontal wells, targeting the Bakken or Three Forks formation, came on-line. An additional two gross (0.05 net) non-operated horizontal wells are either waiting on a drilling rig or being completed. Since January 2010, we have elected to participate in 19 gross (1.00 net) non-operated wells in the Bakken / Three Forks play.

In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled, completed and production facilities should be completed within the next few weeks. Early production testing of each of these wells yielded flow rates in excess of 1,000 barrels of oil per day.

·	In Williams County, North Dakota, one gross (0.02 net) non-operated well targeting the Lodgepole recently came on-line.

·	The drilling rig that was purchased in July continues to undergo refurbishment and it is currently anticipated that it will begin drilling on the first multi-well pad site in McKenzie County, North Dakota in the fourth quarter.

Rocky Mountain - Wyoming

In Niobrara County, Wyoming, the Prairie Falcon 3H was drilled to a total measured depth of 12,120 feet, including a 4,185 foot lateral, and is currently being completed with a 15-stage fracture stimulation. In Campbell County, Wyoming, a horizontal well targeting the Turner formation is planned to be drilled in the fourth quarter of 2011 or first quarter of 2012, subject to timing of rig availability. We own a 100% working interest in each of these wells.

South Texas – Eagle Ford

·	At September 30, 2011, we owned a 41% equity interest in Blue Eagle, a joint venture between Abraxas and Rock Oil Company, LLC.

In Atascosa County, Texas, the Grass Farms 1H was drilled to a total measured depth of 13,150 feet, including a 5,400 foot lateral. The well was recently completed with an 18-stage fracture stimulation and is currently recovering frac fluid as the oil cut continues to increase. The well is being produced on a restricted choke to avoid formation damage and to minimize gas production. Blue Eagle owns a 100% working interest in this well.

·	Blue Eagle anticipates drilling one horizontal well on its recently acquired leasehold (2,487 net acres) in northern McMullen County in the fourth quarter.

West Texas

In Nolan County, Texas, the Spires 126 3H was recently drilled to a total measured depth of 9,300 feet, including a 2,000 foot lateral, and completed open hole and un-stimulated. The well recently came on-line and has produced an average of 180 barrels of oil equivalent (80% oil or liquids) during its first 10 days on production. We own a 100% working interest in this well.

·	In Coke County, Texas, the Sadie A #2 was recently drilled to a total vertical depth of 6,425 feet and is currently being completed. This well targeted the Canyon Sands and we own a 100% working interest in this well.

Canada - Pekisko

In Alberta, Canada, the Twining 6-11 and the Twining 6-12 were recently completed and placed on production. A third well, the Twining 15-18, is currently drilling below 7,500 feet towards a total measured depth of 9,800 feet, including a 3,600 foot lateral. Canadian Abraxas owns a 100% working interest in each of these wells which have targeted the Pekisko formation.

Results of Operations

The following table sets forth certain operating, excluding our interest in the operations of Blue Eagle, data for the periods presented:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Operating revenue:
Oil sales (1)	$	13,157	$	8,530	$	35,320	$	26,313
Gas sales (1)		4,070		5,042		11,943		17,620
NGL sales		438		137		902		285
Rig operations		354		259		846		779
Other		1		1		5		7
	$	18,020	$	13,969	$	49,016	$	45,004

Operating income	$	4,225	$	1,273	$	10,166	$	6,058
Oil sales (MBbl)		153		124		396		373
Gas sales (MMcf)		1,088		1,369		3,187		4,251
NGL sales (MBbl)		8		4		18		8
Average oil sales price ($/Bbl) (1)	$	85.99	$	68.68	$	89.19	$	70.58
Average gas sales price ($/Mcf) (1)	$	3.74	$	3.68	$	3.75	$	4.14
Average NGL sales price ($/Bbl)	$	50.20	$	32.95	$	50.24	$	37.56

______________

(1)

Before the impact of derivative activities.

Comparison of Three Months Ended September 30, 2011 to Three Months Ended September 30, 2010

Operating Revenue. During the three months ended September 30, 2011, operating revenue increased to $18.0 million from $14.0 million for the same period of 2010. The increase in revenue was primarily due to higher realized commodity prices and an increase in oil and NGL sales volumes, partially offset by a decrease in gas sales volumes. Increased commodity prices contributed $2.3 million and increased oil and NGL sales volumes contributed $2.7 million to operating revenue. Decreased gas sales volumes had a negative impact of $1.0 million for the quarter ended September 30, 2011.

Oil sales volumes increased to 153 MBbl during the three months ended September 30, 2011 from 124 MBbl for the same period of 2010. The increase in oil sales was due to new wells brought on line offset by sales of non-core properties and natural field declines. New wells brought onto production contributed 50 MBbl for the three months ended September 30, 2011. The divested properties produced 4 MBbl during the third quarter of 2010. Gas sales volumes decreased to 1,088 MMcf for the three months ended September 30, 2011 from 1,369 MMcf for the same period of 2010. The decrease in gas sales was due to sales of non-core properties and natural field declines. The divested properties produced 188 MMcf during the third quarter of 2010. New wells brought onto production contributed 68 MMcf for the three months ended September 30, 2011. NGL sales volumes increased to 8 MBbl for the three months ended September 30, 2011 from 4 MBbl for the same period of 2010. The increase in NGL sales was primarily due to increased gas production in West Texas and North Dakota that has a higher NGL content than our historical gas production.

Lease Operating Expenses (“LOE”). LOE for the three months ended September 30, 2011 increased to $5.7 million from $5.3 million for the same period in 2010. The increase in LOE was due to higher operating costs offset by LOE related to the properties sold. LOE related to properties sold were $271,000 in the three months ended September 30, 2010. LOE per Boe for the three months ended September 30, 2011 was $16.74 compared to $14.77 for the same period of 2010. The increase per Boe was due to higher costs and lower sales volumes for the three months ended September 30, 2011 as compared to the same period of 2010.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended September 30, 2011 increased to $1.5 million from $1.3 million for the same period

of 2010, primarily as the result of higher commodity prices offset by the sale of non-core properties. Production and ad valorem taxes related to the properties sold were $103,000 in the third quarter of 2010.

General and Administrative (“G&A”) Expenses. G&A expenses, excluding stock-based compensation, for the three months ended September 30, 2011 decreased to $1.6 million from $1.7 million for the same period of 2010. G&A per Boe was $4.75 for the quarter ended September 30, 2011 compared to $4.87 for the same period of 2010. The decrease per Boe was due to lower costs offset by lower production volumes in the third quarter of 2011 compared to the same period in 2010.

Stock-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 have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the quarters ended September 30, 2011 and 2010, stock-based compensation was $430,000 and $358,000, respectively. The increase in 2011 was due to stock option grants in the third quarter of 2011.

Depreciation, Depletion and Amortization (“DD&A”) Expenses. DD&A expense for the three months ended September 30, 2011 increased to $4.2 million from $3.8 million for the same period of 2010. The increase was primarily the result of an increase to the depletion base from an increase in future development costs as determined by the December 31, 2010 reserve report, the contribution of properties to Blue Eagle and the divestiture of non-core properties offset by decreased production volumes for the quarter ended September 30, 2011 as compared to the same period of 2010. DD&A per Boe for the three months ended September 30, 2011 was $12.13 compared to $10.72 in 2010. The increase per Boe was primarily due to a higher depletion rate on our Canadian reserves.

Interest Expense. Interest expense for the three months ended September 30, 2011 decreased to $983,000 from $2.3 million for the same period of 2010. The decrease was primarily due to lower interest rates and lower levels of debt as compared to the same period of 2010.

(Gain) loss on derivative contracts. We account for derivative contract 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 contracts do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The estimated value of our derivative contracts was an asset of approximately $8.2 million as of September 30, 2011, of which $10.3 million was attributable to our commodity swaps and ($2.1) million to our interest rate swap. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the three months ended September 30, 2011, we realized a gain on our derivative contracts of $191,000, which included a realized gain of $791,000 on our commodity swaps and a realized loss of $600,000 on our interest rate swap and we incurred an unrealized gain of $16.5 million on our derivative contracts, which included an unrealized gain of $15.9 million on our commodity swaps and an unrealized gain of $542,000 on our interest rate swap. For the three months ended September 30, 2010, we realized a gain on our derivative contracts of $499,000, which included a realized gain of $1.1 million on our commodity swaps and a realized loss of $573,000 on our interest rate swap and we incurred an unrealized gain of $331,000, which included an unrealized gain of $611,000 on our commodity swaps and an unrealized loss of $280,000 on our interest rate swap.

Equity in (income) loss of joint venture. We account for the joint venture under the equity method of accounting. Under this method, Abraxas’ share of net income (loss) from the joint venture is reflected as an increase (decrease) in its investment account in “Investment in joint venture” and is also recorded as equity investment income (loss) in “Equity in loss (income) of joint venture.” For the three months ended September 30, 2011, we reported income of $546,000 related to Blue Eagle. See Note 2 of the Notes to Condensed Consolidated Financial Statements.

The following table represents our equity interest in Blue Eagle’s production for the three months ended September 30, 2011:

	Three Months Ended September 30, 2011
Oil sales (MBbl)		5
Gas sales (MMcf)		98
NGL sales (MBbl)		9
Average oil sales price ($/Bbl)	$	80.15
Average gas sales price ($/Mcf)	$	4.29
Average NGL sales price ($/Bbl)	$	47.21

Comparison of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2010

Operating Revenue. During the nine months ended September 30, 2011, operating revenue increased to $49.0 million from $45.0 million for the same period of 2010. The increase in revenue was primarily due to higher realized commodity prices for oil and NGL’s and an increase in oil and NGL sales volumes, partially offset by a decrease in gas prices and sales volumes. Increased commodity prices for oil and NGL’s contributed $7.6 million and increased oil and NGL sales volumes contributed $2.0 million to operating revenue. Decreased gas sales volumes had a negative impact of $1.2 million and lower gas prices had a negative impact of $4.4 million for the nine months ended September 30, 2011.

Oil sales volumes increased to 396 MBbl during the nine months ended September 30, 2011 from 373 MBbl for the same period of 2010. The increase in oil sales was due to new wells being brought on line, partially offset by sales of non-core properties and natural field declines. New wells brought onto production contributed 85 MBbl for the nine months ended September 30, 2011. The divested properties produced 22 MBbl during the first nine months of 2010. Gas sales volumes decreased to 3,187 MMcf for the nine months ended September 30, 2011 from 4,251 MMcf for the same period of 2010. The decrease in gas sales was due to sales of non-core properties and natural field declines. The divested properties produced 657 MMcf during the first nine months of 2010. New wells brought onto production contributed 111 MMcf for the nine months ended September 30, 2011. NGL sales volumes increased to 18 MBbl for the nine months ended September 30, 2011 from 8 MBbl for the same period of 2010. The increase in NGL sales was primarily due to increased gas production in West Texas and North Dakota that has a higher NGL content than our historical gas production.

Lease Operating Expenses (“LOE”). LOE for the nine months ended September 30, 2011 increased to $15.4 million compared to $14.9 million for the same period of 2010. LOE increased primarily due to higher costs for services offset by the LOE related to the properties sold. LOE related to properties sold were $1.2 million in the nine months ended September 30, 2010. LOE per Boe for the nine months ended September 30, 2011 was $16.26 compared to $13.68 for the same period of 2010. The increase per Boe was due to higher overall costs and lower sales volumes for the nine months ended September 30, 2011 as compared to the same period of 2010.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the nine months ended September 30, 2011 decreased to $4.2 million from $4.5 million for the same period of 2010, primarily as the result of the sale of non-core properties. Production and ad valorem taxes related to the properties sold were $528,000 for the nine months ended September 30, 2010.

General and Administrative (“G&A”) Expenses. G&A expenses, excluding stock-based compensation, for the nine months ended September 30, 2011 increased to $5.7 million from $5.2 million for the same period of 2010. The increase in G&A was primarily due to additional bonuses paid in 2011 relating to 2010 and increased salaries. The bonuses were not realized in 2010 due to the application of a new bonus structure and the timing of the bonus calculation. Final calculations were made subsequent to filing the 2010 Form 10-K. G&A per Boe was $5.98 for the nine months ended September 30, 2011 compared to $4.79 for the same period of 2010. The increase per Boe was primarily due to higher overall cost and lower production volumes in the first nine months of 2011 compared to the same period in 2010.

Stock-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 have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the nine months ended September 30, 2011 and 2010, stock-based compensation was approximately $1.5 million and $1.2 million, respectively. The increase in 2011 was due to stock option grants in the second and third quarters of 2011.

Depreciation, Depletion and Amortization (“DD&A”) Expenses. DD&A expense for the nine months ended September 30, 2011 decreased to $11.4 million from $12.5 million for same period of 2010. The decrease was primarily the result of decreased production volumes for the nine months ended September 30, 2011 as compared to the same period of 2010, the contribution of properties to Blue Eagle and the divestiture of non-core properties, offset by an increase to the depletion base from an increase in future development costs as determined by the December 31, 2010 reserve report. DD&A per Boe for the nine months ended September 30, 2011 was $12.03 compared to $11.48 in 2010. The increase per Boe was primarily due to a higher depletion rate on our Canadian reserves.

Interest Expense. Interest expense for the nine months ended September 30, 2011 decreased to $3.9 million from $6.9 million for the same period of 2010. The decrease for the nine months ended September 30, 2011 was primarily due to lower interest rates and lower levels of debt as compared to the same period of 2010.

(Gain) loss on derivative contracts. We account for derivative contract 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 contracts are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The estimated value of our derivative contracts was an asset of approximately $8.2 million as of September 30, 2011, of which $10.3 million was attributable to our commodity swaps and ($2.1) million to our interest rate swap. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the nine months ended September 30, 2011, we realized a loss on our derivative contracts of $1.0 million, which included a realized gain of $726,000 on our commodity swaps and a realized loss of $1.7 million on our interest rate swap and we incurred an unrealized gain of $13.4 million on our derivative contracts, which included an unrealized gain of $12.2 million on our commodity swaps and an unrealized gain of $1.2 million on our interest rate swap. For the nine months ended September 30, 2010, we realized a gain on our derivative contracts of $390,000, which included a realized gain of $2.1 million on our commodity swaps and a realized loss of $1.7 million on our interest rate swap and we incurred an unrealized gain of $18.0 million, which included an unrealized gain of $19.6 million on our commodity swaps and an unrealized loss of $1.6 million on our interest rate swap.

Equity in (income) loss of joint venture. We account for the joint venture under the equity method of accounting. Under this method, Abraxas’ share of net income (loss) from the joint venture is reflected as an increase (decrease) in its investment account in “Investment in joint venture” and is also recorded as equity investment income (loss) in “Equity in loss (income) of joint venture.” For the nine months ended September 30, 2011, we reported income of $2.1 million related to Blue Eagle. See Note 2 of the Notes to Condensed Consolidated Financial Statements.

The following table represents our equity interest in Blue Eagle’s production for the nine months ended September 30, 2011:

	Nine Months Ended September 30, 2011
Oil sales (MBbl)		20
Gas sales (MMcf)		331
NGL sales (MBbl)		33
Average oil sales price ($/Bbl)	$	87.12
Average gas sales price ($/Mcf)	$	4.24
Average NGL sales price ($/Bbl)	$	45.52

Recently Issued Accounting Pronouncements

We discuss recently adopted and issued accounting standards in Item 1. Notes to Condensed Consolidated Financial Statements—Note 1, “Basis of Presentation.”

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:

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

acquisition of additional properties;

acquisition of additional interest in existing 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.

Our principal sources of capital going forward will be cash flow from operations, borrowings under our credit facility and the rig loan agreement, cash on hand, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete financing on terms acceptable to us, if at all.

Working Capital (Deficit)

Capital expenditures. Capital expenditures during the nine months ended September 30, 2011 were $53.2 million including $11.3 million associated with the rig purchase and refurbishment, compared to $20.4 million during the same period of 2010. The table below sets forth the components of these capital expenditures:

	Nine Months Ended September 30,
	2011		2010
Expenditure category:
Development	$	41,253	$	20,231
Facilities and other		11,902		131
Total	$	53,155	$	20,362

During the nine months ended 2011, expenditures were primarily for development of our existing properties, and expenditures related to the purchase and refurbishment of the drilling rig purchased in July 2011. During the nine months ended 2010, capital expenditures were primarily for development of our existing properties. We anticipate making capital expenditures in 2011 of $60.0 million, excluding the costs associated with the purchase and refurbishment of the drilling rig and the purchase of 1,769 acres of land (surface only) in San Patricio County, Texas. The 2011 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated commodity prices, the availability of sufficient capital resources, the results of our exploitation efforts, and ability to obtain permits for drilling locations. With the increased number of drilling rigs running, particularly in the Williston Basin and in the Eagle Ford Shale play, together with the increased number of stages on a given frac job, frac crews and equipment are in short supply. As a result, we have experienced and may in the future experience delays in procuring services for the multi-stage frac jobs that we have planned for our operated wells, which would delay the completion of successfully drilled wells. Our capital expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should commodity prices 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 expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset production decreases caused by natural field declines.

On October 25, 2011, the Company purchased 1,769 acres of land (surface only) in San Patricio County, Texas for $3.5 million.

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,
	2011			2010
Net cash provided by operating activities	$	23,035		$	14,298
Net cash used in investing activities		(44,698	)		(2,299	)
Net cash provided by (used in) financing activities		21,578			(11,800	)
Total	$	(85	)	$	199

Operating activities during the nine months ended September 30, 2011 provided $23.0 million compared to providing $14.3 million in the same period of 2010. Net income plus non-cash expense items during 2011 and 2010 and net changes in operating assets and liabilities accounted for most of these funds. Investing activities used $44.7 million during the nine months ended September 30, 2011 compared to $2.3 million in the same period of 2010. For the first nine months of 2011, funds used for capital expenditures were primarily for the development of existing properties and the purchase and refurbishment of a drilling rig, offset by proceeds from the sale of non-core properties. Funds used in the first nine months of 2010 were expenditures for the development of our existing properties offset by proceeds from the sale of non-core properties. Financing activities provided $21.6 million for the first nine months of 2011 compared to using $11.8 million for the first nine months of 2010. Funds provided during the nine months ended September 30, 2011 were primarily the proceeds from our equity offering in February 2011 of $62.2 million offset by payments on our long term debt of $63.1 million.

Future Capital Resources. Our principal sources of capital going forward are cash flow from operations, borrowings under our credit facility and the rig loan agreement, cash on hand, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete financing on terms acceptable to us, if at all.

In the fourth quarter of 2009 and throughout 2010, we sold certain non-operated, non-core assets, to generate cash for debt repayment and to accelerate our drilling program. We sold properties in nine different states for combined net proceeds of approximately $32.2 million (of which $8.5 million was received in February 2011) at various property auctions to numerous buyers. The net proceeds were used to repay outstanding indebtedness under our credit facility, for capital expenditures and general corporate purposes.

Cash from operating activities is dependent upon commodity prices, which are volatile, and production volumes. Oil prices increased during 2010 and have continued to increase during the first nine months of 2011, while gas prices remain weak. A decrease in commodity prices from current levels would reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Unless we otherwise expand and develop reserves, our production volumes will decline as reserves are produced. In the future we may sell producing properties, which would 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 and develop 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 reservoirs will be found. Additionally, due to the increased number of drilling rigs running, particularly in the Williston Basin and in the Eagle Ford Shale play, together with the increased number of stages on any given frac job, frac crews and equipment are in short supply. As a result, we have experienced and may in the future experience delays in procuring services for the multi-stage frac jobs that we have planned for our operated wells, which would delay the completion of successfully drilled wells. 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 credit facility will also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 49% of our proved reserves at December 31, 2010 were classified as undeveloped.

Contractual Obligations

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

Long-term debt; and

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, 2011:

	Payments due in twelve month periods ending:
Contractual Obligations	Total		September 30, 2012		September 30, 2013-2014		September 30, 2015-2016		Thereafter
Long-term debt (1)	$	102,048	$	160	$	1,495	$	99,092	$	1,301
Interest on long-term debt (2)		11,953		3,198		6,333		2,383		39
Lease obligations (3)		129		68		61		—		—
Total	$	114,130	$	3,426	$	7,889	$	101,475	$	1,340

(1)

These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These payments assume that we will not borrow additional funds.

(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, Alberta, which expires on January 30, 2014, and a lease on office space in North Dakota, which expires on September 30, 2012.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At September 30, 2011, our reserve for these obligations totaled $8.2 million for which no contractual commitment exists. For additional information related to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.

Off-Balance Sheet Arrangements. At September 30, 2011, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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, 2011, 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 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.

Long-Term Indebtedness

The following table summarizes the Company’s long-term debt:

	September 30, 2011			December 31, 2010
Credit facility	$	93,000		$	136,000
Rig loan agreement		4,069			—
Real estate lien note		4,979			5,092
		102,048			141,092
Less current maturities		(160	)		(152	)
	$	101,888		$	140,940

Credit Facility

commitment amount. Outstanding amounts under the 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) 1.25—2.25%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus 2.25%—3.25%, depending on the utilization of the borrowing base. At September 30, 2011, the interest rate on the credit facility was 2.99% based on 1-month LIBOR borrowings.

Under the 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 of not less than 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter of not less than 2.50 to 1.00. We are also required to maintain a total debt to EBITDAX ratio as of the last day of each quarter of not more than 4.00 to 1.00. 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 a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20, and any accounts receivable from Blue Eagle and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20, and any accounts payable to Blue Eagle. 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. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts 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 ASC 815 and ASC 410-20; provided that net income shall be adjusted to negate the effect of non-cash gain or loss attributable to Blue Eagle. 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. For the purposes of 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. We were in compliance with all covenants as of September 30, 2011.

As of September 30, 2011, the current ratio was 1.65 to 1.00, the interest coverage ratio was 3.73 to 1.00 and the total debt to EBITDAX ratio was 3.24 to 1.00.

In addition to the foregoing and other customary covenants, the 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.

Rig Loan Agreement

On September 19, 2011, Raven Drilling entered into a rig loan agreement with RBS Asset Finance, Inc. to finance the costs of purchasing and refurbishing of an Oilwell 2000 hp diesel electric drilling rig (the “Collateral”). The rig loan agreement provides for interim borrowings payable to Raven Drilling or certain vendors on behalf of Raven Drilling until the final amount of the loan is determined. The rig loan agreement further provides for multiple notes in quantities of not less than $100,000 each with a maximum total of $7.0 million. Outstanding amounts under the interim borrowings will bear interest at LIBOR plus 3.50% and outstanding amounts under each note will bear interest at the four-year interest swap rate, published by the Federal Reserve, plus 3.50%, as determined at closing of each note. Upon closing of each note, interest only is due for the first 18-months (approximately) and thereafter, each note will amortize in full over the remaining life of the note. Interest and principal, when required, is payable monthly. Subject to earlier prepayment provisions and events of default, the stated maturity date of the note will be 60 months after the closing of the note. At September 30, 2011, the interest rate on the rig loan agreement was 3.74% based on 1-month LIBOR borrowings.

As of September 30, 2011, $4.1 million was outstanding under the rig loan agreement.

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 building to serve as its corporate headquarters. This note was refinanced in November 2008. The 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, 2011, $5.0 million was outstanding on the note.

Hedging Activities

Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. We have entered into commodity swaps on approximately 80% of the estimated oil and gas production from our net proved developed producing reserves (as of December 31, 2010) through December 31, 2012 and on 67% for the calendar year 2013.

The following table sets forth our derivative contract position as of September 30, 2011:

	Fixed-Price Swaps
	Oil				Gas
Contract Period	Daily Volume (Bbl)		Swap Price (per Bbl)		Daily Volume (MMBtu)		Swap Price (per MMBtu)
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 recognized, and in the future will recognize, realized and unrealized losses on our derivative contracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will recognize realized and unrealized gains on our commodity derivative contracts. For the nine months ended September 30, 2011, we recognized a realized gain of $726,000 and an unrealized gain of $12.2 million as compared to a realized gain of $2.1 million and an unrealized gain of $19.6 million on our commodity derivative contracts during the first nine months of 2010. If the disparity between our contract prices and market prices continues, we will recognize 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 credit facility 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 drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.

See “—Quantitative and Qualitative Disclosures about Market Risk—Derivative Instrument Sensitivity” for further information.

Net Operating Loss Carryforwards

At December 31, 2010, we had, subject to the limitation discussed below, $139.6 million of net operating loss carryforwards for U.S. tax purposes and $3.1 million of net operating loss carryforwards for Canadian tax purposes. The U.S. loss carryforward will expire from 2022 through 2030 and the Canadian loss carryforward will expire in 2030, if not utilized.

Uncertainties exist as to the future utilization of the net operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, we established a valuation allowance of $91.9 million for deferred tax assets at December 31, 2010.

We account for uncertain tax positions under provisions of ASC 740-10. This ASC did not have any effect on the Company’s financial position or results of operations for the year ended December 31, 2010 or for the nine months ended September 30, 2011. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2011, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 2000 through 2010 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and Abraxas Energy Partners, L.P., which was merged into a wholly-owned subsidiary of Abraxas, are currently undergoing an Internal Revenue Service audit of their 2009 Federal income tax returns.

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 prevailing commodity prices. Declines in commodity prices will adversely affect our operating results and our financial condition, liquidity and ability to obtain financing. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing commodity prices 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, commodity prices 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 indices 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, 2011, a 10% decline in commodity prices would have reduced our operating revenue, cash flow and net income by approximately $4.8 million; however, due to the derivative contracts that we have in place, it is unlikely that a 10% decline in commodity prices would significantly impact our operating revenue, cash flow and net income.

Derivative Instrument Sensitivity

We account for our derivative contracts in accordance with ASC 815. The derivative instruments we utilize are based on index prices that may and often do differ from the actual prices realized in our operations. Our derivative contracts do not qualify for hedge accounting as prescribed by ASC 815; therefore fluctuations in the market value of our derivative contracts are recognized in earnings during the current period.

The following table sets forth our derivative contract position as of September 30, 2011:

	Fixed-Price Swaps
	Oil				Gas
Contract Period	Daily Volume (Bbl)		Swap Price (per Bbl)		Daily Volume (MMBtu)		Swap Price (per MMBtu)
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 interest rate swap arrangement for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. The swap was amended in February 2009 lowering our fixed rate to 2.95% and further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012.

At September 30, 2011, the aggregate fair market value of our commodity derivative contracts was an asset of approximately $10.3 million and the aggregate fair market value of our interest rate swap was a liability of approximately $2.1 million.

For the nine months ended September 30, 2011, we recognized a realized gain of $726,000 and an unrealized gain of $12.2 million on our commodity derivative contracts and we recognized a realized loss of $1.7 million and an unrealized gain of $1.2 million on our interest rate swap.

Interest rate risk

We are subject to interest rate risk associated with borrowings under our credit facility. As of September 30, 2011, we had $93.0 million of outstanding indebtedness under our credit facility. Outstanding amounts under the 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) 1.25—2.25%, depending on the utilization of the borrowing

base, or, if we elect LIBOR plus 2.25%—3.25%, depending on the utilization of the borrowing base. At September 30, 2011, the interest rate on the credit facility was 2.99% based on 1-month LIBOR borrowings. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $930,000 on an annual basis. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The interest rate swap arrangement for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. The swap was amended in February 2009 lowering our fixed rate to 2.95% and further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012.

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 months ended September 30, 2011 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

ABRAXAS PETROLEUM CORPORATION

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, as amended, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K, as amended, 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 affect our business, financial condition and/or operating results.

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

None

Item 3. Defaults Upon Senior Securities.

None

Item 4. [Removed and Reserved].

Item 5. Other Information.

None

Item 6. Exhibits.

(a)

Exhibits

Exhibit 31.1

Certification - Robert L.G. Watson, CEO

Exhibit 31.2

Certification – Barbara M. Stuckey, 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 – Barbara M. Stuckey, CFO

ABRAXAS PETROLEUM CORPORATION

SIGNATURES

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

Date: November 9, 2011		By: /s/Robert L.G. Watson
		ROBERT L.G. WATSON,
		President and Principal
		Executive Officer

Date: November 9, 2011		By: /s/Barbara M. Stuckey
		BARBARA M. STUCKEY,
		Vice President and
		Principal Financial Officer

Date: November 9, 2011		By: /s/G. William Krog, Jr.
		G. WILLIAM KROG, JR.,
		Principal Accounting Officer