newsrelaeas.htm

Net loss for the quarter ended September 30, 2010 was $856,000, or $0.01 per share, compared to net loss of $4.4 million, or $0.09 per share, for the same period in 2009. Adjusted net loss, excluding unrealized gains on derivative contracts, for the quarter ended September 30, 2010 was $1.2 million, or $0.02 per share, compared to adjusted net income, excluding unrealized losses on derivative contracts and non-controlling interest, of $747,000, or $0.02 per share, for the same period in 2009.

Unrealized gains or losses on derivative contracts are based on mark-to-market valuations which are non-cash in nature and may fluctuate drastically period to period. As commodity prices fluctuate, these derivative contracts are valued against current market prices at the end of each reporting period in accordance with Accounting Standards Codification (“ASC”) 815, “Derivatives and Hedging,” as amended and interpreted, and require Abraxas to either record an unrealized gain or loss based on the calculated value difference from the previous period-end valuation.

In McKenzie County, North Dakota, Abraxas is currently drilling the horizontal lateral of the Stenehjem 27-34 1H in the middle Bakken formation, to a target lateral length of approximately 9,000 feet. A 28-stage fracture stimulation is currently scheduled for the end of December. Abraxas owns an approximate 70% working interest in this well.

In Dunn, Divide and McKenzie Counties, North Dakota, Abraxas elected to participate in six non-operated Bakken/Three Forks wells that are currently drilling or planned to be drilled this year. Abraxas owns an approximate 4% working interest in four of these wells and a 1% and 2% working interest in the fifth and sixth well, respectively.

In Nolan County, Texas, Abraxas drilled the Spires 149-1 to a total vertical depth of 7,300 feet and completion operations are currently underway on what appears to be an oil discovery in the Strawn formation. Abraxas is currently drilling the horizontal lateral of the Spires 126-1H in the Strawn formation. Abraxas owns a 100% working interest in each of these wells.

In DeWitt County, Texas, Blue Eagle Energy, LLC, the recently announced joint venture between Abraxas and Rock Oil Company, LLC, is currently drilling the vertical section of the T Bird 1H towards a target total measured depth of 19,300, including a 5,500 foot lateral. Abraxas currently owns an approximate 50% interest in the joint venture.

In the Twining area of Alberta, two horizontal wells targeting the Pekisko formation have been drilled by Canadian Abraxas Petroleum, ULC (“Canaxas”), an indirect wholly-owned subsidiary of Abraxas. The Swalwell 6-6 was drilled to a total measured depth of 9,725 feet, including a 4,400 foot lateral, and completed with a ten-stage fracture stimulation. The well is currently recovering load fluid and producing small amounts of oil and gas. The Twining 9-11 was drilled to a total measured depth of 10,650 feet, including a 5,250 foot lateral, and completed with a 14 stage acid stimulation. The well is currently recovering load fluid with oil. These two wells earned Canaxas approximately 10 sections of land, or 6,400 net acres. Canaxas owns a 100% working interest in each of these wells.

Abraxas continues its previously announced non-core, principally non-operated divestiture program and recently raised approximately $2.8 million in net proceeds during the November Oil & Gas Asset Clearinghouse auction. These producing properties were located in the Mid-Continent region of the United States. Since the program started in late 2009, Abraxas has raised approximately $23.8 million in net proceeds which have been used to pay down debt and accelerate capital projects.

Abraxas’ board recently approved a $40 million capital expenditure budget for 2011, a 33% increase over 2010. The 2011 capital expenditure budget will be funded out of cash flow from operations. Approximately 50% of the 2011 budget will be spent on horizontal oil wells in the Bakken/Three Forks and Niobrara plays in the Rocky Mountain region and the other 50% will target conventional oil in the Permian Basin and onshore Gulf Coast regions of the United States and central Alberta in Canada.

“The third quarter was very busy from an operational standpoint and we hope to have definitive results in the near future on a number of wells which are currently drilling, completing or awaiting completion. We were fortunate to secure two fracture stimulation dates this year for our operated wells in the Williston Basin as each of these stimulations take approximately seven days with 24-hour

Abraxas invites you to participate in a conference call on Tuesday, November 16, 2010, at 10:00 a.m. CT (11:00 a.m. ET) to discuss the contents of this release and respond to questions. Please dial 1.888.680.0894, passcode 13294497, 10 minutes before the scheduled start time, if you would like to participate in the call. The conference call will also be webcast live on the Internet and can be accessed directly on the Company’s website at www.abraxaspetroleum.com under Investor Relations. In addition to the audio webcast replay, a transcript of the conference call will be posted on the Investor Relations section of the Company’s website approximately 24 hours after the conclusion of the call, and will be accessible for at least 60 days.

Safe Harbor for forward-looking statements: Statements in this release looking forward in time involve known and unknown risks and uncertainties, which may cause Abraxas’ actual results in future periods to be materially different from any future performance suggested in this release. Such factors may include, but may not be necessarily limited to, changes in the prices received by Abraxas for natural gas and crude oil. In addition, Abraxas’ future natural gas and crude oil production is highly dependent upon Abraxas’ level of success in acquiring or finding additional reserves. Further, Abraxas operates in an industry sector where the value of securities is highly volatile and may be influenced by economic and other factors beyond Abraxas’ control. In the context of forward-looking information provided for in this release, reference is made to the discussion of risk factors detailed in Abraxas’ filings with the Securities and Exchange Commission during the past 12 months.

(In thousands except per share data):	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Financial Results:
Revenues	$	13,969	$	13,409	$	45,004	$	36,627
EBITDA(a)	6,524		9,319		21,870		31,149
Discretionary cash flow(a)	3,810		5,714		13,696		20,995
Net income (loss)	(856)		(4,370)		15,627		(9,952)
Net income (loss) per share – basic	$	(0.01)	$	(0.09)	$	0.21	$	(0.20)
Weighted average shares outstanding – basic	75,972		49,672		75,893		49,600

Production:
Crude oil per day (Bopd)	1,395		1,583		1,393		1,595
Natural gas per day (Mcfpd)	14,879		17,087		15,572		17,497
Crude oil equivalent per day (Boepd)	3,875		4,430		3,989		4,512
Crude oil equivalent (MBoe)	356.5		407.6		1,088.9		1,231.7

Realized Prices, net of realized hedging activity:
Crude oil ($ per Bbl)	$	65.12	$	73.31	$	66.28	$	67.03
Natural gas ($ per Mcf)	4.69		4.40		4.97		5.26
Crude oil equivalent ($ per Boe)	41.46		43.15		42.55		44.09

Expenses:
Lease operating ($ per Boe)	$	14.77	$	13.10	$	13.68	$	11.84
Production taxes (% of oil and gas revenue)	9.4%		11.1%		10.2%		11.3%
General and administrative, excluding stock-based compensation ($ per Boe)	4.87		3.64		4.79		3.75
Cash interest ($ per Boe)	6.01		7.17		5.93		6.69
Depreciation, depletion and amortization ($ per Boe)	10.72		10.12		11.48		10.65

(In thousands except per share data)	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

Revenues:
Oil and gas production revenues	$	13,709	$	13,215	$	44,218	$	35,930
Rig revenues	259		192		779		692
Other	1		2		7		5
	13,969		13,409		45,004		36,627
Operating costs and expenses:
Lease operating	5,266		5,338		14,893		14,582
Production taxes	1,292		1,464		4,519		4,074
Depreciation, depletion, and amortization	3,821		4,126		12,495		13,120
Rig operations	223		178		613		577
General and administrative (including stock-based compensation of $358, $264, $1,205 and $860)	2,094		1,746		6,426		5,476
	12,696		12,852		38,946		37,829
Operating income (loss)	1,273		557		6,058		(1,202)

Other (income) expense:
Interest income	(2)		(2)		(6)		(13)
Interest expense	2,271		3,276		6,857		8,883
Amortization of deferred financing fees	515		213		1,837		799
Loss (gain) on derivative contracts (unrealized of $(332), $8,217, $(17,968) and $22,676)	(831)		4,527		(18,358)		6,222
Financing fees	—		—		—		362
Equity in loss of joint venture	237		—		237		—
Other	(61)		13		(136)		2,242
	2,129		8,027		(9,569)		18,495
Net income (loss) before non-controlling interest	(856)		(7,470)		15,627		(19,697)
Non-controlling interest	—		3,100		—		9,745
Net income (loss)	$	(856)	$	(4,370)	$	15,627	$	(9,952)

Net income (loss) per common share - basic	$	(0.01)	$	(0.09)	$	0.21	$	(0.20)
Net income (loss) per common share - diluted	$	(0.01)	$	(0.09)	$	0.20	$	(0.20)

Weighted average shares outstanding:
Basic		75,972		49,672	75,893		49,600
Diluted		75,972		49,672	77,119		49,600

To fully assess Abraxas’ operating results, management believes that, although not prescribed under generally accepted accounting principles ("GAAP"), discretionary cash flow and EBITDA are appropriate measures of Abraxas' ability to satisfy capital expenditure obligations and working capital requirements. Discretionary cash flow and EBITDA are non-GAAP financial measures as defined under SEC rules. Abraxas' discretionary cash flow and EBITDA should not be considered in isolation or as a substitute for other financial measurements prepared in accordance with GAAP or as a measure of the Company's profitability or liquidity. As discretionary cash flow and EBITDA exclude some, but not all items that affect net income and may vary among companies, the discretionary cash flow and EBITDA presented below may not be comparable to similarly titled measures of other companies. Management believes that operating income calculated in accordance with GAAP is the most directly comparable measure to discretionary cash flow and EBITDA; therefore, operating income is utilized as the starting point for these reconciliations.

Discretionary cash flow is defined as operating income (loss) plus depreciation, depletion and amortization expenses, non-cash expenses and impairments, cash portion of other income (expense) less cash interest. The following table provides a reconciliation of discretionary cash flow to operating income (loss) for the periods presented.

(In thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Operating income (loss)	$	1,273		$	557		$	6,058		$	(1,202	)
Depreciation, depletion and amortization		3,821			4,126			12,495			13,120
Stock-based compensation		358			264			1,205			860
Realized gain (loss) on derivative contracts		499			3,690			390			16,454
Cash interest		(2,141	)		(2,923	)		(6,452	)		(8,237	)
Discretionary cash flow		3,810			5,714			13,696			20,995

EBITDA is defined as net income (loss) plus interest expense, depreciation, depletion and amortization expenses, deferred income taxes and other non-cash items. The following table provides a reconciliation of EBITDA to operating income (loss) for the periods presented – see consolidated statements of operations for a reconciliation of net income (loss) to operating income (loss).

(In thousands)	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

Operating income (loss)	$	1,273	$	557	$	6,058	$	(1,202	)
Depreciation, depletion and amortization		3,821		4,126		12,495		13,120
Stock-based compensation		358		264		1,205		860
Realized gain (loss) on derivative contracts(a)		1,072		4,372		2,112		18,371
EBITDA	$	6,524	$	9,319	$	21,870	$	31,149

This release also includes a discussion of “adjusted net income (loss), excluding certain non-cash items,” which is a non-GAAP financial measure as defined under SEC rules. The following table provides a reconciliation of adjusted net income (loss), excluding non-controlling interest and non-cash change in derivative fair value, to net income (loss) for the periods presented. Management believes that net income (loss) calculated in accordance with GAAP is the most directly comparable measure to adjusted net income (loss), excluding certain non-cash items.

(In thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009

Net income (loss)	$	(856	)	$	(4,370	)	$	15,627		$	(9,952	)
Non-controlling interest		—			(3,100	)		—			(9,745	)
Loss (gain) on unrealized derivative contracts		(332	)		8,217			(17,968	)		22,676
Adjusted net income (loss), excluding certain non-cash items	$	(1,188	)	$	747		$	(2,341	)	$	2,979
Net income (loss) per share – basic	$	(0.01	)	$	(0.09	)	$	0.21		$	(0.20	)
Adjusted net income (loss), excluding certain non-cash items, per share – basic	$	(0.02	)	$	0.02		$	(0.03	)	$	0.06

(In thousands)	September 30, 2010			December 31, 2009

Cash	$	2,060		$	1,861
Working capital (a)		(6,054	)		(2,568	)
Property and equipment – net		121,460			156,156
Total assets		178,109			176,236

Long-term debt		139,965			143,592
Stockholders’ equity		(1,673	)		(18,363	)
Common shares outstanding		76,378			76,232