ABRAXAS PETROLEUM CORP - Quarter Report: 2008 September (Form 10-Q)

axas10q093008.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

⊠	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30. 2008

⃞	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: 001-16701

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 ⊠ 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 [ ]	Accelerated filer [ X ]
Non-accelerated filer [ ] (Do not mark if a smaller reporting company)	Smaller reporting company [ ]

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

The number of shares of the issuer’s common stock outstanding as of November 6, 2008 was:

Class	Shares Outstanding
Common Stock, $.01 Par Value	49,258,537

Forward-Looking Information

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

declines in our production of natural gas and crude oil;

prices for natural gas and crude oil;

our ability to raise equity capital or incur additional indebtedness;

economic and business conditions;

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;

results of our hedging activities; and

other factors discussed elsewhere in this document.

In addition to these factors, important factors that could cause actual results to differ materially from our expectations (“Cautionary Statements”) are disclosed under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, as amended, which are incorporated by reference herein. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the Cautionary Statements.

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX

	PART I
	FINANCIAL INFORMATION

ITEM 1 -	FINANCIAL STATEMENTS
	Condensed Consolidated Balance Sheets – September 30, 2008 – (unaudited) and December 31, 2007	5
	Condensed Consolidated Statements of Operations – (unaudited) Three and Nine Months Ended September 30, 2008 and 2007	7
	Condensed Consolidated Statements of Cash Flows – (unaudited) Nine Months Ended September 30, 2008 and 2007	8
	Notes to Consolidated Financial Statements (unaudited)	9

ITEM 2 –	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

ITEM 3 –	Quantitative and Qualitative Disclosure about Market Risks	33

ITEM 4 –	Controls and Procedures	34

	PART II
	OTHER INFORMATION

ITEM 1–	Legal Proceedings	36
ITEM 1a –	Risk Factors	36
ITEM 2 –	Unregistered Sales of Equity Securities and Use of Proceeds	37
ITEM 3 –	Defaults Upon Senior Securities	37
ITEM 4 –	Submission of Matters to a Vote of Security Holders	37
ITEM 5 –	Other Information	37
ITEM 6 –	Exhibits	37
	Signatures	38

PART 1

FINANCIAL INFORMATION

Item 1. Financial Statements

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)

	September 30,
	2008		December 31,
	(Unaudited)		2007
Assets:
Current assets:
Cash	$	6,073	$	18,936
Accounts receivable, net
Joint owners		2,141		840
Oil and gas production		13,515		5,288
Other		26		—
		15,682		6,128

Derivative asset - current		2,314		2,658
Other current assets		493		377
Total current assets		24,562		28,099

Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved		431,322		265,090
Unproved properties excluded from depletion		—		—
Other property and equipment		10,201		3,633
Total		441,523		268,723
Less accumulated depreciation, depletion, and amortization		168,585		151,696
Total property and equipment – net		272,938		117,027

Deferred financing fees, net		1,723		856
Derivative asset – long-term		87		359
Other assets		842		778
Total assets	$	300,152	$	147,119

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands)

	September 30,
	2008			December 31,
	(Unaudited)			2007
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	11,310		$	7,413
Joint interest oil and gas production payable		5,409			2,429
Accrued interest		516			241
Other accrued expenses		3,285			1,514
Derivative liability – current		7,589			5,154
Current maturities of long-term debt		40,106			—
Total current liabilities		68,215			16,751

Long-term debt (less current maturities)		130,545			45,900

Derivative liability – long-term		15,767			3,941
Future site restoration		9,680			1,183
Total liabilities		224,207			67,775

Minority interest in partnership		14,919			23,497

Commitments and contingencies

Stockholders’ equity :
Common Stock, par value $.01 per share- Authorized 200,000 shares; issued and outstanding, 49,258 and 49,021		492			490
Additional paid-in capital		186,693			185,646
Accumulated deficit		(126,716	)		(130,791	)
Accumulated other comprehensive income		557			502
Total stockholders’ equity		61,026			55,847
Total liabilities and stockholders’ equity	$	300,152		$	147,119

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Revenue:
Oil and gas production revenues	$	28,910		$	10,959		$	84,856		$	35,151
Rig revenues		333			443			968			1,082
Other		3			2			15			5
		29,246			11,404			85,839			36,238
Operating costs and expenses:
Lease operating and production taxes		7,507			2,790			19,879			8,815
Depreciation, depletion, and amortization		5,806			3,611			16,904			10,867
Rig operations		241			199			644			572
General and administrative (including stock-based compensation of $400, $204, $1,297 and $748)		1,767			1,156			5,439			3,739
		15,321			7,756			42,866			23,993
Operating income		13,925			3,648			42,973			12,245

Other (income) expense:
Interest income		(47	)		(167	)		(174	)		(234	)
Interest expense		3,033			699			8,171			7,634
Amortization of deferred financing fees		281			62			748			609
Loss (gain) on derivatives (unrealized $(84,114),$(690), $16,478 and $(2,506))		(78,069	)		(2,263	)		30,024			(3,953	)
Loss on debt extinguishment		—			—			—			6,455
Gain on sale of assets		—			—			—			(59,335	)
Other		350			—			1,084			—
		(74,452	)		(1,669	)		39,853			(48,824	)
Income before income tax and minority interest		88,377			5,317			3,120			61,069

Income tax expense		—			—			—			715
Income before minority interest		88,377			5,317			3,120			60,354
Minority interest in (income) loss of partnership		(17,622	)		(2,319	)		956			(859	)
Net income	$	70,755		$	2,998		$	4,076		$	59,495


Net income per common share – basic	$	1.44		$	0.06		$	0.08		$	1.31

Net income per common share – diluted	$	1.43		$	0.06		$	0.08		$	1.30

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2008			2007
Operating Activities
Net Income	$	4,076		$	59,495
Adjustments to reconcile net income to net
cash provided by operating activities:
Minority interest in partnership income (loss)		(956	)		859
Change in derivative fair value		14,877			(1,524	)
Gain on sale of assets		—			(59,335	)
Depreciation, depletion, and amortization		16,904			10,867
Amortization of deferred financing fees		748			609
Accretion of future site restoration		426			84
Stock-based compensation		1,297			748
Other non-cash expenses		63			170
Changes in operating assets and liabilities:
Accounts receivable		(9,554	)		78
Other		(125	)		(1,480	)
Accounts payable and accrued expenses		16,621			(2,275	)
Net cash provided by operations		44,377			8,296

Investing Activities
Capital expenditures, including purchases and development of properties		(173,568	)		(13,179	)
Proceeds from the sale of oil and gas properties		753			—
Net cash used in investing activities		(172,815	)		(13,179	)

Financing Activities
Proceeds from long-term borrowings		124,751			35,790
Payments on long-term borrowings		—			(128,404	)
Deferred financing fees		(1,615	)		(992	)
Proceeds from exercise of stock options		61			1
Net proceeds from issuance of equity		—			20,073
Net proceeds from issuance of partnership equity		—			92,643
Partnerships distribution to minority interest		(7,622	)		(912	)
Net cash provided by (used in) financing activities		115,575			18,199
Increase (decrease) in cash		(12,863	)		13,316
Cash, at beginning of period		18,936			43
Cash, at end of period	$	6,073		$	13,359

Supplemental disclosure of cash flow information:
Interest paid	$	7,470		$	8,128

See accompanying notes to condensed consolidated financial statements

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Abraxas Petroleum Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(tabular amounts in thousands, except per share data)

Note 1. Basis of Presentation

The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K filed for the year ended December 31, 2007, 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 the material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim consolidated financial statements have not been audited by independent registered public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2008, are not necessarily indicative of results to be expected for the full year.

The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we”, “us”, “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating effective May 25, 2007. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 52.8% minority owners of the Partnership presented as minority interest. Abraxas owns the remaining 47.2% of the partnership interests. The Company has determined that based on its control of the general partner of the Partnership, this 47.2% owned entity should be consolidated for financial reporting purposes.

The condensed consolidated financial statements included herein have been prepared by Abraxas and are unaudited, except for the balance sheet at December 31, 2007, which has been derived from the audited consolidated financial statements at that date. In the opinion of management, the unaudited condensed consolidated financial statements include all recurring adjustments necessary for a fair presentation of the financial position as of September 30, 2008 and 2007, and the cash flows for each of the nine-month periods ended September 30, 2008 and 2007. Although management believes the unaudited interim related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The 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, 2007, as amended.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Stock-based Compensation

The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees. The Company uses the Black-Scholes model for option valuation as of the current time.

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The following table summarizes the stock option activities for the nine months ended September 30, 2008.

	Shares (thousands)		Weighted Average Option Exercise Price Per Share		Weighted Average Grant Date Fair Value Per Share		Aggregate Intrinsic Value
Outstanding, December 31, 2007	2,526		$	2.65	$	1.32	$	3,847
Granted	86		$	4.37	$	2.47		211
Exercised	(177	)	$	1.40	$	0.83		(148	)
Expired or canceled	(9	)	$	3.76	$	3.18		(28	)
Outstanding, September 30, 2008	2,426		$	2.80	$	1.60	$	3,882

The following table shows the weighted average assumptions used in the Black-Scholes valuation of the fair value of option grants during 2008.

Expected dividend yield		0	%
Volatility		0.5177
Risk free interest rate		3.398	%
Expected life		7.066
Fair value of options granted	$	211
Weighted average grant date fair value of options granted	$	2.47

Additional information related to options at September 30, 2008 and December 31, 2007 is as follows:

	September 30,	December 31,
	2008	2007
Options exercisable (in thousands)	1,999	1,852

As of September 30, 2008, there was approximately $1.1 million of unamortized compensation expense related to outstanding options that will be recognized through the period ended March 2010.

Note 2. Income taxes

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

For the nine-month period ended September 30, 2008, there is no current or deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowance which has been recorded against such benefits.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes”, and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. Accordingly, the Company adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have any effect on the Company’s financial position or results of operations for the periods subsequent to the adoption date. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2008, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2007 remain open to examination by the tax jurisdictions to which the Company is subject.

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Note 3. Long-Term Debt

Long-term debt consisted of the following:


	September 30, 2008			December 31, 2007
Partnership credit facility	$	125,600		$	45,900
Partnership subordinated credit agreement		40,000			—
Real estate lien note		5,051			—
		170,651			45,900
Less current maturities		(40,106	)		—
	$	130,545		$	45,900

Senior Secured Credit Facility. On June 27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50 million. Availability under the Credit Facility is subject to a borrowing base. The borrowing base under the Credit Facility, which at September 30, 2008 was $6.5 million, is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we may also request one redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our current borrowing base. Our borrowing base at September 30, 2008 of $6.5 million was determined based upon our reserves at December 31, 2007. Our borrowing base can never exceed the $50.0 million maximum commitment amount. Outstanding amounts under the Credit Facility will bear interest at (a) the greater of reference rate announced from time to time by Société Générale, and (b) the Federal Funds Rate plus 0.5 of 1%, plus in each case, (c) 0.5% - 1.5% depending on utilization of the borrowing base, or, if Abraxas elects, at the London Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization of the borrowing base. Subject to earlier termination rights and events of default, the Credit Facility’s stated maturity date will be June 27, 2011. Interest will be payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. As of September 30, 2008 there is no outstanding balance under this facility.

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

Each of Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC and Abraxas Energy Investments, LLC, has guaranteed Abraxas’ obligations under the Credit Facility on a senior secured basis. Obligations under the Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of Abraxas’ and the subsidiary guarantors’ material property and assets of Abraxas and the subsidiary guarantors comprising at least 90% of the PV-10 of their proved reserves and the related oil and gas properties.

Under the Credit Facility, Abraxas is subject to customary covenants, including certain financial covenants and reporting requirements. The Credit Facility requires Abraxas to maintain a minimum current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio (generally defined as the ratio of consolidated EBITDA to consolidated interest expense as of the last day of such quarter) of not less than 2.50 to 1.00.

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

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

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

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

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· 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.

Amended and Restated Partnership Credit Facility. On May 25, 2007, the Partnership entered into a senior secured revolving credit facility which was amended and restated on January 31, 2008, which we refer to as the Partnership Credit Facility. The Partnership Credit Facility has a maximum commitment of $300.0 million. Availability under the Partnership Credit Facility is subject to a borrowing base. The borrowing base under the Partnership Credit Facility, which is currently $140.0 million, is determined semi-annually by the lenders based upon the Partnership’s reserve reports, one of which must be prepared by the Partnership’s independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of the Partnership’s proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of the Partnership’s current borrowing base. The Partnership’s borrowing base at September 30, 2008 of $140.0 million was determined based upon its reserves at December 31, 2007 which included the reserves attributable to the oil and gas properties acquired from St. Mary Land & Exploration Company on January 31, 2008. The borrowing base can never exceed the $300 million maximum commitment amount. Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale and (2) the Federal Funds Rate plus 0.5%, plus in each case (b) .25% - 1.00%, depending on the utilization of the borrowing base or, if the Partnership elects, at the London Interbank Offered Rate plus 1.25% - 2.00%, depending on the utilization of the borrowing base. At September 30, 2008, the interest rate on the Partnership Credit Facility was 4.5%. Subject to earlier termination rights and events of default, the Partnership Credit Facility’s stated maturity date is January 31, 2013. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Partnership Credit Facility, and under certain circumstances, may be required, from time to time, to permanently reduce the lenders’ aggregate commitment under the Partnership Credit Facility in compliance with certain notice and dollar increment requirements.

Each of the general partner of the Partnership, Abraxas General Partner, LLC, which is a wholly-owned subsidiary of Abraxas and which we refer to as the GP, and Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we refer to as the Operating Company, has guaranteed the Partnership’s obligations under the Credit Facility on a senior secured basis. Obligations under the Partnership Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of the material property and assets of the GP, the Partnership and the Operating Company comprising at least 90% of their proved reserves and the related oil and gas properties, other than the GP’s general partner units in the Partnership.

Under the Partnership Credit Facility, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Partnership Credit Facility requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. The Partnership Credit Facility required the Partnership to enter into hedging arrangements for specified volumes, which equated to approximately 85% of the Partnership’s estimated oil and gas production from its net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the properties acquired from St. Mary in January 2008). The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from our estimated net proved developed producing reserves (including the reserves attributable to the St. Mary properties) through December 31, 2011.

Under the terms of the Partnership Credit Facility, the Partnership may make cash distributions if, after giving effect to such distributions, the Partnership is not in default under the Partnership Credit Facility and there is no borrowing base deficiency and provided that no such distribution shall be made using the proceeds of any advance unless the amount of the unused portion of the amount then available under the Partnership Credit Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing base (which at September 30, 2008 is $140.0 million) or the total commitment amount of the Partnership Credit Facility (which at September 30, 2008 was $300.0 million) at such time.

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

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

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

· permit a change of control.

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

Subordinated Credit Agreement

On January 31, 2008, the Partnership entered into a subordinated credit agreement which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement has a maximum commitment of $50 million, all of which was borrowed at closing. Outstanding amounts under the Subordinated Credit Agreement bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, and (2) the Federal Funds Rate plus 0.5%, plus in each case, (b) 4.00% to 5.50% depending on the applicable date, or, if we elect, at the London Interbank Offered Rate plus 5.00% to 6.50%, depending on the applicable date. The rates for the applicable dates are as follows:

Date	Eurodollar Rate (LIBOR) Advances	Base Rate Advances
01/31/08 – 04/30/08	5.0%	4.0%
05/01/08 – 07/31/08	5.5%	4.5%
After 07/31/08	6.5%	5.5%

At September 30, 2008, the interest rate on the facility was 9.0%. Subject to earlier termination rights and events of default, the Subordinated Credit Agreement’s stated maturity date is January 31, 2009. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. The Partnership is permitted to terminate the Subordinated Credit Agreement, and under certain circumstances, may be required, from time to time, to make prepayments under the Subordinated Credit Agreement.

Each of the GP and Abraxas Operating has guaranteed the Partnership’s obligations under the Subordinated Credit Agreement on a subordinated secured basis. Obligations under the Subordinated Credit Agreement are secured by subordinated security interests, subject to certain permitted encumbrances, in property and assets of the Partnership, GP, and Abraxas Operating comprising at least 90% of the PV-10 of their proved reserves and the related oil and gas properties, other than the GP’s general partner units in the Partnership.

Under the Subordinated Credit Agreement, the Partnership is subject to customary covenants, including certain financial covenants and reporting requirements. The Subordinated Credit Agreement requires the Partnership to maintain a minimum current ratio as of the last day of each quarter of 1.0 to 1.0 and an interest coverage ratio (defined as the ratio of consolidated EBITDA to consolidated interest expense) as of the last day of each quarter of not less than 2.50 to 1.00. The Partnership Credit Facility required it to enter into hedging arrangements for specific volumes, which equated to approximately 85% of the estimated oil and gas production from its net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The Partnership entered into NYMEX-based fixed price commodity swaps on approximately 85% of its estimated oil and gas production from our estimated net proved developed producing reserves (including the reserves attributable to the St. Mary properties) through December 31, 2011.

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

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

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

· permit a change of control.

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

The Partnership has intended to re-pay the amounts due under this agreement with the proceeds of the IPO. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. The Partnership has entered into discussions with the lending institutions to either extend or refinance the $40.0 million of debt under its Subordinated Credit Agreement, due January 31, 2009. There can be no assurance that the Partnership will be successful in such negotiations.

Interest Rate Swap

In order to mitigate its interest rate exposure, the Partnership entered into an interest rate swap, effective August 12, 2008, to fix its floating LIBOR based debt. The Partnership’s two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% reduces to $50 million on August 12, 2009. The arrangement expires on August 12, 2010.

Real Estate Lien Note

On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a new building to serve as its corporate headquarters. The note bears interest at a fixed rate of 6.65%. The note is interest only for six months. At the end of six months the note is payable in monthly principal and interest installments, based on a twenty year amortization, until maturity in June 2015 at which time the balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of September 30, 2008, $5.1 million was outstanding on the note.

Note 4. Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
Numerator:
Net income available to common stockholders	$	70,755	$	2,998	$	4,076	$	59,495
Denominator:
Denominator for basic earnings per share -
Weighted-average shares		49,043		48,814		48,955		45,524

Effect of dilutive securities:
Stock options and warrants		355		127		469		346

Dilutive potential common shares
Denominator for diluted earnings per share -
Weighted-average shares and assumed conversions		49,398		48,941		49,424		45,870

Net earnings per common share – basic	$	1.44	$	0.06	$	0.08	$	1.31

Net earnings per common share – diluted	$	1.43	$	0.06	$	0.08	$	1.30

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Note 5. Hedging Program and Derivatives

The Partnership enters into derivative contracts, which we sometimes refer to as hedging agreements, to hedge the risk of future oil and gas price fluctuations. Such agreements are primarily in the form of NYMEX-based fixed price commodity swaps, which limit the impact of price fluctuations with respect to the Partnership’s sale of oil and gas. The Partnership does not enter into speculative hedges.

Statement of Financial Accounting Standards, (‘‘SFAS’’) No. 133, ‘‘Accounting for Derivative Instruments and Hedging Activities,’’ as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The Partnership elected not to designate its derivative instruments for hedge accounting as prescribed by SFAS 133. Accordingly, all derivatives will be recorded on the balance sheet at fair value with changes in fair value being recognized in earnings.

The following table sets forth the Partnership’s derivative contract position at September 30, 2008:

Period Covered	Product	Volume (Production per day)	Weighted Average Fixed Price
Year 2008	Natural Gas	11,840 Mmbtu	$8.44
Year 2008	Crude Oil	1,105 Bbl	$84.84
Year 2009	Natural Gas	10,595 Mmbtu	$8.45
Year 2009	Crude Oil	1,000 Bbl	$83.80
Year 2010	Natural Gas	9,130 Mmbtu	$8.22
Year 2010	Crude Oil	895 Bbl	$83.26
Year 2011	Natural Gas	8,010 Mmbtu	$8.10
Year 2011	Crude Oil	810 Bbl	$86.45

Note 6. Financial Instruments

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

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

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

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

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

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

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of September 30, 2008
Assets:
Investment in common stock	$	557	$	—	$	—	$	557
NYMEX Fixed Price Derivative contracts		—		2,401		—		2,401
Total Assets	$	557	$	2,401	$	—	$	2,958
Liabilities:
NYMEX Fixed Price Derivative contracts	$	—	$	22,831	$	—	$	22,831
Interest Rate Swaps		—		—		525		525
Total Liabilities	$	—	$	22,831	$	525	$	23,356

The Company has an investment in a former subsidiary consisting of shares of common stock. The stock is actively traded on the Toronto Stock Exchange. This investment is valued at its quoted price as of September 30, 2008, in US dollars. Accordingly this investment is characterized as Level 1.

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

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

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Additional information for the Partnership’s recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the three and nine months ended September 30, 2008 is as follows (in millions):

	Derivative Assets and (Liabilities) - net
Balance July 1, 2008	$	—
Total realized and unrealized losses included in change in net assets		(525	)
Settlements during the period		—
Ending balance September 30, 2008	$	(525	)

Note 7. Minority interest in (income) loss of Partnership

The minority interest in the (income) loss of the Partnership represents the third parties 52.8% interest in the Partnership’s net income/ loss. Additionally, in accordance with generally accepted accounting principles, when cumulative losses applicable to the minority interest exceed the minority interest equity capital in the entity, such excess and any further losses applicable to the minority interest are charged to the earnings of the majority interest. If future earnings are recognized by the minority interest, such earnings will then be credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the minority interest exceeded the minority interest equity capital by $28.2 million and, thus $28.2 million of the minority interest loss in excess of equity was charged to earnings and was reflected as a reduction of the loss applicable to the minority interest. During the third quarter of 2008, the Partnership had unrealized gains which resulted in the reversal of the previously recorded unrealized losses accordingly, the $28.2 million that was charged to earnings during the second quarter was recovered in the third quarter and is reflected as a reduction of the income applicable to the minority interest.

Note 8. 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, 2008, 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 financial position, results of operations, or cash flows.

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ABRAXAS PETROLEUM CORPORATION

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

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K filed for the year ended December 31, 2007, as amended by our Annual Report on Form 10-K/A Number 1 filed with the Securities and Exchange Commission on August 11, 2008 and as further amended by our Annual Report on Form 10-K/A Number 2 filed with the Securities and Exchange Commission on August 21, 2008. The terms “Abraxas” or “Abraxas Petroleum” refer to Abraxas Petroleum Corporation and its subsidiaries other than Abraxas Energy Partners, L.P., which we refer to as “Abraxas Energy Partners” or the “Partnership”, and its subsidiary, Abraxas Operating, LLC, which we refer to as “Abraxas Operating” and the terms “we”, “us”, “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its consolidated subsidiaries including Abraxas Energy Partners and Abraxas Operating. The operations of Abraxas Petroleum and the Partnership are consolidated for financial reporting purposes with the interest of the 52.8% minority owners presented as minority interest. Abraxas owns the remaining 47.2% of the partnership interests.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2007, as amended.

General

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

Factors Affecting Our Financial Results

While we have attained positive net income in four of the five years ended December 31, 2007, we cannot assure you that we can achieve positive operating income and net income in the future. Our financial results depend upon many factors, which significantly affect our results of operations including the following:

the sales prices of natural gas and crude oil;

the level of total sales volumes of natural gas and crude oil;

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

the level of and interest rates on borrowings; and

the level of success of exploitation, exploration and development activity.

Commodity Prices and Hedging Activities.

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

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During the first six months of 2008, prices for natural gas and crude oil were sustained at record or near-record levels, however during the third quarter of 2008, and subsequently, there has been a significant drop in prices. New York Mercantile Exchange (NYMEX) spot prices for West Texas Intermediate (WTI) crude oil averaged $113.45 per barrel for the nine month period ended September 30, 2008. WTI crude oil ended the quarter at $100.64 per barrel. NYMEX Henry Hub spot prices for natural gas averaged $9.68 per million British thermal units (MMBtu) during first nine months of 2008 and ended the quarter at $7.21. Subsequent to the end of the third quarter prices for crude oil and natural gas have continued to decline. As of October 31, 2008 the (NYMEX) spot prices for West Texas Intermediate (WTI) crude oil was $67.81 per barrel and NYMEX Henry Hub spot prices for natural gas was $6.17 per million British thermal units (MMBtu). If commodity prices continue to decline, our revenue and cash flow from operations would also decline. In addition, lower commodity prices could also reduce the amount of natural gas and crude oil that we can produce economically. This may result in our having to make downward adjustments to our estimated proved reserves. If this occurs, we could incur a “ceiling limitation write-down” under applicable accounting rules. Under these rules, if the net capitalized cost of natural gas and crude oil properties exceed a ceiling limit, we must charge the amount of the excess to earnings. This charge does not impact cash flow from operating activities, but does reduce our stockholder’s equity and earnings. The risk that we will be required to write-down the carrying value of natural gas and crude oil properties increases when natural gas and crude oil prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though gas and crude oil prices may have increased the ceiling applicable to the subsequent period.

The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to:

basis differentials which are dependent on actual delivery location,

adjustments for BTU content; and

gathering, processing and transportation costs.

During the first nine months of 2008, differentials averaged $5.02 per Bbl of crude oil and $1.23 per Mcf of natural gas as compared to $2.96 per Bbl of crude oil and $0.91 per Mcf of natural gas during the same period of 2007. We have experienced greater differentials during 2008 compared to prior years because of the increased percentage of our production from the Rocky Mountain and Mid-Continent regions which experience higher differentials than our Texas properties.

Under the terms of the Partnership Credit Facility, Abraxas Energy Partners was required to enter into derivative contracts for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 from its net estimated proved developed producing reserves (including the reserves attributable to the properties acquired from St. Mary). The Partnership intends to enter into derivative contracts in the future to reduce the impact of price volatility on its cash flow. By removing a significant portion of price volatility on its future oil and gas production, the Partnership believes it will mitigate, but not eliminate, the potential effects of changing commodity gas prices on its cash flow from operations for those periods. However, when prevailing market prices are higher than the prices at which we have hedged our oil and gas production, we will not realize increased cash flow on the portion of our production that we have hedged as a result of these high prices. We have sustained and in the future we will sustain realized and unrealized losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on our derivative contracts. For example, during the three months ended September 30, 2008, we had an unrealized gain of $84.1 million on our derivative contracts. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

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The following table sets forth the Partnership’s derivative contract position at September 30, 2008:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2008	Natural Gas	11,840 Mmbtu	$8.44
Year 2008	Crude Oil	1,105 Bbl	$84.84
Year 2009	Natural Gas	10,595 Mmbtu	$8.45
Year 2009	Crude Oil	1,000 Bbl	$83.80
Year 2010	Natural Gas	9,130 Mmbtu	$8.22
Year 2010	Crude Oil	895 Bbl	$83.26
Year 2011	Natural Gas	8,010 Mmbtu	$8.10
Year 2011	Crude Oil	810 Bbl	$86.45

At September 30, 2008, the aggregate fair market value of our derivative contracts was approximately $(20.4) million.

Production Volumes. Because our proved reserves will decline as natural gas and crude oil are produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Approximately 90% of the estimated ultimate recovery of Abraxas’ and 91% of the Partnership’s, or 91% of our consolidated proved developed producing reserves as of December 31, 2007, had been produced. Based on the reserve information set forth in our reserve report of December 31, 2007, Abraxas’ average annual estimated decline rate for its net proved developed producing reserves is 9% during the first five years, 6% in the next five years, and approximately 5% thereafter. Based on the reserve information set forth in our reserve report of December 31, 2007, the Partnership’s average annual estimated decline rate for its net proved developed producing reserves is 12% during the first five years, 9% in the next five years and approximately 9% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While Abraxas has had some success in finding, acquiring and developing additional revenues, Abraxas has not been able to fully replace the production volumes lost from natural field declines and prior property sales. For example, in 2006, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we replaced 219% of the reserves we produced. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.

We had capital expenditures of $172.8 million during the first nine months of 2008, including $136.5 million for the St. Mary property acquisition that closed in January 2008, and have a capital budget for 2008 of approximately $55 million, above the St. Mary acquisition, of which $35 million is applicable to Abraxas and $20 million applicable to the Partnership. The final amount of our capital expenditures for 2008 will depend on our success rate, production levels, availability of capital and commodity prices.

Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, distributions from the Partnership and if an appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it. At September 30, 2008, Abraxas had approximately $6.5 million of availability under the Credit Facility. Upon the closing of the acquisition of properties from St. Mary, the Partnership borrowed $115.6 million under the Partnership Credit Facility and $50 million under the Subordinated Credit Agreement. At September 30, 2008, the Partnership had $14.4 million available under the Partnership Credit Facility.

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. Our properties are concentrated in locations that facilitate substantial economies of scale in drilling and production operations and more efficient reservoir management practices. At December 31, 2007, we operated 95% of the properties accounting for approximately 95% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenses.

Our future natural gas and crude oil 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 natural gas and crude oil properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. In 2006, for example, Abraxas replaced only 7% of the reserves it produced. In 2007, however, we replaced 219% of our reserves. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations, distributions of available cash from the Partnership to Abraxas and the amount that Abraxas is able to borrow under its credit facility and that the Partnership will be able to borrow under its credit facility will also decline. In addition, approximately 69% of Abraxas’ and 56% of the Partnership’s estimated proved reserves at December 31, 2007 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.

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Borrowings and Interest. At September 30, 2008, Abraxas Energy Partners had indebtedness of approximately $125.6 under the Amended Partnership Credit Facility and $40 million under the Subordinated Credit Agreement. At September 30, 2008 the Partnership had $14.4 million available under the Partnership Credit Facility. At September 30, 2008, Abraxas had availability of $6.5 million under its $50 million Credit Facility. There is currently no outstanding balance under this facility. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our numerous drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices. In order to mitigate its interest rate exposure, the Partnership entered into an interest rate swap, effective August 12, 2008, to fix its floating LIBOR based debt. The Partnership’s two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% reduces to $50 million on August 12, 2009. The arrangement expires on August 12, 2010.

Results of Operations

The following table sets forth certain of our operating data for the periods presented. Operating revenue, operating income and production data represents the consolidated total for Abraxas Petroleum and Abraxas Energy Partners. Average prices reflect realized prices before the impact of derivative contracts.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In thousands)	2008		2007		2008		2007
Operating Revenue :
Crude Oil Sales	$	15,469	$	3,479	$	43,737	$	9,212
Natural Gas Sales		13,441		7,480		41,119		25,939
Rig Operations		333		443		968		1,082
Other		3		2		15		5
	$	29,246	$	11,404	$	85,839	$	36,238

Operating Income	$	13,925	$	3,648	$	42,973	$	12,245
Crude Oil Production (MBbls)		140		48		403		147
Natural Gas Production (MMcfs)		1,663		1,409		4,865		4,334
Average Crude Oil Sales Price ($/Bbl)	$	110.66	$	72.48	$	108.43	$	62.52
Average Natural Gas Sales Price ($/Mcf)	$	8.08	$	5.31	$	8.45	$	5.98

Comparison of Three Months Ended September 30, 2008 to Three Months Ended September 30, 2007

Operating Revenue. During the three months ended September 30, 2008, operating revenue from natural gas and crude oil sales increased by $17.9 million to $28.9 million compared to $11.0 million during three months ended September 30, 2007. The increase in revenue was due to an increase in production volumes during the third quarter of 2008 as compared to the same period of 2007 as well as higher commodity prices during the third quarter of 2008 as compared to 2007. The increase in production volumes contributed $12.2 million to revenue while increased commodity prices contributed $5.7 million to oil and gas production revenue. Crude oil production volumes increased from 48 MBbls for the quarter ended September 30, 2007 to 140 MBbls for the same period of 2008 The increase in crude oil sales volumes was primarily due to production from properties acquired in the St. Mary acquisition that closed on January 31, 2008. Production for the quarter ended September 30, 2008 from these properties added 92.6 MBbls of crude oil. Natural gas production volumes increased from 1,409 MMcf for the three months ended September 30, 2007 to 1,663 MMcf for the same period of 2008. The properties acquired in the St. Mary acquisition contributed 494.9 MMcf of natural gas production during the quarter, which was partially offset by natural field declines.

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Average sales prices, net of realized gains/losses on derivative contracts, for the quarter ended September 30, 2008 were:

$84.02 per Bbl of crude oil, and

$6.69 per Mcf of natural gas

Average sales prices, net of realized gains/losses on derivative contracts, for the quarter ended September 30, 2007 were:

$67.98 per Bbl of crude oil, and

$6.58 per Mcf of natural gas

Lease Operating Expenses (“LOE”). LOE for the three months ended September 30, 2008 increased to $7.5 million compared to $2.8 million for the three months ended September 30, 2007. LOE related to the properties acquired in the St. Mary property acquisition added $4.0 million to LOE during the quarter. LOE on a per BOE basis for the three months ended September 30, 2008 was $18.01 per BOE compared to $9.86 for the same period of 2007. The increase in per BOE cost was attributable to the increase in the number of crude oil wells as a result of the St. Mary acquisition, which are generally more expensive to operate than natural gas wells, as well as the overall increase in costs.

General and Administrative (“G&A”) Expenses. G&A expenses including stock-based compensation increased to $1.8 million for the quarter ended September 30, 2008 from $1.2 million for the same period of 2007. The increase in G&A was primarily due to higher personnel expenses associated with additional staff added to manage the properties acquired from St. Mary. G&A expense on a per BOE basis was $4.24 for the third quarter of 2008 compared to $4.09 for the same period of 2007. The per Mcfe increase was attributable to the higher G&A expense being offset by higher production volumes during the third quarter of 2008 as compared to the same period of 2007.

Stock-based Compensation. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. For the three months ended September 30, 2008 and 2007, stock based compensation was approximately $400,000 and $203,000 respectively. The increase in 2008 as compared to 2007 was due to the grant of options and restricted stock in the third quarter of 2007 as well as grants to new employees.

Depreciation, Depletion and Amortization (“DD&A”) Expenses. DD&A expense increased to $5.8 million for the three months ended September 30, 2008 as compared to $3.6 million for the three months ended September 30, 2007. The increase in DD&A was primarily the result of increased production as well as an increase in the depletion base as a result of the St. Mary acquisition. Our DD&A on a per BOE basis for the three months ended September 30, 2008 was $13.92 per BOE compared to $12.78 per BOE in 2007. The increase in the per BOE DD&A was due to the higher depletion base for the period.

Interest Expense. Interest expense increased to $3.0 million for the third quarter of 2008 compared to $0.7 million for the same period of 2007. The increase in interest expense was primarily due to the increase in the Partnerships’ long term debt as a result of the St. Mary acquisition. The Partnerships’ long term debt as of September 30, 2007 was $35.0 million compared to $126.0 million as of September 30, 2008.

Income (loss) from derivative contracts. We account for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. Abraxas Energy Partners has entered into a series of NYMEX–based fixed price commodity swaps. The estimated unearned value of these derivative contracts is a liability of approximately $20.4 million as of September 30, 2008. For the quarter ended September 30, 2008, we realized a loss on these derivative contracts of $6.0 million. For the quarter ended September 30, 2008, we incurred unrealized gains on derivative contracts in place of $84.1 million. The gain for the quarter ended September 30, 2008 was due to the dramatic decline in commodity prices from their levels at June 30, 2008.

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Minority interest. Minority interest represents the share of the net income (loss) of Abraxas Energy Partners for the quarter owned by the partners other than Abraxas Petroleum. Additionally, in accordance with generally accepted accounting principles, when cumulative losses applicable to the minority interest exceed the minority interest equity capital in the entity, such excess and any further losses applicable to the minority interest are charged to the earnings of the majority interest. If future earnings are recognized by the minority interest, such earnings will then be credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the minority interest exceeded the minority interest equity capital by $28.2 million and, as a result $28.2 million of the minority interest loss in excess of equity was charged to earnings and was reflected as a reduction of the loss applicable to the minority interest. During the third quarter, primarily as a result of unrealized gains on derivative contracts, the $28.2 million loss in excess of the minority equity capital as of June 30, 2008 was recovered. The recovery of the loss incurred during the second quarter is reflected as a reduction in the net income applicable to the minority interest.

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

Comparison of Nine Months Ended September 30, 2008 to Nine Months Ended September 30, 2007

Operating Revenue. During the nine months ended September 30, 2008, operating revenue from natural gas and crude oil sales increased to $84.9 million as compared to $35.2 million in the nine months ended September 30, 2007. The increase in revenue was due to higher commodity prices as well as increased production volumes. Higher commodity prices contributed $17.5 million to revenue for the nine months ended September 30, 2008, while increased production volumes contributed $32.2 million to oil and gas revenue.

Crude oil production volumes increased from 147.4 MBbls during the nine months ended September 30, 2007 to 403.4 MBbls for the same period of 2008. The increase in crude oil sales volumes was primarily due to production from properties acquired in the St. Mary acquisition that closed on January 31, 2008. Production for the months of February through September 2008 from these properties added 253.7 MBbls of crude oil. Natural gas production increased to 4,865 MMcf for the nine months ended September 30, 2008 from 4,334 MMcf for the same period of 2007. The properties acquired in the St. Mary acquisition contributed 1,288 MMcf of natural gas production during the period, which was partially offset by natural field declines.

Average sales prices, net of realized gains/losses on derivative contracts, for the nine months ended September 30, 2008 were:

$86.43 per Bbl of crude oil, and

$7.49 per Mcf of natural gas

Average sales prices, net of realized gains/losses on derivative contracts, for the nine months ended September 30, 2007 were:

$61.05 per Bbl of crude oil, and

$6.37 per Mcf of natural gas

Lease Operating Expenses. LOE for the nine months ended September 30, 2008 increased to $19.9 million from $8.8 million for the same period of 2007. LOE related to the properties acquired in the St. Mary property acquisition added $10.2 million to LOE during the period ended September 30, 2008. LOE on a per BOE basis for the nine months ended September 30, 2008 was $16.37 per BOE compared to $10.14 for the same period of 2007. The increase in per BOE cost was attributable to the increase in the number of crude oil wells as a result of the St. Mary acquisition, which are more expensive to operate than natural gas wells, as well as an overall increase in costs. Additionally, the increase in commodity prices resulted in higher production taxes for the nine months ended September 30, 2008 as compared to the same period of 2007.

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G&A Expenses. G&A expenses, including stock-based compensation, increased to $5.4 million for the first nine months of 2008 from $3.7 million for the first nine months of 2007. The increase in G&A was primarily due to higher personnel expenses associated with additional staff added to manage the properties acquired from St. Mary. G&A expense on a per BOE basis was $4.48 for the nine months ended September 30, 2008 compared to $4.30 for the same period of 2007. The increase in G&A expense on a per BOE basis was primarily due to higher G&A expense, being offset by increased production volumes in 2008 compared to the same period in 2007.

Stock-based Compensation. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. For the nine months ended September 30, 2008 and 2007, stock based compensation was approximately $1.3 million and $748,000, respectively. The increase in 2008 as compared to 2007 was due to the grant of options and restricted stock in the third quarter of 2007 as well as grants to new employees.

DD&A Expenses. DD&A expense increased to $16.9 million for the nine months ended September 30, 2008 from $10.9 million for the same period of 2007. The increase in DD&A was primarily the result of increased production, as well as an increase in the depletion base as a result of the St. Mary acquisition. Our DD&A on a per BOE basis for the nine months ended September 30, 2008 was $13.92 per BOE compared to $12.50 per BOE in 2007. The increase in the per BOE DD&A was due to the higher depletion base for the period.

Interest Expense. Interest expense increased to $8.2 million for the first nine months of 2008 compared to $7.6 million for the same period of 2007. The increase in interest expense is due to higher levels of long-term debt as of September 30, 2008 as compared to 2007. The Partnerships long term debt as of September 30, 2007 was $35.0 million compared to $125.60 million as of September 30, 2008.

Loss on debt extinguishments. The loss on debt extinguishment consists primarily of the call premium and interest that was paid in connection with the refinancing and redemption of our senior secured notes in May 2007.

Income taxes. Federal income tax and state of Texas margin tax have been recognized for the period ended September 30, 2007 as a result of the gain on the sale of assets during the period. No deferred income tax expense or benefit has been recognized due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits. No current or deferred income tax expense or benefit has been recognized for the period ended September 30, 2008 due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits.

Gain on sale of assets. As a result of the transactions related to the formation of Abraxas Energy Partners, Abraxas Petroleum recognized a gain of $59.3 million. This gain was calculated based on the requirements of Staff Accounting Bulletin 51, (Topic 5H) based on the fact that the Company elected gain treatment as a policy and the transaction met the following criteria: (1) there were no additional broad corporate reorganizations contemplated; (2) there was not a reason to believe that the gain would not be realized, since there is no additional capital raising transaction anticipated nor was there a significant concern about the new entity’s ability to continue in existence; (3) the share price of capital raised in the private placement was objectively determined; (4) no repurchases of the new subsidiary’s units are planned; and (5) the Company acknowledges that it will consistently apply the policy, and any future transactions that might result in a loss must be recorded as a loss in the income statement.

Income (loss) from derivative contracts. We account for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. Abraxas Energy Partners has entered into a series of NYMEX–based fixed price commodity swaps. The estimated unearned value of these derivative contracts was approximately $(20.4) million as of September 30, 2008. For the nine months ended September 30, 2008, we realized a loss on these derivative contracts of $13.5 million. For the nine months ended September 30, 2008, we incurred unrealized losses on derivative contracts in place of $16.5 million.

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Minority interest. Minority interest represents the share of the net income (loss) of Abraxas Energy Partners for the quarter owned by the partners other than Abraxas Petroleum. Additionally, in accordance with generally accepted accounting principles, when cumulative losses applicable to the minority interest exceed the minority interest equity capital in the entity, such excess and any further losses applicable to the minority interest are charged to the earnings of the majority interest. If future earnings are recognized by the minority interest, such earnings will then be credited to the majority interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. During the second quarter of 2008, primarily as a result of unrealized losses on derivative contracts, losses applicable to the minority interest exceeded the minority interest equity capital by $28.2 million and, as a result $28.2 million of the minority interest loss in excess of equity was charged to earnings and is reflected as a reduction of the loss applicable to the minority interest. During the third quarter, primarily as a result of unrealized gains on derivative contracts, the $28.2 million loss in excess of the minority equity capital as of June 30, 2008 was recovered. The recovery of the loss incurred during the second quarter is reflected as a reduction in the net income applicable to the minority interest.

Recently Issued Accounting Pronouncements

Fair Value Measurements (SFAS No. 157) — In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The FASB agreed to defer the effective date of Statement 157 for one year for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. There is no deferral for financial assets and financial liabilities. We are evaluating the impact of SFAS No. 157 on our consolidated financial statements and do not expect the impact of implementation to be material.

The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) — In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after November 15, 2007. We do not expect the implementation of SFAS No. 159 to have a material impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Enhanced disclosures to improve financial reporting transparency are required and include disclosure about the location and amounts of derivative instruments in the financial statements, how derivative instruments are accounted for and how derivatives affect an entity’s financial position, financial performance and cash flows. A tabular format including the fair value of derivative instruments and their gains and losses, disclosure about credit risk-related derivative features and cross-referencing within the footnotes are also new requirements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application and comparative disclosures encouraged, but not required. We have not yet adopted SFAS No. 161. We do not believe that SFAS No. 161 will have a material impact on our financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” The statement is intended to improve financial reporting by identifying a consistent hierarchy for selecting accounting principles to be used in preparing financial statements that are prepared in conformance with generally accepted accounting principles. Unlike Statement on Auditing Standards (SAS) No. 69, “The Meaning of Present in Conformity With GAAP,” FAS No. 162 is directed to the entity rather than the auditor. The statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (PCAOB) amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with GAAP,” and is not expected to have any impact on the Company’s results of operations, financial condition or liquidity.

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In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership interest in the consolidated entity and should be reported as equity in the consolidated financial statements. The presentation of the consolidated income statement has been changed by SFAS No. 160, and consolidated net income attributable to both the parent and the noncontrolling interest is now required to be reported separately. Previously, net income attributable to the noncontrolling interest was typically reported as an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, the ownership interests in subsidiaries held by parties other than the parent must be clearly identified, labeled, and presented in the equity in the consolidated financial statements separately from the parent’s equity. Subsequent changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary should be accounted for consistently, and when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the former subsidiary must be initially measured at fair value. Expanded disclosures, including a reconciliation of equity balances of the parent and noncontrolling interest, are also required. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Prospective application is required. Due to our investment in Abraxas Energy Partners, the adoption of SFAS No. 160 could have a material impact on our financial position and results of operations, however we do not believe that it will have a material impact on our cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS No. 141(R) will have on our financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2008.

Liquidity and Capital Resources

General. The natural gas and crude oil industry is highly capital intensive and has historically been a cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following costs:

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

acquisition of interests in additional natural gas and crude oil properties; and

production and transportation facilities.

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

Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, distributions from the Partnership, sales of debt or equity securities if available to it and if an appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, cash on hand, borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it.

Working Capital (Deficit). At September 30, 2008, we had current assets of $24.6 million and current liabilities of $68.2 million resulting in a working capital deficit of approximately $43.6 million. This compares to working capital of approximately $11.3 million at December 31, 2007. Current liabilities at September 30, 2008 consisted of current portion of long-term debt consisting of $40.0 million outstanding under the Partnership’s Subordinated Credit Agreement, the current portion of derivative liability of $7.6 million, trade payables of $11.3 million, revenues due third parties of $5.4 million, accrued interest of $0.5 million and other accrued liabilities of $3.3 million. The Partnership has intended to repay its indebtedness under the Subordinated Credit Agreement with proceeds from its initial public offering. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. The Partnership has entered into discussions with the lending institutions to either extend or refinance the $40.0 million in debt under its Subordinated Credit Agreement, due January 31, 2009. There can be no assurance that the Partnership will be successful in such negotiations.

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Capital expenditures. The table below sets forth the components of our capital expenditures on a historical basis for the nine months ended September 30, 2008 and 2007.

	Nine Months Ended September 30,
	2008			2007
	(in thousands)
Expenditure category:
Acquisitions		$	137,211		$	—
Development			29,789			13,090
Facilities and other			6,568			89
Total		$	173,568		$	13,179

During the nine months ended September 30, 2008, capital expenditures were primarily for the acquisition of properties from St. Mary, the development of our existing properties and the acquisition of an office building for our corporate headquarters. For the first nine months of 2007, capital expenditures were primarily for the development of existing properties. We anticipate making capital expenditures of $55 million in 2008, excluding the cost of the St. Mary acquisition. The Partnership anticipates making capital expenditures for 2008 of $20 million which will be used primarily for the development of its current properties. These anticipated expenditures are subject to adequate cash flow from operations, availability under our Credit Facility and the Partnership’s Credit Facility and, in Abraxas’ case, distributions of available cash from the Partnership. If these sources of funding do not prove to be sufficient, we may also issue additional shares of equity securities although we may not be able to complete equity financings on terms acceptable to us, if at all. Our ability to make all of our budgeted capital expenditures will also be subject to availability of drilling rigs and other field equipment and services. Our capital expenditures could also include expenditures for the acquisition of producing properties if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. There has been a significant decline in commodity prices during the third quarter of 2008. Should the prices of natural gas and crude oil continue to decline and if our costs of operations continue to increase as a result of the scarcity of drilling rigs or if our production volumes decrease, our cash flows will decrease which may result in a reduction of the capital expenditures budget. If we decrease our capital expenditures budget, we may not be able to offset natural gas and crude oil production volumes decreases caused by natural field declines and sales of producing properties, if any.

Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities, all relating to continuing operations, are summarized in the following table:

	Nine Months Ended September 30,
	2008				2007
	(in thousands)
Net cash provided by operating activities		$	44,377			$	8,296
Net cash used in investing activities			(172,815	)			(13,179	)
Net cash provided by financing activities			115,575				18,199
Total		$	(12,863	)		$	13,316

Operating activities during the nine months ended September 30, 2008 provided $44.4 million in cash compared to providing $8.3 million in the same period in 2007. Net income plus non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $115.6 million for the first nine months of 2008 compared to $18.2 million for the same period of 2007. Funds provided in 2008 were primarily proceeds from the Partnership’s Credit Facility and Subordinated Credit Agreement in connection with the St. Mary property acquisition. Most of the funds provided in 2007 were proceeds from the issuance of common stock, proceeds from the sale of units in Abraxas Energy Partners and proceeds from our revolving credit facilities. Investing activities used $172.8 million during the nine months ended September 30, 2008 compared to using $13.2 million for the same period of 2007. Expenditures during the nine months ended September 30, 2008 were primarily for the acquisition of properties from St. Mary Land and Exploration as well as the development of our existing properties. For the first nine months of 2007, capital expenditures were primarily for the development of existing properties.

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Future Capital Resources. Abraxas’ sources of capital going forward will primarily be cash from operating activities, funding under the Credit Facility, cash on hand, distributions from the Partnership and if an appropriate opportunity presents itself, proceeds from the sale of properties. Abraxas Energy Partners’ principal sources of capital will be cash from operating activities, cash on hand borrowings under the Partnership Credit Facility, and sales of debt or equity securities if available to it. The credit markets are undergoing significant volatility and capacity constraints. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit market. Our exposure to the current credit market crisis includes our Credit Facility, the Partnership Credit Facility and the Subordinated Credit Agreement and counterparty performance risk.

Our Credit Facility and the Partnership Credit Facility are each subject to a borrowing base. Our Credit Facility matures on June 27, 2011 and the Partnership Credit Facility matures on January 31, 2013. Should current credit market volatility be prolonged for several years, future extensions of credit may contain terms that are less favorable than those in our Credit Facility and the Partnership Credit Facility. The Subordinated Credit Agreement matures on January 31, 2009. The Partnership has intended to re-pay the amounts due under this agreement with the proceeds of the IPO. However, the equity capital markets have been negatively affected in recent months. As a result, we cannot assure you that the Partnership will be successful in completing the IPO prior to the maturity of the Subordinated Credit Agreement. The Partnership has entered into discussions with the lending institutions to either extend or refinance the $40.0 million of debt under its Subordinated Credit Agreement, due January 31, 2009. There can be no assurance that the Partnership will be successful in such negotiations.

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

Oil and gas prices are also volatile and have declined significantly since June 30, 2008 and have continued to decline since the end of the quarter. Further, the decline in commodity prices has not been accompanied by a decline in the prices of goods and services that we use to drill, complete and operate our wells. The decline in commodity prices has reduced our cash flow from operations from what it would have otherwise been. To mitigate the impact of lower commodity prices on our cash flows, we have entered into commodity derivative instruments. In the event of a global recession, commodity prices may stay depressed or reduce further, thereby causing a prolonged downturn, which would further reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans.

Our cash flow from operations will also depend upon the volume of natural gas and crude oil that we produce. Unless we otherwise expand reserves, our production volumes may decline as reserves are produced. For example, in 2006, Abraxas replaced only 7% of the reserves it produced. In 2007 we replaced 219% of the reserves we produced. In the future, if an appropriate opportunity presents itself, we may sell producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful, exploration and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive natural gas or crude oil reservoirs will be found. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations, distributions from the Partnership and the amount that we are able to borrow under our credit facilities will also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 69% of Abraxas Petroleum’s and 50% of the Partnership’s total estimated proved reserves at December 31, 2007 were undeveloped. During the first nine months of 2008, we expended approximately $29.8 million for our wells and continued general well maintenance and work-overs utilizing contract work-over rigs as well as our own work-over rigs.

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Contractual Obligations

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

Long-term debt

Operating leases for office facilities

We have no off-balance sheet debt or unrecorded obligations and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of September 30, 2008:

	Payments due in twelve month period ended: (in thousands)
Contractual Obligations	Total		September 30, 2009		September 30, 2010-2011		September 30, 2012-2013		Thereafter
Long-Term Debt (1)	$	170,651	$	40,106	$	125,881	$	321	$	4,343
Interest on long-term debt (2)		18,387		7,092		10,072		659		564
Operating Leases (3)		107		107		—		—		—
Total	$	189,145	$	47,305	$	135,953	$	980	$	4,907

(1)	These amounts represent the balances outstanding under the revolving credit facility and the real estate lien note. These repayments assume that we will not draw down additional funds

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

(3)	These amounts are attributable to the lease for our previous office facility.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At September 30, 2008, our reserve for these obligations totaled $9.7 million for which no contractual commitment exists.

Off-Balance Sheet Arrangements. At September 30, 2008, we had no existing off-balance sheet arrangements, as defined under SEC regulations that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At September 30, 2008, 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 crude oil and natural gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments and borrowings under our bank credit facilities and other sources. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion.

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Long-Term Indebtedness

Long-term debt consisted of the following:


	September 30, 2008			December 31, 2007
	(in thousands)
Partnership credit facility	$	125,600		$	45,900
Partnership subordinated credit agreement		40,000			—
Real estate lien note		5,051			—
		170,651			45,900
Less current maturities		(40,106	)		—
	$	130,545		$	45,900

Senior Secured Credit Facility. On June 27, 2007, Abraxas entered into a new senior secured revolving credit facility, which we refer to as the Credit Facility. The Credit Facility has a maximum commitment of $50 million. Availability under the Credit Facility is subject to a borrowing base. The borrowing base under the Credit Facility, which is currently $6.5 million, is determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, may make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we may also request one redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our current borrowing base. Our borrowing base at September 30, 2008 of $6.5 million was determined based upon our reserves at December 31, 2007. Our borrowing base can never exceed the $50.0 million maximum commitment amount. Outstanding amounts under the Credit Facility will bear interest at (a) the greater of reference rate announced from time to time by Société Générale, and (b) the Federal Funds Rate plus 0.5 of 1%, plus in each case, (c) 0.5% - 1.5% depending on utilization of the borrowing base, or, if Abraxas elects, at the London Interbank Offered Rate plus 1.5% - 2.5%, depending on the utilization of the borrowing base. Subject to earlier termination rights and events of default, the Credit Facility’s stated maturity date will be June 27, 2011. Interest will be payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances.

Each of Abraxas’ subsidiaries other than the Partnership, Abraxas General Partner, LLC and Abraxas Energy Investments, LLC has guaranteed Abraxas’ obligations under the Credit Facility on a senior secured basis. Obligations under the Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in property and assets of Abraxas and the subsidiary guarantors comprising at least 90% of the PV-10 of their proved reserves and the related oil and gas properties.

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

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

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

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

· permit a change of control.

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Each of the general partner of the Partnership, Abraxas General Partner, LLC, which is a wholly-owned subsidiary of Abraxas and which we refer to as the GP, and Abraxas Operating, LLC, which is a wholly-owned subsidiary of the Partnership and which we refer to as the Operating Company, has guaranteed the Partnership’s obligations under the Credit Facility on a senior secured basis. Obligations under the Partnership Credit Facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in property and assets of the GP, the Partnership and the Operating Company comprising at least 90% of the PV-10 of their proved reserves and the related oil and gas properties, other than the GP’s general partner units in the Partnership.

Under the terms of the Partnership Credit Facility, the Partnership may make cash distributions if, after giving effect to such distributions, the Partnership is not in default under the Partnership Credit Facility and there is no borrowing base deficiency and provided that no such distribution shall be made using the proceeds of any advance unless the amount of the unused portion of the amount then available under the Partnership Credit Facility is greater than or equal to 10% of the lesser of the Partnership’s borrowing base (which at September 30, 2008 was $140.0 million) or the total commitment amount of the Partnership Credit Facility (which at September 30, 2008 was $300.0 million) at such time.

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

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

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

· permit a change of control.

Subordinated Credit Agreement

Date	Eurodollar Rate (LIBOR) Advances	Base Rate Advances
01/31/08 – 04/30/08	5.0%	4.0%
05/01/08 – 07/31/08	5.5%	4.5%
After 07/31/08	6.5%	5.5%

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

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

· engage in transactions with affiliates;

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

· permit a change of control.

Interest Rate Swap

Real Estate Lien Note

On May 9, 2008 the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a new building to serve as its corporate headquarters. The note bears interest at a fixed rate of 6.65%. The note is interest only for six months. At the end of six months the note is payable in monthly principal and interest installments, based on a twenty year amortization, until maturity in June 2015 at which time the balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of September 30, 2008, $5.1 million is outstanding on the note.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

As an independent crude oil and natural gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the quarter ended September 30, 2008, a 10% decline in crude oil and natural gas prices would have reduced our operating revenue, cash flow and net income by approximately $5.7 million for the quarter, however, due to the derivative contracts that the Partnership has in place, it is unlikely that a10% decline in commodity prices from their current levels would significantly impact our operating revenue, cash flow and net income.

Derivative Instrument Sensitivity

The Partnership accounts for its derivative instruments in accordance with SFAS 133 as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. In 2003 we elected not to designate derivative instruments as hedges. Accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded in current derivative income (loss).

The Partnership has enter into derivative contracts for approximately 85% of the estimated oil and gas production through December 31, 2011 from its net proved developed producing reserves. The Partnership intends to enter into hedging arrangements in the future to reduce the impact of price volatility on its cash flow. By removing a significant portion of price volatility on its future oil and gas production, the Partnership believes it will mitigate, but not eliminate, the potential effects of changing commodity gas prices on its cash flow from operations for those periods.

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The following table sets forth the Partnership’s derivative contract position at September 30, 2008:

Period Covered	Product	Volume (Production per day)	Fixed Price
Year 2008	Natural Gas	11,840 Mmbtu	$8.44
Year 2008	Crude Oil	1,105 Bbl	$84.84
Year 2009	Natural Gas	10,595 Mmbtu	$8.45
Year 2009	Crude Oil	1,000 Bbl	$83.80
Year 2010	Natural Gas	9,130 Mmbtu	$8.22
Year 2010	Crude Oil	895 Bbl	$83.26
Year 2011	Natural Gas	8,010 Mmbtu	$8.10
Year 2011	Crude Oil	810 Bbl	$86.45

We expect to sustain realized and unrealized gains and losses as a result of our hedging arrangements. For the year ended December 31, 2007, we recognized a realized gain of $1.9 million and an unrealized loss of $6.3 million, and for the three and nine months ended September 30, 2008, we recognized a realized losses of $6.0 million and $13.5 million, respectively and unrealized gains of $84.1 million and unrealized losses of $16.5 million, respectively, on our derivative contracts. The loss for nine months ended September 30, 2008 was a result of the contract prices being less than current market prices. The gain for the three months ended September 30, 2008 is due to NYMEX prices at September 30, 2008 being significantly lower than the NYMEX prices at June 30, 2008. On September 30, 2008, NYMEX futures prices were $100.64 per barrel of oil and $7.21 per MMbtu of gas. If market prices continue to be below our contract prices we will sustain realized and unrealized gains on our derivative contracts, however if market prices are higher than our contract prices we will sustain realized and unrealized losses on our derivative contracts.

Interest Rate Risk

The Partnership is subject to interest rate risk associated with borrowings under the Partnership Credit Facility and the Subordinated Credit Agreement. At September 30, 2008, the Partnership had $125.6 million in outstanding indebtedness under the Partnership Credit Facility. Outstanding amounts under the Partnership Credit Facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, and (2) the Federal Funds Rate plus 0.5%, plus in each case, (b) 0.25% to 1.25% depending on utilization of the borrowing base, or, if the Partnership elects, at the London Interbank Offered Rate plus 1.25% to 2.25%, depending on the utilization of the borrowing base. At September 30, 2008, the interest rate on the facility was 4.5%. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.3 million on an annual basis. In addition the Partnership had $40.0 million in outstanding indebtedness under the Subordinated Credit Agreement. Outstanding amounts under the Subordinated Credit Agreement bear interest at the reference rate announced from time to time by Société Générale or, if the Partnership elects, at the London Interbank Offered Rate plus various amounts. At September 30, 2008 the interest rate on the facility was 9.0%. For every percentage point that the rate rises, our interest expense would increase by approximately $400,000 on an annual basis. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. Our 2-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% reduces to $50 million on August 12, 2009. The arrangement expires on August 12, 2010.

Item 4. Controls and Procedures.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2008. Based on that evaluation, management concluded that our disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance

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that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. We believe that a control system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. Management is required to apply judgment in evaluating the cost-benefit relationship of possible controls and procedures.

There have been no changes in our internal controls over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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ABRAXAS PETROLEUM CORPORATION

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

There have been no changes in legal proceedings from that described in the Company’s Annual Report of Form 10-K for the year ended December 31, 2007 as amended, and in Note 8 in the Notes to Condensed Consolidated Financial Statements contained in Part I of this report on Form 10-Q.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing Abraxas. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for all of our oil and gas are lower than the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity in the Rocky Mountain area, have gradually widened differentials in this area.

Our derivative contract activities could result in financial losses or could reduce our cash flow.

To achieve more predictable cash flow and reduce our exposure to adverse fluctuations in the prices of oil and gas and to comply with the requirements under our credit facility, we have and expect to continue to enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized derivative contract losses. The Partnership has entered into NYMEX-based fixed price commodity swap arrangements on approximately 85% of its estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011 (including the reserves attributable to the St. Mary properties). The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity price derivative contract activities. For example, the prices utilized in our derivative instruments are NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where oil and gas are produced. The prices that we receive for our oil and gas production are lower than the relevant benchmark prices that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. As a result, our cash flow could be affected if the basis differentials widen more than we anticipate. For more information see ‘‘An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations’’. We currently do not have any basis differential hedging arrangements in place. Our cash flow could also be affected based upon the levels of our production. If production is higher than we estimate, we will have greater commodity price exposure than we intended. If production is lower than the nominal amount that is subject to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction in cash flows.

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If the prices at which the Partnership has hedged its oil and gas production are less than current market prices, its ability to maintain or increase cash distributions could be adversely affected.

The Partnership has entered into NYMEX-based fixed price commodity swap arrangements on approximately 85% of our estimated oil and gas production from its estimated net proved developed producing reserves through December 31, 2011, (including the reserves attributable to the properties acquired from St. Mary). The volume weighted average prices at which the Partnership has hedged this production are $85.54 per barrel of oil and $8.32 per MMbtu of gas. The hedged price of crude oil is less than NYMEX future prices on September 30, 2008 of $100.64 per barrel of oil. When the Partnership’s derivative contracts are at less than current market prices, the Partnership has sustained realized and unrealized losses on its derivative contracts. For the nine months ended September 30, 2008, the Partnership recognized a realized loss on derivative contracts of $13.5 million and an unrealized loss of $16.5 million. The realized loss has resulted in a decrease in cash flow from operations of the Partnership as well as negatively impacting cash available for distribution by the Partnership. The Partnership expects to continue to enter into similar hedging arrangements in the future to reduce its cash flow volatility.

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

None

Item 3. Defaults Upon Senior Securities.

None

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

None

Item 5. Other Information.

None

Item 6. Exhibits.

(a) Exhibits

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

Exhibit 31.2 Certification - Chris E. Williford, CFO

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

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

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ABRAXAS PETROLEUM CORPORATION

SIGNATURES

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

Date: November 10, 2008 By:/s/ Robert L.G. Watson

ROBERT L.G. WATSON,

President and Chief

Executive Officer

Date: November 10, 2008 By:/s/ Chris E. Williford

CHRIS E. WILLIFORD,

Executive Vice President and

Principal Accounting Officer