As filed with the Securities and Exchange Commission on March 10, 2009

Registration No. 333-144537

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 9

Form S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

ABRAXAS ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

1311

26-0144848

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification Number)

18803 Meisner Drive

San Antonio, Texas 78258

(210) 490-4788

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)



Robert L.G. Watson Chief Executive Officer		Barbara M. Stuckey President and Secretary

18803 Meisner Drive San Antonio, Texas 78258 (210) 490-4788 (Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Steven R. Jacobs

Jackson Walker L.L.P.

112 E. Pecan Street, Suite 2400

San Antonio, Texas 78205

(210) 978-7727

Elise F. Green

Jackson Walker L.L.P.

100 Congress Avenue, Suite 1100

Austin, Texas 78701

(512) 236-2000

Gregory Sichenzia

Sichenzia Ross Friedman Ference LLP

61 Broadway, 32^nd Floor

New York, NY 10006

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box. ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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 the definitions 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 ¨

Non-accelerated filer x

(Do not check if a
smaller reporting company)

Smaller reporting company ¨

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

SUBJECT TO COMPLETION, DATED MARCH 10, 2009

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PRELIMINARY PROSPECTUS

1,335,000 Common Units

LOGO

Representing Limited Partner Interests

Abraxas Energy Partners, L.P. is a limited partnership formed in May 2007 by Abraxas Petroleum Corporation. We are offering 1,335,000 common units representing limited partner interests. As part of this offering, Abraxas Petroleum Corporation, one of our principal unitholders and the parent corporation of our general partner, or its designee, has agreed to purchase from us up to 400,000 common units offered hereby that are not sold by the underwriters. For more information, please read “Certain Relationships and Related Party Transactions—Standby Purchase Agreement” and “Underwriting.” This is the initial public offering of our common units. We expect the initial public offering price to be between $6.50 and $8.50 per common unit. Our common units have been approved for listing on the NASDAQ Stock Market under the symbol “AXLP.”

Investing in our common units involves risks. Please see “Risk Factors” beginning on page 20.

These risks include the following:

•

The inability to re-finance our subordinated credit facility could have a material adverse effect on our liquidity, financial position and capital resources.

•

We may not have sufficient cash from operations to make cash distributions to holders of our units at the initial quarterly distribution rate following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements and payments to our general partner.

•

Oil and gas prices are volatile and are currently at low levels. If oil or gas prices continue to decline, our cash flow from operations will decline and we may have to lower our distributions or may not be able to pay distributions at all.

•

Our oil and gas reserves naturally decline, and we are unlikely to be able to sustain distributions at the level of our initial quarterly distribution without making capital expenditures or accretive acquisitions that maintain or grow our asset base.

•

Our exploitation and development activities will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

•

We may incur debt to pay our quarterly distributions, which may negatively affect our ability to execute our business strategy and pay future distributions.

•

Abraxas Petroleum Corporation controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and Abraxas Petroleum Corporation have conflicts of interest with us and limited fiduciary duties, and may favor their own interests to our detriment.

•

Cost reimbursements and payments to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distributions.

•

Unitholders have limited voting rights and are not entitled to elect our general partner or its Board of Directors on an annual or other continuing basis.

•

Even if unitholders are dissatisfied, they cannot remove our general partner without the consent of unitholders owning at least 66²/3% of our common units, including units owned by our general partner and its affiliates.

•

You will experience immediate and substantial dilution of $7.90 in tangible net book value per common unit.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service treats us as a corporation or we become subject to additional material entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.

•

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

In order to comply with certain U.S. laws limiting ownership of interests in oil and gas leases on federal lands, we require an owner of our units to be an “Eligible Holder.” If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units, your common units will be subject to redemption and you will have no right to vote your common units on any matter. Please read “The Partnership Agreement—Non-Eligible Holders; Redemption.”

PRICE $ PER COMMON UNIT


	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discount	$	$
Proceeds to us (before expenses)	$	$

We have granted the underwriters a 45-day option to purchase up to an additional 200,250 common units from us on the same terms and conditions set forth above to cover over-allotments. Rodman & Renshaw, LLC, on behalf of the underwriters, expects to deliver the common units on or about , 2009.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

RODMAN & RENSHAW, LLC C.K. COOPER & COMPANY

The date of this prospectus is , 2009

LOGO

TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
ABRAXAS ENERGY PARTNERS, L.P.		1
Overview		1
Our Properties		2
Formation Transactions		3
Business Strategy		4
Competitive Strengths		4
Hedging		4
Summary of Risk Factors		5
Our Relationship with Abraxas Petroleum		7
Summary of Conflicts of Interest and Fiduciary Duties		8
Principal Executive Offices and Internet Address		8
Partnership Structure		9
The Offering		11
Summary Historical and Pro Forma Financial and Operating Data		15
Non-GAAP Financial Measures		18
RISK FACTORS		20
Risks Related to Our Business		20
Risks Inherent in an Investment in Us		31
Tax Risks to Common Unitholders		37
USE OF PROCEEDS		41
CAPITALIZATION		42
DILUTION		43
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		44
Our Cash Distribution Policy		44
Our Initial Distribution Rate		46
Pro Forma Financial Information and Estimated Cash Available for Distributions		48
Assumptions and Considerations		52
How We Make Cash Distributions		59
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA		61
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		64
Overview		64
Basis of Presentation		64
How We Evaluate Our Operations		65
Outlook		69
Factors Affecting Comparability of Future Results		70
Results of Operations		72
Liquidity and Capital Resources		75
Critical Accounting Policies		81
Recent Accounting Pronouncements		84
Quantitative and Qualitative Disclosures about Market Risk		86
BUSINESS		88
General		88
Our Properties		88
Business Strategy		92
Competitive Strengths		93
Acreage		93


Productive Wells		94
Reserves Information		94
Oil and Gas Production and Sales Prices		95
Drilling Activities		96
Hedging Activity		96
Markets and Customers		96
Our Relationship with Abraxas Petroleum		97
Well Operations		97
Regulation of Oil and Gas Activities		98
Environmental Matters		101
Title to Properties		105
Competition		105
Employees		105
Office Facilities		105
Legal Proceedings		106
MANAGEMENT		107
Management of Abraxas Energy		107
Directors and Executive Officers of Our General Partner		108
Payment of Fees and Reimbursement of Expenses		110
Executive Compensation		110
Compensation Discussion and Analysis		112
Compensation of Directors		114
Long-Term Incentive Plan		115
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		119
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		122
Distributions and Payments to Our General Partner and Its Affiliates		122
Summary of Formation Transaction Documents		123
Standby Purchase Agreement		127
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		128
Conflicts of Interest		128
Fiduciary Duties		130
DESCRIPTION OF THE COMMON UNITS		133
The Units		133
Transfer Agent and Registrar		133
Transfer of Common Units		133
THE PARTNERSHIP AGREEMENT		135
Organization and Duration		135
Purpose		135
Power of Attorney		135
Capital Contributions		136
Limited Liability		136
Voting Rights		137
Issuance of Additional Securities		138
Amendments to Our Partnership Agreement		139
Prohibited Amendments		139
No Unitholder Approval		139
Opinion of Counsel and Unitholder Approval		140
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		140
Termination or Dissolution		141
Liquidation and Distribution of Proceeds		141
Withdrawal or Removal of Our General Partner		142
Transfer of General Partner Interest		142


Transfer of Ownership Interests in Our General Partner		143
Change of Management Provisions		143
Limited Call Right		143
Meetings; Voting		143
Status as Limited Partner		144
Non-Eligible Holders; Redemption		144
Indemnification		145
Payment of Fees and Reimbursement of Expenses		145
Books and Reports		145
Right to Inspect Our Books and Records		146
Registration Rights		146
UNITS ELIGIBLE FOR FUTURE SALE		146
MATERIAL TAX CONSEQUENCES		148
Summary		148
General		148
Partnership Status		148
Limited Partner Status		150
Tax Consequences of Unit Ownership		150
Tax Treatment of Operations		156
Disposition of Common Units		160
Uniformity of Units		162
Tax-Exempt Organizations and Other Investors		163
Administrative Matters		163
State, Local, Foreign and Other Tax Considerations		165
INVESTMENT IN OUR PARTNERSHIP BY EMPLOYEE BENEFIT PLANS		167
UNDERWRITING		168
VALIDITY OF THE COMMON UNITS		172
EXPERTS		172
WHERE YOU CAN FIND MORE INFORMATION		173
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		173
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A SECOND AMENDED AND RESTATED LIMITED PARTNERSHIP AGREEMENT OF ABRAXAS ENERGY PARTNERS, L.P.		A-1
APPENDIX B GLOSSARY OF CERTAIN TERMS		B-1
APPENDIX C APPLICATION FOR TRANSFER OF COMMON UNITS		C-1
APPENDIX D RESERVE ENGINEER’S LETTER		D-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

iii

Until , 2009 (25 days after the date of this prospectus) all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

We have included a glossary of some of the terms used in this prospectus in Appendix B. References to “Abraxas Energy,” “we,” “us,” “our” and similar references or like terms refer to Abraxas Energy Partners, L.P. and its subsidiary Abraxas Operating, LLC, which we refer to as “Abraxas Operating.” References to “Abraxas Petroleum” refer to Abraxas Petroleum Corporation (NASDAQ: “AXAS”) and its subsidiaries, other than Abraxas Energy Partners, L.P. References to “our general partner” refer to Abraxas General Partner, LLC, our general partner, and references to “Abraxas Investments” refer to Abraxas Energy Investments, LLC. References to “St. Mary” refer to St. Mary Land & Exploration Company and references to “our assets” or “our properties” refer to the oil and gas properties contributed to us by Abraxas Petroleum in May 2007 and the oil and gas properties acquired from St. Mary on January 31, 2008. The terms “pro forma” or “on a pro forma basis” refer to what our business might have looked like if the transaction defined as the “St. Mary Acquisition” had occurred at the times indicated or as of the beginning of the period indicated, and where specifically indicated, also give effect to this offering and the application of the net proceeds we expect to receive as described under “Use of Proceeds.”

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements. Unless otherwise indicated, the information presented in this prospectus assumes an initial public offering price of $7.50 per common unit, that the underwriters’ over-allotment option to purchase additional common units is not exercised and that Abraxas Petroleum does not purchase any common units in this offering. You should read “Risk Factors” beginning on page 20 for information about important factors that you should consider carefully before buying our common units. Our reserve information is derived from a reserve report prepared by DeGolyer and MacNaughton, an independent engineering firm, for approximately 93% of the standardized measure of our properties. Reserve estimates for our remaining properties were prepared by Abraxas Petroleum personnel. The properties included in the reserve report prepared by DeGolyer and MacNaughton were selected by us. For more information, see “Business—Reserves Information.” Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil.

ABRAXAS ENERGY PARTNERS, L.P.

Overview

We are a Delaware limited partnership formed by Abraxas Petroleum in May 2007 to exploit, develop, produce and acquire oil and gas properties. Our assets consist primarily of producing and non-producing properties located in the Rocky Mountain, Mid-Continent, Permian Basin and Gulf Coast regions of the United States.

At December 31, 2008, our oil and gas properties had estimated net proved reserves of 110.3 Bcfe, of which 76% were gas, with a standardized measure of $118.6 million. Our net proved reserves as of December 31, 2008 were 61% proved developed and 39% proved undeveloped. At December 31, 2008, we owned an average working interest of 18% in 1,639 gross (293 net) producing wells that produced 8.2 net Bcfe during 2008. Our properties are located in mature fields that exhibit relatively long-lived production, with a reserve to production index of 13.4 years (8.2 years for our proved developed properties) based on our estimated reserves as of December 31, 2008 and our production for the year ended December 31, 2008. Approximately 92% of the estimated ultimate recovery of our proved developed reserves as of December 31, 2008 had been produced. Abraxas Petroleum operates properties comprising over 75% of our estimated proved reserves at December 31, 2008. We have identified 226 drilling locations, of which 129 were classified as proved undeveloped as of December 31, 2008, which we believe provides us with a multi-year inventory of drilling opportunities.

The following table sets forth summary historical information about our properties. The reserve information is as of December 31, 2008 and the average daily production information is for the year ended December 31, 2008. The producing well information is as of December 31, 2008.


	Estimated Net Proved Reserves (Bcfe) As of December 31, 2008(1)			Standardized Measure (1) (in millions)		Average Daily Production for the Year Ended December 31, 2008			Producing Wells As of December 31, 2008
	Developed	Undeveloped	Total	Standardized Measure (1) (in millions)		Mcfepd	%		Gross	Net
Rocky Mountain	23.5	0.8	24.3	$	33.4	6,020	27	%	861	91
Mid-Continent	12.9	5.4	18.3		20.0	3,638	16	%	600	103
Permian Basin	14.6	19.2	33.8		34.1	6,908	31	%	114	52
Gulf Coast	16.5	17.4	33.9		31.1	5,887	26	%	64	47

Total	67.5	42.8	110.3	$	118.6	22,453	100	%	1,639	293

(1)

Standardized measure means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, calculated in accordance with Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities”. Because we are a limited partnership that allocates our taxable income to our unitholders, no provisions for federal or state income taxes have been provided for in the calculation of standardized measure. Our estimated net proved reserves and standardized measure as of December 31, 2008 were determined using NYMEX prices of $44.60 per barrel for oil and $5.62 per MMbtu of gas and do not include adjustments for our derivative contracts.

Our Properties

Our properties are located in the Rocky Mountain, Mid-Continent, Permian Basin and Gulf Coast regions of the United States.

In May 2007, Abraxas Petroleum contributed properties located in the Permian Basin of West Texas and the Gulf Coast Basin of South Texas to us. The majority of these properties were discovered by Abraxas Petroleum during the past decade or by major oil companies 40 to 50 years ago, some of which have been subsequently redeveloped by Abraxas Petroleum.

On January 31, 2008, we acquired oil and gas properties from St. Mary for $126.0 million. The properties included interests in 1,464 gross (214 net) wells located in a number of basins throughout the central portion of the United States, principally in the Rocky Mountain and Mid-Continent regions. We borrowed $79.7 million under our credit facility and $50.0 million under a new subordinated credit facility to finance this acquisition and pay fees and expenses incurred in connection with the acquisition. We sometimes refer to the acquisition of the properties from St. Mary and the borrowings incurred by us to finance this acquisition as the St. Mary Acquisition.

Our Rocky Mountain properties consist of the following:

•

Northern Rockies—Our properties in the Northern Rockies are located in the Williston Basin of North Dakota, South Dakota and Montana and consist of wells that produce oil from Paleozoic-aged carbonate reservoirs from the Madison formation at 8,000 feet down to the Red River formation at 12,000 feet.

•

Southern Rockies—Our properties in the Southern Rockies are located in the Green River, Powder River and Uinta Basins of Wyoming, Colorado and Utah and consist of wells that produce oil from Cretaceous-aged fractured shales in the Niobrara formation and oil and gas from Cretaceous-aged sandstones in the Muddy and Frontier formations. Well depths range from 7,000 feet down to 10,000 feet.

Our Mid-Continent properties consist of the following:

•

Arkoma Basin—Our properties in the Arkoma Basin are located in Oklahoma and Arkansas and consist of wells that mainly produce gas from Hartshorne coals at 3,000 feet.

•

Anadarko Basin—Our properties in the Anadarko Basin are located in Oklahoma and the Texas Panhandle and consist of wells that mainly produce gas from Pennsylvanian-aged sandstones (Atoka/Morrow) from depths as deep as 18,000 feet.

•

ARK-LA-TEX—Our properties in the ARK-LA-TEX region principally produce from the East Texas/North Louisiana Basins and include wells that produce oil and gas from various formations.

Our Permian Basin properties consist of the following:

•

ROC Complex—Our properties in the ROC Complex are located in Pecos, Reeves and Ward Counties and consist of wells that produce oil and gas from multiple stacked formations from the Bell Canyon at 5,000 feet down to the Ellenburger at 16,000 feet. Our core set of properties in this complex were acquired in 1994 and subsequently developed by Abraxas Petroleum.

•

Oates SW—Our properties in the Oates SW area are located in Pecos County and consist of wells that produce gas from the Devonian formation at a depth of approximately 13,500 feet. Abraxas Petroleum began redeveloping this area in 2001 with the use of horizontal drilling technology.

•

Permian Basin—Other—Our other properties in the Permian Basin principally produce from the relatively shallow Canyon and Yates-Seven Rivers-Queen sands.

Our Gulf Coast properties consist of the following:

•

Edwards—Our fields in the Edwards trend were redeveloped by Abraxas Petroleum in 1997 through the use of horizontal drilling technology. Our wells produce gas from the Edwards formation at a depth of approximately 13,500 feet.

•

Portilla—The Portilla field was discovered in 1950 by The Superior Oil Company, predecessor to Mobil Oil Corporation, and consists of wells that produce oil and gas from the Frio sands and the deeper Vicksburg from depths of approximately 7,000 to 9,000 feet. Abraxas Petroleum acquired this field in 1993.

•

Gulf Coast—Other—Our other properties in the Gulf Coast principally produce from the Cotton Valley and the Haynesville formations.

Formation Transactions

In May 2007, we entered into the following transactions, which we refer to as the Formation Transactions:

•

Abraxas Petroleum contributed properties to Abraxas Operating;

•

Abraxas Investments and our general partner contributed all of the membership interests in Abraxas Operating to us in exchange for the issuance of an aggregate of 5,131,959 common units and 227,232 general partner units to Abraxas Investments and our general partner, respectively;

•

we borrowed $35.0 million under our credit facility; and

•

we issued and sold 6,002,408 of our common units to certain private investors, whom we refer to as the Private Investors, in consideration for gross proceeds of approximately $100.0 million.

The gross proceeds from the Formation Transactions, together with $22.5 million received by Abraxas Petroleum in a private placement of its common stock, were $157.5 million. These proceeds were used as follows:

•

$139.3 million was used to refinance and repay Abraxas Petroleum’s Floating Rate Secured Notes due 2009 (including a call premium and accrued and unpaid interest of $14.3 million);

•

$0.9 million was used to repay indebtedness under Abraxas Petroleum’s credit facility;

•

$10.3 million was used to pay fees and expenses, including placement fees to A.G. Edwards & Sons, Inc. of $8.6 million and legal and accounting fees of $1.7 million; and

•

$7.0 million was used to make a distribution of excess capital to Abraxas Petroleum.

The Private Investors are identified in “Security Ownership of Certain Beneficial Owners and Management.”

Business Strategy

Our primary business objective is to provide stability and growth in our cash distributions per unit over time. We intend to accomplish this objective by executing the following business strategies:

•

Maintaining an inventory of drilling locations which are sufficient, when drilled and completed, to allow us to maintain our current production levels for at least three years;

•

Making accretive acquisitions of relatively long-lived reserves with relatively low-risk exploitation and development opportunities;

•

Using our technical expertise to exploit and develop our existing assets and to maximize reserve recovery; and

•

Reducing cash flow volatility through commodity price hedging.

Competitive Strengths

We believe that the following strengths position us well to execute our strategies:

•

Our properties are characterized by relatively predictable, long-lived production, with a reserve to production index of 13.4 years (8.2 years for our proved developed properties) based on our estimated reserves as of December 31, 2008 and our production for the year ended December 31, 2008;

•

We have a substantial inventory of relatively low to moderate risk, proved undeveloped and other identified drilling locations;

•

Our management team has a proven acquisition, exploitation and development track record;

•

Over 75% of our estimated proved reserves at December 31, 2008 are operated by Abraxas Petroleum, which is an efficient, low-cost operator;

•

Abraxas Petroleum has an aligned and vested interest in our success due to its substantial ownership in us; and

•

Our relationship with Abraxas Petroleum will provide us with additional operational, technical and other expertise.

Hedging

We are currently a party to derivative contracts, which we sometimes refer to as hedging arrangements, and we intend to enter into hedging arrangements in the future, to reduce the impact of oil and gas price volatility on our cash flow from operations. At December 31, 2008 and continuing through December 2011, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated oil and gas

production from our estimated net proved developed producing reserves at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas which are significantly higher than market prices on March 2, 2009 of $44.76 per barrel of oil and $4.20 per MMbtu of gas. By removing a significant portion of price volatility from our oil and gas production for the next three years, we believe we have mitigated, but not eliminated, the potential effects of changing oil and gas prices on our cash flow from operations for those periods. Because the prices at which we have hedged our production are significantly higher than current prices, we will realize greater cash flow on the portion of production that we have hedged as a result of these higher contract prices than we would have without these arrangements. Conversely, we will sustain realized and unrealized losses on our derivative contracts if prevailing market prices for our oil and gas are higher than our contract prices. We have elected out of hedge accounting as prescribed by applicable accounting rules. For more information on our hedging arrangements, please read “Management’s Discussion & Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives” and “—Quantitative and Qualitative Disclosures about Market Risk—Hedging Activity and Sensitivity.” Please read also “Risk Factors—Risks Related to Our Business” for a discussion of certain risk factors relating to our hedging activities.

Summary of Risk Factors

An investment in our common units involves risks associated with our business, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not comprehensive. Please read carefully these and other risks under “Risk Factors” beginning on page 20.

Risks Related to Our Business

•

The inability to re-finance our subordinated credit facility could have a material adverse effect on our liquidity, financial position and capital resources.

•

The assumptions underlying our estimated cash available for distribution which we present in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

•

Oil and gas prices are volatile and currently at low levels. If oil or gas prices continue to decline, our cash flow from operations will decline and we may have to lower our distributions or may not be able to pay distributions at all.

•

A material portion of our production is currently concentrated in two wells. If production from these wells declines more than we anticipate, we may have to decrease our distributions to you.

•

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

•

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 and could affect our ability to pay cash distributions to you.

•

The estimated proved oil and gas reserves we present are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

•

We may incur debt to pay our quarterly distributions, which may negatively affect our ability to execute our business strategy and pay future distributions.

•

Our hedging activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions.

•

If the prices at which we hedge our oil and gas production are less than prevailing market prices, our ability to maintain or increase cash distributions could be adversely affected.

•

We may incur costs for plugging and abandoning wells and environmental liabilities relating to our properties.

Risks Inherent in an Investment in Us

•

Abraxas Petroleum controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and Abraxas Petroleum have conflicts of interest with us and limited fiduciary duties, and may favor their own interests to our detriment.

•

Abraxas Petroleum is not limited in its ability to compete with us, which could affect our ability to acquire additional assets.

•

Cost reimbursements and payments to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distributions.

•

Unitholders have limited voting rights and are not entitled to elect our general partner or its Board of Directors on an annual or other continuing basis.

•

Our partnership agreement limits the fiduciary duties owed by our general partner to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

•

Even if unitholders are dissatisfied, they cannot remove our general partner without the consent of unitholders owning at least 66²/₃% of our common units, including units owned by our general partner and its affiliates.

•

Control of our general partner may be transferred to a third party without unitholder consent and the successor owner could replace our board of directors and officers.

•

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our units, other than our general partner and its affiliates, which may limit the ability of significant unitholders to influence the manner or direction of management.

•

You will experience immediate and substantial dilution of $7.90 in tangible net book value per common unit.

•

We may issue an unlimited number of additional units, including units that are senior to the common units, without your approval, which would dilute your existing ownership interests.

•

Common units held by persons who are not Eligible Holders will be subject to the possibility of redemption.

•

Unitholders may have limited liquidity for their units, a trading market may not develop for the units, and you may not be able to resell your units at the initial public offering price.

Tax Risks to Common Unitholders

•

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS treats us as a corporation or we become subject to additional material entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.

•

An IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

•

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

•

It is possible that all or a portion of gain or loss on disposition of common units may be recognized as ordinary income, subject to your marginal rate.

•

Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

•

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

•

We will be deemed to have terminated as a partnership for federal tax purposes if there is a sale or exchange of 50% or more of our interests within a twelve-month period.

•

Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.

•

Certain federal income tax deductions currently available with respect to oil and gas drilling and development may be eliminated as a result of future legislation. Additionally, federal income tax rates may be increased for certain investors, in which case any income resulting from an investment in us may result in higher federal income tax payments.

Our Relationship with Abraxas Petroleum

Our general partner, Abraxas General Partner, LLC, is a wholly-owned subsidiary of Abraxas Petroleum and has sole responsibility for conducting our business and managing our operations. Some of the executive officers and directors of Abraxas Petroleum also serve as executive officers and directors of our general partner. The Board of Directors of our general partner currently consists of six members, with three directors meeting the independence standards established by the NASDAQ Stock Market. For more information about these individuals, please read “Management—Directors and Executive Officers of Our General Partner.”

Upon the completion of this offering, Abraxas Petroleum will beneficially own a 2% general partner interest and a 40.1% limited partner interest in us, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and that Abraxas Petroleum does not purchase any common units in this offering. We have entered into a standby purchase agreement with Abraxas Petroleum under which Abraxas Petroleum, or its designee, has agreed to purchase from us up to 400,000 common units offered hereby that are not sold by the underwriters. For more information, please read “Certain Relationships and Related Party Transactions—Standby Purchase Agreement” and “Underwriting.” We have entered into an omnibus agreement with Abraxas Petroleum and our general partner regarding certain payment and indemnification matters, including the payment of plugging and abandonment costs and environmental liabilities, and an operating agreement regarding the operation of our properties. For more information, please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “—Operating Agreement.” While we believe that our relationship with Abraxas Petroleum is a

significant competitive strength, it is also a source of potential conflicts. For example, Abraxas Petroleum is not prohibited from competing with us and may acquire or dispose of assets in the future without any obligation to offer us the opportunity to purchase those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Abraxas Petroleum is a publicly traded independent energy company engaged primarily in the acquisition, development, exploration and production of oil and gas in Texas, the Mid-Continent and the Rocky Mountain regions of the United States. Its principal means of growth has been through the acquisition and subsequent exploitation and development of producing properties. As a result of its historical acquisition activities, Abraxas Petroleum currently has a number of development opportunities on its existing properties. In addition, Abraxas Petroleum intends to expand upon its development activities with complementary exploration projects in its core areas of operation and through acquisitions. As of December 31, 2008, Abraxas Petroleum had 40.4 Bcfe of estimated net proved reserves principally in Texas, of which 65% were classified as proved undeveloped. In addition to these proved reserves, Abraxas Petroleum has acreage in the West Texas Woodford/Barnett Shale Play (approximately 12,000 gross acres) and in the Mowry Shale/Turner Sand Play (approximately 33,000 gross acres) located in the southern Powder River Basin of east central Wyoming.

Summary of Conflicts of Interest and Fiduciary Duties

General. Our general partner has a legal duty to manage us in a manner beneficial to holders of our common units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by Abraxas Petroleum, the officers and directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to Abraxas Petroleum. As a result of these relationships, conflicts of interest exist and may arise in the future between us and holders of our common units, on the one hand, and our general partner and Abraxas Petroleum, on the other.

Partnership Agreement Modifications to Fiduciary Duties. Our partnership agreement, among other things, limits the liability and reduces the fiduciary duties of our general partner to holders of our common units, and restricts the remedies available to holders of our common units for actions that might otherwise constitute a breach of the fiduciary duties owed by our general partner to holders of our common units. Our partnership agreement also provides that Abraxas Petroleum is neither restricted from competing with us, nor is it under any obligation to offer sales of its producing properties to us. By purchasing a common unit, you will be deemed to have agreed to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units will consent to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.” Please read also “The Partnership Agreement.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 18803 Meisner Drive, San Antonio, Texas 78258 and our telephone number is (210) 490-4788. Our website will be located at www.abraxasenergypartners.com. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.

PARTNERSHIP STRUCTURE

We are a Delaware limited partnership that was formed in May 2007. We are a holding company, and our operating assets are owned by our operating subsidiary, Abraxas Operating. At the closing of this initial public offering, our ownership structure will be as follows:


	Assumes no exercise of the underwriters’ over- allotment option and that Abraxas Petroleum does not purchase any units in this offering			Assumes Abraxas Petroleum purchases all of the common units it has agreed to purchase in this offering			Assumes full exercise of the underwriters’ over- allotment option and that Abraxas Petroleum does not purchase units in this offering
	Number of Units	Percentage		Number of Units	Percentage		Number of Units	Percentage
Public common units	1,335,000	10.5	%	935,000	7.3	%	1,535,250	11.8	%
Private Investors’ common units	6,009,987	47.0	%	6,009,987	47.0	%	6,009,987	46.3	%
Abraxas Petroleum and affiliates:
Common units	5,131,959	40.1	%	5,531,959	43.3	%	5,131,959	39.5	%
General Partner units	256,754	2.0	%	256,754	2.0	%	260,840	2.0	%
Restricted common units	52,000	0.4	%	52,000	0.4	%	52,000	0.4	%

Total	12,785,700	100	%	12,785,700	100	%	12,990,036	100	%

The following diagram of our organizational structure assumes sale of all the common units offered hereby and the underwriters do not exercise their over-allotment option to purchase additional common units and that Abraxas Petroleum does not purchase any common units in this offering.

LOGO

(1)	In connection with this offering, our general partner will be purchasing 29,522 additional general partner units, for a total of 256,754 general partner units, to maintain a 2% general partner interest in us.

(2)	Represents restricted units that we granted on January 2, 2009 to our general partner’s executive officers and outside directors and to certain executive officers and key employees of Abraxas Petroleum under our long-term incentive plan.

THE OFFERING

Common units offered to the public

We are offering a total of 1,335,000 common units, or 1,535,250 common units if the underwriters exercise their over-allotment option to purchase additional common units in full. As part of this offering, Abraxas Petroleum has agreed to purchase from us up to 400,000 common units offered hereby that are not sold by the underwriters. For more information, please read “Certain Relationships and Related Party Transactions—Standby Purchase Agreement” and “Underwriting.”

Units outstanding after this offering

12,528,946 common units, representing a 98% limited partner interest in us. Our general partner will own 256,754 general partner units, representing a 2% general partner interest in us after making a proportionate capital contribution of $0.2 million. Our total units outstanding after this offering will be 12,785,700 units.

If the underwriters exercise their over-allotment option to purchase additional units in full, there will be 12,729,196 common units and 260,840 general partner units, or a total of 12,990,036 units outstanding.

Use of proceeds

We intend to use the net proceeds of approximately $9.3 million from this offering, after deducting approximately $0.9 million for underwriting discounts and offering expenses to be paid with proceeds from this offering, together with our general partner’s proportionate capital contribution of $0.2 million and any proceeds from the exercise of the underwriters’ over-allotment option to partially repay the indebtedness outstanding under our subordinated credit facility.

At March 2, 2009, the principal balance outstanding under our subordinated credit facility was $40.0 million. The maturity date of our subordinated credit facility is July 1, 2009. We intend to re-finance this indebtedness prior to its scheduled maturity; however there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial advisor to assist us in this re-financing.

We have previously paid approximately $1.8 million in offering expenses out of available cash.

Cash distributions

We expect to make an initial quarterly distribution of $0.375 per unit ($1.50 per unit on an annualized basis) on all of our units after completion of this offering, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. We currently make quarterly distributions of $0.375 per unit ($1.50 per unit on an annualized basis) to our unitholders. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions—Our Initial Distribution Rate.”

We expect to pay a prorated distribution for the first quarter during which we are a publicly traded partnership. We will pay the prorated distribution for the period from the first day our common units are publicly traded to and including June 30, 2009. We expect to pay this cash distribution on or before August 14, 2009. All unitholders, including our general partner, will receive the same cash distribution per unit; none of our unitholders have any incentive distribution rights, and we do not have subordinated or preferred units. We only have one class of common units.

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of certain terms attached to this prospectus as Appendix B. Within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2009, we will distribute our available cash to unitholders of record on the applicable record date.

The amount of pro forma available cash generated during the year ended December 31, 2008 would have been sufficient to allow us to pay the full initial quarterly distribution for four quarters on all of our units. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2008, please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Consolidated Available Cash for the Year Ended December 31, 2008.”

We believe that, based on estimates contained in the assumptions listed under the caption “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Month Period Ending June 30, 2010” and “—Assumptions and Considerations,” we will have sufficient cash available for distribution to pay the initial quarterly distribution for the four quarters ending June 30, 2010 at an initial quarterly distribution rate of $0.375 per unit ($1.50 per unit on an annualized basis) on all of our units.

Issuance of additional units

We can issue an unlimited number of additional units, including units ranking senior to our common units, on the terms and conditions determined by our general partner without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Securities.”

Limited voting rights

Our general partner will manage our business. Unlike the stockholders of a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding common units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of

approximately 41.4% of our common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and that Abraxas Petroleum does not purchase any common units in this offering. This will give Abraxas Petroleum the ability to prevent our general partner’s involuntary removal. Please read “The Partnership Agreement—Voting Rights.”

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price. Please read “The Partnership Agreement—Limited Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2011, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.50 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.30 per unit. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

Material tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Agreement to be bound by the Partnership Agreement

By purchasing a common unit, you will be deemed to have agreed to be bound by the terms of our partnership agreement.

Exchange listing and trading symbol

Our common units have been approved for listing on the NASDAQ Stock Market under the symbol “AXLP.”

Private investors’ resale shelf registration statement

In addition to this offering, we intend to file a shelf registration statement for the resale of 6,009,987 common units held by the Private Investors pursuant to the terms of a registration rights agreement entered into by us and the Private Investors on May 25, 2007, as amended. For a discussion of this agreement, please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Registration Rights Agreement.” Please also read “Units Eligible for Future Sale.”

Eligible Holders and redemption

We currently own interests in federal leases, which may require unitholders or their transferees to certify or re-certify to us their status as Eligible Holders. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. If a unitholder or transferee of a unitholder, as the case may be, does not properly complete a certification or re-certification

as to its status as an Eligible Holder, or if such unitholder or transferee is not an Eligible Holder, such person will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we have the right to redeem such units at a price which is equal to the average daily closing price per common unit for the 20 consecutive trading days prior to the date of determination of the price at which such units would be redeemed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units—Transfer of Common Units” and “The Partnership Agreement—Non-Eligible Holders; Redemption.”

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows summary historical financial and operating data of Abraxas Petroleum and our pro forma and historical financial data for the periods and as of the dates indicated. The summary historical financial data of Abraxas Petroleum as of December 31, 2006 and for the year ended December 31, 2006 and for the period from January 1 to May 24, 2007 and the summary historical financial data of Abraxas Energy as of December 31, 2007 and 2008 and for the period from May 25 to December 31, 2007 and for the year ended December 31, 2008 are derived from the audited consolidated financial statements included elsewhere in this prospectus. The financial condition and results of operations of Abraxas Petroleum for the periods up to May 24, 2007 are referred to in this prospectus as “Predecessor,” and the financial condition and results of operations for periods subsequent to May 24, 2007 are referred to as “Successor” and represent only those of the Abraxas Energy. The summary pro forma financial data of Abraxas Energy for the year ended December 31, 2008 are derived from the unaudited pro forma financial statements included elsewhere in this prospectus and give effect to:

•

The acquisition of certain oil and gas properties from St. Mary and our related borrowings of $129.7 million, which occurred on January 31, 2008.

•

The completion of this offering and the use of proceeds from this offering as described in “Use of Proceeds.”

The unaudited pro forma statement of operations data for the year ended December 31, 2008 assume the St. Mary Acquisition and this offering occurred on January 1, 2008. The unaudited pro forma balance sheet as of December 31, 2008 assumes that this offering occurred on December 31, 2008. This pro forma financial data does not reflect incremental expenses we expect to incur as a publicly traded partnership of $0.8 million per year.

You should read the following table in conjunction with “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the unaudited pro forma and audited historical consolidated financial statements of Abraxas Energy and the notes thereto, the audited historical consolidated financial statements of Abraxas Petroleum and the notes thereto and the audited historical statements of revenues and direct operating expenses relating to the properties acquired from St. Mary included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information. The following table includes Adjusted EBITDA, which is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, which we refer to as GAAP, please see “—Non-GAAP Financial Measures.”

Summary Historical and Unaudited Pro Forma Financial Data


	Historical												Pro Forma (unaudited)
	Predecessor						Successor						Pro Forma (unaudited)
	Abraxas Petroleum						Abraxas Energy						Abraxas Energy
										Year Ended December 31,			St. Mary Acquisition			After Offering
	Years Ended December 31,			January 1 - May 24 2007			May 25 - December 31, 2007			Year Ended December 31,			Year Ended December 31,
	2006			January 1 - May 24 2007			May 25 - December 31, 2007			2008			2008
	(In thousands, except per share/unit data)
Total operating revenue	$	51,077		$	19,305		$	22,148		$	83,391		$	87,045		$	87,045
Lease operating and production taxes		11,776			4,757			5,136			22,577			23,621			23,621
Depreciation, depletion and amortization		14,939			5,773			7,039			20,063			20,955			20,955
Ceiling-test impairment		—			—			—			97,121			97,121			97,121
General and administrative		5,160			1,867			987			2,657			2,657			2,657
Net interest expense		16,738			6,371			1,774			10,181			10,704			10,116
Amortization of deferred financing fees		1,591			632			121			988			1,054			1,054
Financing fees		—			—			—			359			359			359
Loss (gain) on derivative contracts		(646	)		218			4,125			(28,333	)		(28,333	)		(28,333	)
Loss on debt extinguishment		—			—			6,455			—			—			—
Other		—			—			—			1,105			1,105			1,105

Income (loss)	$	700		$	(608	)	$	(3,489	)	$	(43,327	)	$	(42,198	)	$	(41,610	)
Income (loss) per common share/unit:
Basic	$	0.02		$	(0.01	)	$	(0.31	)	$	(3.81	)	$	(3.30	)	$	(3.25	)
Diluted	$	0.02		$	(0.01	)	$	(0.31	)	$	(3.81	)	$	(3.30	)	$	(3.25	)
Other Financial Data:
Adjusted EBITDA(1)	$	33,887		$	12,305		$	18,031		$	47,166		$	49,776		$	49,776
Capital expenditures	$	26,346		$	6,622		$	14,086		$	131,900
Net cash provided by (used in):
Operating activities	$	15,561		$	10,150		$	5,466		$	30,474
Investing activities	$	(14,102	)	$	(6,622	)	$	(14,086	)	$	(131,900	)
Financing activities	$	(1,458	)	$	(1,742	)	$	10,379		$	101,591

(1)	For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, which we refer to as GAAP, please see “—Non-GAAP Financial Measures.”


	Predecessor			Successor		Successor			Pro Forma After Offering (unaudited)
	Abraxas Petroleum			Abraxas Energy		Abraxas Energy
	At December 31,					At December 30,
	2006			2007		2008
	(In thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	(3,719	)	$	3,740	$	(14,595	)	$	(7,062	)
Total assets		116,940			105,703		169,240			169,240
Current maturities of long-term debt		—			—		40,000			32,467
Long-term debt		127,614			45,900		125,600			125,600
Stockholders’/partners’ equity (deficit)		(22,165	)		49,688		(12,492	)		(4,959	)

Summary Historical and Pro Forma Operating and Reserve Data

The following tables show summary historical operating and reserve data of Abraxas Petroleum, and our historical and pro forma operating and reserve data for the periods and as of the dates indicated, giving effect to and reflecting the St. Mary Acquisition as if it had occurred on January 1, 2008. The information in these tables should be read in conjunction with “Unaudited Pro Forma Financial Statements,” “Risk Factors” beginning on page 20, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Appendix D.


	Predecessor				Successor				Pro Forma
	Abraxas Petroleum				Abraxas Energy				Abraxas Energy
	Year Ended December 31,		January 1 - May 24, 2007		May 25 - December 31, 2007		Year Ended December 31,		Year Ended December 31,
	2006		January 1 - May 24, 2007		May 25 - December 31, 2007		2008		2008
Production:
Oil (MBbls)		200		79		78		452		484
Gas (MMcf)		6,515		2,291		2,753		5,505		5,678
Total (MMcfe)		7,718		2,765		3,219		8,218		8,581
Average daily production (Mcfepd)		21,144		19,198		14,566		22,453		23,447

Average Sales Price:
Oil ($/Bbl)	$	62.10	$	56.49	$	69.78	$	79.14	$	79.25
Gas ($/Mcf)	$	5.77	$	6.22	$	6.80	$	6.97	$	6.94
Gas equivalents ($/Mcfe)	$	6.48	$	6.77	$	7.50	$	9.02	$	9.06

Operating Expenses ($/Mcfe)	$	1.52	$	1.72	$	1.60	$	2.75	$	2.75


	Predecessor			Successor
	Abraxas Petroleum			Abraxas Energy
	As of December 31,
	2006			2007			2008
Reserve Data:
Oil (MBbls)		2,756			1,206		4,479
Gas (MMcf)		70,333			65,460		83,406
Total (MMcfe)		86,872			72,694		110,278
Proved developed reserves as a % of total		55	%		50	%	61	%
Standardized measure (in thousands)(1)	$	156,844		$	147,751		118,570
Proved developed reserves as a % of total		76	%		74	%	89	%

(1)

Non-GAAP Financial Measures

In this prospectus, we include Adjusted EBITDA, which is a non-GAAP financial measure. We provide a reconciliation of Adjusted EBITDA to net income and net cash provided by operations, its most directly comparable financial measures calculated and presented in accordance with GAAP.

We define Adjusted EBITDA as net income (loss) plus:

•

Net interest expense;

•

Depreciation, depletion and amortization;

•

Amortization of deferred financing fees;

•

Unrealized loss (gain) on derivative contracts;

•

Ceiling-test impairment;

•

Income tax provision;

•

(Gain) loss on sale of assets; and

•

Loss on debt extinguishment.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; and

•

the ability of our assets to generate sufficient cash:

•

to fund maintenance capital expenditures; and

•

to pay cash distributions to our unitholders.

Adjusted EBITDA is also a quantitative standard used throughout the investment community with respect to performance of publicly-traded partnerships.

Our Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, net cash provided by operations or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations.

The following table presents a reconciliation of our consolidated net income (loss) and net cash provided by (used in) operations to Adjusted EBITDA.


	Predecessor						Successor			Successor			Pro Forma (unaudited)
	Abraxas Petroleum						Abraxas Energy			Abraxas Energy			Abraxas Energy
													St. Mary Acquisition			After Offering
	Year Ended December 31,			January 1 - May 24, 2007			May 25 - December 31, 2007			Year Ended December 31, 2008			Year Ended December 31,
	2006			January 1 - May 24, 2007			May 25 - December 31, 2007			Year Ended December 31, 2008			2008
	(In thousands)
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	700		$	(608	)	$	(3,489	)	$	(43,327	)	$	(42,198	)	$	(41,610	)
Add (deduct):
Net interest expense		16,738			6,371			1,774			10,181			10,704			10,116
Depreciation, depletion and amortization		14,939			5,773			7,039			20,063			20,955			20,955
Amortization of deferred financing fees		1,591			632			121			988			1,054			1,054
Unrealized loss (gain) on derivative contracts		(81	)		137			6,131			(37,860	)		(37,860	)		(37,860	)
Ceiling-test impairment		—			—			—			97,121			97,121			97,121
Loss on debt extinguishment		—			—			6,455			—			—			—

Adjusted EBITDA	$	33,887		$	12,305		$	18,031		$	47,166		$	49,776		$	49,776

Reconciliation of net cash provided by (used in) operations to Adjusted EBITDA:
Net cash provided by (used in) operations	$	15,561		$	10,150		$	5,466		$	30,474
Add (deduct):
Cash interest expense and other financing costs, net		16,605			6,394			1,675			9,715
Equity-based compensation		(998	)		(276	)		—			(242	)
Changes in working capital		2,892			3,918			(4,428	)		2,816
Unrealized loss (gain) on derivative contracts		(81	)		137			6,131			(37,860	)
Ceiling-test impairment		—			—			—			97,121
Other		(92	)		(8,018	)		9,187			(54,858	)

Adjusted EBITDA	$	33,887		$	12,305		$	18,031		$	47,166

RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we would not be able to pay distributions on our units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

The inability to re-finance our subordinated credit facility could have a material adverse effect on our liquidity, financial position and capital resources.

Our subordinated credit facility matures on July 1, 2009. We intend to re-finance this indebtedness prior to its scheduled maturity; however there can be no assurance that we will be successful in this effort. In addition, under our subordinated credit facility, an event of default would occur if we fail to receive $20.0 million of proceeds from an equity issuance on or before April 30, 2009. We have engaged an exclusive financial advisor to re-finance the $40.0 million currently outstanding under our subordinated credit facility. In addition, we are also in discussions with our current lenders to amend our credit facilities in the event an equity issuance is not completed by April 30, 2009. We have no intention of pursuing any other equity offerings other than this offering prior to April 30, 2009. While we believe that there are alternatives available to us to re-finance our subordinated credit facility, we cannot assure you that any of these alternatives will be successfully implemented. If we are unable to re-finance the indebtedness under our subordinated credit facility or unable to amend our existing credit facilities, we may be required to sell assets and reduce capital expenditures and cash distributions. We cannot assure you that we will be able to re-finance the indebtedness under our subordinated credit facility, sell assets, or obtain additional financing on terms acceptable to us, if at all. If an event of default were to occur under our subordinated credit facility, an event of default would also occur under our credit facility. Upon an event of default, our lenders could foreclose on our assets and exercise other customary remedies, all of which would have a material adverse effect on us. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Subordinated Credit Facility.”

We may not have sufficient available cash each quarter to enable us to make cash distributions at the initial quarterly distribution rate or at all. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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the amount of oil and gas we produce;

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the prices at which we sell our oil and gas production;

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the effectiveness of our commodity price hedging strategy;

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our ability to continue to exploit and develop our existing oil and gas properties in a timely and cost efficient manner;

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the level of our operating and general and administrative expenses;

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the level of our interest expenses and restrictions on distributions in our credit facility;

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fluctuations in our working capital needs;

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timing and collectibility of receivables;

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the level of our capital expenditures, including those funded from our cash reserves which we expect to be substantial, established by our general partner for the proper conduct of our business; and

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our ability to acquire additional oil and gas properties at economically attractive prices.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

The estimate of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” has been prepared by management and we have not received an opinion or report on it from our or any other independent auditor. This estimate is based on assumptions about exploitation, development, production, oil and gas prices, hedging activities, capital expenditures, operating and general and administrative expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those assumed. If we do not achieve our anticipated results or cannot borrow amounts needed, we will not be able to pay the full initial quarterly distributions or any amount on our units, in which event the market price of our common units is likely to decline substantially.

Our revenue, profitability and cash flow from operations depend upon the prices and demand for oil and gas. Since the third quarter of 2008, oil and gas prices have declined dramatically. This decline has significantly affected our financial results and may impede our future growth. In particular, low commodity prices will:

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negatively impact the value of our reserves because declines in oil and gas prices would reduce the amount of oil and gas that we can produce economically;

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reduce the amount of cash flow available for capital expenditures;

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limit our ability to borrow money or raise additional capital; and

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impair our ability to pay distributions.

The oil and gas markets are volatile, and we cannot predict future oil and gas prices. Prices for oil and gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

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the domestic and foreign supply of and demand for oil and gas;

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the level of consumer product demand;

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weather conditions;

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political and economic conditions and events in foreign oil and gas producing countries, including those in the Middle East, South America and Russia;

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actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;

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technological advances affecting energy consumption and supply;

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domestic and foreign governmental regulations and taxation;

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the impact of energy conservation efforts;

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the proximity, capacity, cost and availability of oil and gas pipelines and other transportation facilities to our production, and access to readily available alternatives in the event of disruptions in such pipelines or facilities; and

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the price and availability of alternative fuels.

For more information relating to the volatility of oil and gas prices, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Commodity Prices and Hedging Activities.”

A material portion of our production is currently concentrated in two wells. If production from these wells declines more than we anticipate, we may have to decrease our distributions to you.

Approximately 11% of our production during the year ended December 31, 2008 was from the La Escalera 1AH well in our Oates SW area of the Permian Basin and the Henson 3H well in the Edwards trend of the Gulf Coast region. These wells represented approximately 3% of our estimated proved developed reserves as of December 31, 2008 principally because the La Escalera 1AH well is expected to be depleted in 2011. Like all gas wells, the rate of production from these wells will decline over time and the estimated future reserves associated with these wells will also decrease. If production from these wells declines more rapidly than we anticipate, it would have a material adverse effect on our ability to make distributions at the level we anticipate.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

After giving effect to the use of proceeds from this offering, we expect to have approximately $125.6 million outstanding under our credit facility and approximately $30.0 million outstanding under our subordinated credit facility. Following this offering, we will have the ability to incur debt, including under our credit facility, subject to borrowing base limitations. At December 31, 2008, our borrowing base was $140.0 million. Our future indebtedness could have important consequences to us, including:

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

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

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

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

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

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Approximately 92% of the estimated ultimate recovery of our estimated proved

developed reserves as of December 31, 2008 had been produced. Based on the reserve information set forth in our reserve reports at December 31, 2008, our average annual estimated decline rate for our net proved developed producing reserves is 10% during the first five years, 8% in the next five years and approximately 8% thereafter. This rate of decline is an estimate, and actual production declines could be materially higher. Our decline rate may change when we drill additional wells, make acquisitions and under other circumstances. Our future cash flow from operations and our ability to maintain distributions to unitholders are highly dependent on our success in efficiently exploiting and developing our current reserves. Our ability to increase distributions will be highly dependent on our ability to economically find or acquire additional recoverable reserves. We may not be able to exploit, develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

We are unlikely to be able to sustain our current level of distributions without making capital expenditures or accretive acquisitions that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures will fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce any indebtedness until we make the capital expenditures. If we do not reserve sufficient cash or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions.

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 typically 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.

During 2008, we experienced differentials of $7.31 per Bbl of oil and $1.36 per Mcf of gas. Approximately 43% of our production during 2008 was from our properties located in the Rocky Mountain and Mid-Continent regions of the United States. Historically, these regions have experienced wider differentials than the Permian Basin and Gulf Coast. If the percentage of our production from these regions increases, we would expect that our price differentials would also increase. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our cash flow from operations and could affect our ability to pay cash distributions to you. For more information regarding our expected differentials for the twelve months ending June 30, 2010, please read “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Operations and Revenue—Prices.”

The process of estimating oil and gas reserves is complex, involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this prospectus. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploitation and development activities, prevailing oil and gas prices and other factors, many of which are beyond our control.

The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the standardized measure thereof for oil and gas properties are based on the assumption that future oil and gas prices remain the same as oil and gas prices at December 31, 2008. The NYMEX prices on such date were $44.60 per Bbl of oil and $5.62 per MMbtu of gas which resulted in realized prices of $41.56 per Bbl of oil and $4.78 per Mcf of gas. These estimates also assume that we will make future capital expenditures that are necessary to develop and realize the value of proved undeveloped reserves on our properties. In addition, approximately 39% of our total estimated proved reserves at December 31, 2008 were undeveloped. By their nature, estimates of undeveloped reserves are less certain than proved developed reserves. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth in this prospectus.

The standardized measure of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to pay cash distributions to you.

As required by SEC regulations, we base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our properties will be affected by factors such as:

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supply of and demand for oil and gas;

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actual prices we receive for oil and gas;

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our actual operating costs;

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the amount and timing of our capital expenditures;

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the amount and timing of actual production; and

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required by the SEC, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to you.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploitation, development, production and acquisition of oil and gas reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities. The incurrence of debt will require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. Our cash flow from operations and access to capital is subject to a number of variables, including:

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the amount of oil and gas we produce from existing wells;

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the prices at which we sell our production;

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the costs to produce oil and gas from our existing wells;

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the estimated quantities of our oil and gas reserves;

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our ability to develop and produce new wells on our existing properties; and

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our ability to locate, acquire and produce new reserves.

If our revenue or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility restricts our ability to incur additional indebtedness. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash flow from operations or availability under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to the exploitation and development of our properties as well as any acquisition activities which, in turn, could lead to a decline in our reserves and production, and could adversely effect our business, results of operation, financial condition and ability to make cash distributions. In addition, issuing additional units may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate.

We may incur debt to pay our quarterly distributions, which may negatively affect our ability to execute our business strategy and pay future distributions.

We may be unable to pay our distributions without borrowing under our credit facility and any future financing agreements. When we borrow to pay distributions, we are distributing more cash than we are generating from our operations. If we use borrowings under our credit facility to pay distributions for an extended period of time, we may be unable to support or grow our business. Further, increased interest expense associated with any such borrowings will reduce our cash available for distributions on our units and will have a material adverse effect on our business, financial condition and results of operations.

Our credit facilities contain substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

The operating and financial restrictions and covenants in our credit facility and any future financing agreements may restrict our ability to finance future operations or capital expenditures or to engage, expand or pursue our business activities or to pay distributions. Our credit facility restricts our ability to, among other things:

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make distributions to unitholders or repurchase units;

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incur indebtedness;

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grant liens;

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make acquisitions, investments and dispositions; and

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engage in transactions with affiliates.

We are also required to comply with certain financial covenants and ratios and a restriction that the amount of our borrowings cannot exceed the borrowing base determined by the lenders in their sole discretion. The lenders can unilaterally adjust the borrowing base, and the borrowings permitted to be outstanding under our credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and gas properties as additional collateral. We do not currently have any substantial unpledged properties and we may not have the financial resources in the future to make mandatory principal repayments required under our credit facility. Please read “Cash Distribution Policy and Restrictions on Distributions—Our Cash Distribution Policy—General,” “—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy,” “—Our Initial Distribution Rate” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.” Our ability to comply

with these restrictions and covenants in the future is uncertain and will be affected by the levels of our cash flow from operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants or ratios in our credit facility or exceed our borrowing base, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be limited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher oil and gas prices generally increase the demand for drilling rigs, equipment and crews, which can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling of new wells or significant increases in drilling costs could reduce our revenues and cash available for distribution. Over the past few years, Abraxas Petroleum has experienced some delays and increased costs for drilling rigs, equipment and crews. For more information on these costs, please refer to “Management Discussion and Analysis of Financial Condition and Results of Operations.”

We will rely on development drilling to replace reserves we have produced and to increase our levels of production. Developing and producing oil and gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Part of our business strategy will focus on replacing the reserves we produce by drilling development wells. Abraxas Petroleum and other third parties conduct our drilling operations. We cannot assure you that we will be able to replace reserves through development drilling. In 2006, for example, Abraxas Petroleum replaced only 7% of the reserves it produced. Drilling operations on our properties involve numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. We will incur significant expenditures to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to our unitholders.

Drilling operations on our properties may be curtailed, delayed or cancelled as a result of a variety of factors, including:

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unexpected drilling conditions;

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facility or equipment failure or accidents;

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shortages or delays in the availability of drilling rigs, equipment and crews;

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adverse weather conditions;

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compliance with environmental and governmental rules and regulations;

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title problems;

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unusual or unexpected geological formations;

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pipeline ruptures;

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fires, blowouts, craterings and explosions; and

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uncontrollable flows of oil or gas or well fluids.

We intend to continue to make acquisitions of oil and gas properties to grow our asset base. The properties we acquire may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution.

Part of our business strategy is to make accretive acquisitions of oil and gas properties. All acquisitions require an assessment of recoverable reserves, title, future oil and gas prices, operating costs, potential environmental hazards and liabilities, potential tax and ERISA liabilities, and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher-valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed due diligence review may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations and our ability to make cash distributions to our unitholders.

Additional potential risks related to acquisitions include, among other things:

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incorrect assumptions regarding the future prices of oil and gas or the future operating or development costs of properties acquired;

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incorrect estimates of the oil and gas reserves attributable to a property we acquire;

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unpredictable production profiles and decline rates of properties acquired;

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an inability to integrate successfully the properties we acquire;

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the assumption of liabilities;

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limitations on our rights to be indemnified by the seller;

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the diversion of management’s attention from other business concerns; and

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losses of key operational employees at the acquired properties.

Our hedging activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions.

To achieve more predictable cash flow and reduce our exposure to 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 losses. At December 31, 2008, we had NYMEX-based fixed price commodity swaps on approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2011. We have elected out of hedge accounting as prescribed by applicable accounting rules. For more information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives.”

The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity price hedging activities. For example, the prices utilized in our derivative contracts 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 typically 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 adversely 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 and could affect our ability to pay cash distributions to you.” 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk—Hedging Activities and Sensitivity” for more information.

If the prices at which we hedge our oil and gas production are less than prevailing market prices, our ability to pay cash distributions could be adversely affected.

At December 31, 2008, we had NYMEX-based fixed price commodity swaps on approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2011. The volume weighted average prices in our derivative contracts are $84.41 per barrel of oil and $8.27 per MMbtu of gas. The contract prices for oil and gas are significantly higher than the NYMEX futures price on March 2, 2009 of $44.76 per barrel and $4.20 per MMbtu. When our contract prices are higher than prevailing market prices, we will sustain realized and unrealized gains on our derivative contracts. Conversely, when our contract prices are less than prevailing market prices, we will sustain realized and unrealized losses on our derivative contracts. For the year ended December 31, 2008, we recognized a realized loss of ($9.3) million and an unrealized gain of $37.9 million. The realized loss resulted in a decrease in cash flow from operations and negatively affected our cash available for distribution. We expect to continue to enter into similar hedging arrangements in the future to reduce cash flow volatility.

The counterparty to our derivative contracts may be unable to perform its obligations to us, which could materially affect our cash flows, results of operations and our ability to pay cash distributions.

As of December 31, 2008, the mark-to-market value of our commodity derivative contracts was $39.2 million which entitles us to future payments from our counterparty. Since December 31, 2008 commodity prices have continued to decline which has increased the mark-to-market value of our commodity derivative contracts. The worldwide financial and credit crisis may have adversely affected the ability of our counterparty to fulfill its obligations to us. If our counterparty is unable or unwilling to make the required payments to us, it could have a material adverse effect on our cash flows, results of operations and our ability to pay cash distributions.

Our ability to use hedging arrangements to protect us from future oil and gas price declines will be dependent upon oil and gas prices at the time we enter into these hedging arrangements and our future levels of hedging, and as a result our future net cash flow may be more sensitive to commodity price changes.

We have currently hedged a significant portion of our estimated oil and gas production from our net proved developed producing reserves with NYMEX-based fixed price commodity swaps through December 2011. As our derivative contracts expire, more of our future production will be sold at market prices unless we enter into further hedging arrangements. Our commodity price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under any future obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these arrangements, which may be substantially higher or lower than current oil and gas prices. Accordingly, our commodity price hedging strategy may not protect us from significant declines in oil and gas prices received for our future production. Conversely, our commodity price hedging strategy has limited and may in the future limit our ability to realize increased cash flow from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared to the next few years, which would result in our oil and gas revenues becoming more sensitive to commodity price changes.

Future commodity price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow and make distributions.

Lower oil or gas prices may not only decrease our revenues, but also reduce the amount of oil or gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of exploitation and development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and gas properties for impairments. This is known as a ceiling-test impairment. At December 31, 2008, the net capitalized costs of our oil and gas properties exceeded the present value of our estimated proved reserves by $97.1 million resulting in a ceiling-test impairment of $97.1 million. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to our unitholders.

The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and gas industry has periodically experienced shortages of drilling rigs, equipment and crews, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the technical fields of petroleum engineering and geology. In addition, competition is strong for attractive oil and gas producing properties, companies that own such properties and undeveloped leases and drilling rights. We may be outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

Our business is subject to operational risks that may not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our business activities are subject to operational risks, including:

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damages to equipment caused by adverse weather conditions, including hurricanes, lightning strikes and flooding;

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facility or equipment malfunctions;

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pipeline ruptures or spills;

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fires, blowouts, craterings and explosions; and

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uncontrollable flows of oil or gas or well fluids.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

We maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.

Our ability to make cash distributions to our unitholders and to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

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the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;

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the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

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the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

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the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as Superfund, and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability on responsible parties for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. Please read “—We may incur costs for plugging and abandoning wells and environmental liabilities relating to our properties” and “Business—Environmental Matters” for more information on the laws and regulations that affect us, the operation of our properties and certain related risks and potential liabilities.

The operation of our properties is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and gas operations are subject to complex and stringent laws and regulations. In order to operate our properties in compliance with these laws and regulations, Abraxas Petroleum (which operates properties comprising over 75% of our estimated proved reserves at December 31, 2008) and all other operators of our properties must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on the ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect the operation of our properties by limiting the quantity of oil and gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the operations of our properties. While the cost of

compliance with these laws has not been material to the operations of our properties in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders could be adversely affected. Please read “Business—Environmental Matters” and “Business—Regulation of Oil and Gas Activities” for more information.

We may incur costs for plugging and abandoning wells and environmental liabilities relating to our properties.

We are responsible for all plugging and abandonment costs relating to our properties. As of December 31, 2008, we have estimated these costs to be approximately $9.0 million. In addition, under the terms of our omnibus agreement with Abraxas Petroleum, we have agreed to be responsible for all environmental liabilities relating to the properties contributed to us in the Formation Transactions except to the extent we are indemnified by Abraxas Petroleum. Abraxas Petroleum has agreed to indemnify us through May 24, 2010 against certain potential environmental claims. Abraxas Petroleum’s maximum liability for these indemnification obligations will not exceed $5 million and Abraxas Petroleum will not have any obligation under this indemnification until our aggregate losses exceed $500,000. Abraxas Petroleum will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 25, 2007. We have agreed to indemnify Abraxas Petroleum against environmental liabilities related to our assets to the extent Abraxas Petroleum is not required to indemnify us. We also agreed to indemnify St. Mary against all environmental liabilities related to the properties acquired in the St. Mary Acquisition.

Increases in interest rates could cause the market price of our common units to decline, which could adversely affect our ability to issue additional equity, make acquisitions and incur debt.

An investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may demand to receive a higher rate of return which might exceed those otherwise obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt and other investments may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests such as our common units. Reduced demand for our common units may cause the market price of our common units to decline and could adversely affect our ability to issue additional equity. Further, borrowings under our credit facility are subject to variable interest rates. Accordingly, our cost of borrowing will increase as interest rates increase. Both of these factors could, in turn, adversely affect the availability of capital with which to make accretive acquisitions.

Inflation would increase our costs and may adversely affect our business, financial condition and results of operations.

The cost of labor and supplies, taxes, repairs, maintenance and insurance are all subject to inflationary pressures. Inflation could adversely affect our ability to make accretive acquisitions at economically attractive prices, and could increase our operating and general and administrative expenses and diminish our ability to continue to exploit and develop our existing oil and gas properties in a cost efficient manner. Pursuant to our omnibus agreement, the annual fees payable to Abraxas Petroleum for general and administrative expenses are subject to annual adjustments for inflation, as well as for acquisition or other expansion adjustments. In addition, we are required to reimburse Abraxas Petroleum for the costs it incurs for operating our properties. Unless prices of oil and gas also increase, significant inflation would adversely affect our business, financial condition and results of operations.

Risks Inherent in an Investment in Us

Abraxas Petroleum owns and controls our general partner. Some of our general partner’s directors and officers, are also directors and officers of Abraxas Petroleum. The directors and officers of our general partner

have a fiduciary duty to manage our general partner in a manner beneficial to Abraxas Petroleum. Conflicts of interest exist and may arise between Abraxas Petroleum and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our unitholders. These conflicts include, among others, the following situations:

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neither our partnership agreement nor any other agreement requires Abraxas Petroleum to pursue a business strategy that favors us. Abraxas Petroleum’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Abraxas Petroleum, which may be contrary to our interests;

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our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

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Abraxas Petroleum is not limited in its ability to compete with us, which could limit our ability to acquire additional assets;

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our general partner determines the amount and timing of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuance of additional partnership securities and cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

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Abraxas Petroleum operates properties comprising over 75% of our estimated proved reserves at December 31, 2008, determines the manner in which its personnel and operational resources are utilized and is not prohibited from favoring other properties it operates over our properties, so long as it conducts itself in accordance with the operating standards set forth in the operating agreements;

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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

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in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions;

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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;

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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of our common units; and

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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Conflicts of Interest and Fiduciary Duties.”

Abraxas Petroleum is not limited in its ability to compete with us, which could affect our ability to acquire additional assets.

Neither our partnership agreement nor our omnibus agreement prohibits Abraxas Petroleum and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, Abraxas Petroleum and its affiliates may acquire, develop or dispose of additional oil and gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. In addition, Abraxas Petroleum is not obligated to present us with potential acquisitions and is not restricted from competing with us. Competition from these entities could adversely impact our results of operations and cash available for distribution. Please read “Conflicts of Interest and Fiduciary Duties.”

Cost reimbursements and payments to our general partner and its affiliates for services provided may be substantial and could reduce our cash available for distributions.

Pursuant to our omnibus agreement, we currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and

administrative expenses, subject to annual adjustments for inflation and acquisitions or other expansion adjustments. This fee includes an adjustment made in January 2008 for the St. Mary property acquisition of $1.1 million. Thereafter, our payment obligations to Abraxas Petroleum for general and administrative services provided on our behalf are not fixed. In addition, pursuant to our operating agreements we are required to reimburse Abraxas Petroleum for all of our operating expenses, which are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Operating expenses do not include general and administrative expenses. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “—Operating Agreement.”

Unitholders have limited voting rights and are not entitled to elect our general partner or its Board of Directors on an annual or other continuing basis.

Unlike the holders of common stock in a corporation, common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management decisions regarding our business. Unitholders did not elect our general partner or its Board of Directors, and will have no right to elect our general partner on an annual or other continuing basis. The Board of Directors of our general partner, including the independent directors, are elected by Abraxas Petroleum. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have a very limited ability to remove our general partner. Please read “Management,” and “The Partnership Agreement—Meetings; Voting.”

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;

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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board of Directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter acted with knowledge that such conduct was criminal; and

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provides that in resolving conflicts of interest, it will be presumed that in making its determination as to whether the terms are “no less favorable” or “fair and reasonable” to us, the general partner or its

conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a common unitholder will be deemed to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Holders of our common units are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent the removal of our general partner. The vote of the holders of at least 66²/3% of all outstanding common units voting together as a single class is required to remove our general partner. Upon consummation of this offering, our general partner and its affiliates will own approximately 41.4% of our common units and approximately 40.7% of our common units if the underwriters exercise their over-allotment option to purchase additional common units in full. If Abraxas Petroleum purchases all of the common units it has agreed to purchase in this offering, our general partner and its affiliates will own approximately 44.6% of our common units and approximately 43.9% of our common units if the underwriters exercise their over-allotment option to purchase additional common units in full.

Control of our general partner may be transferred to a third party without unitholder consent and the successor owner could replace our board of directors and officers.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Abraxas Petroleum, the owner of our general partner, from transferring all or a portion of its ownership interest in our general partner to a third party. The successor owner of our general partner would then be in a position to replace the Board of Directors and officers of our general partner with its own choices and thereby influence the decisions made by the Board of Directors and officers. In addition, Abraxas Petroleum has secured its obligations under its credit facility with its ownership interests in our general partner and Abraxas Investments. If Abraxas Petroleum defaults on its credit agreement, its lenders could foreclose on these interests and obtain control of our general partner or sell such controlling interest to a third party.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

You will experience immediate and substantial dilution of $7.90 in tangible net book value per common unit.

The assumed initial public offering price of $7.50 per unit exceeds our pro forma net tangible book value of $(1.10) per unit before this offering. Based on the assumed initial public offering price of $7.50 per unit, you will incur immediate and substantial dilution of $7.90 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

Units eligible for future sale may have adverse effects on our unit price and the liquidity of the market for our common units.

We cannot predict the effect of future sales of our common units, or the availability of common units for future sales, on the market price of or the liquidity of the market for our common units. Sales of substantial amounts of common units, or the perception that such sales could occur, could adversely affect the prevailing market price of our common units. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, if no active trading market develops for our common units, sales of common units or the possibility of such sales could have a greater adverse effect on the market price of our common units than would be the case if an active market existed.

Upon completion of this offering, the Private Investors and their affiliates will own approximately 6,009,987 common units, representing approximately 47.0% of our outstanding units. Subject to the terms and conditions of our registration rights agreement, the Private Investors will generally be eligible to sell their common units into the market beginning 60 days after the date of this prospectus. Please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Registration Rights Agreement” for additional information.

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register, under the Securities Act and applicable state securities laws, the offer and sale of any common units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other units, including common units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In addition, subject to exceptions, we, the officers and directors of our general partner, our general partner and its affiliates have agreed not to sell any common units they may hold for a period of 365 days from the date of this prospectus. However, we may issue and sell an unlimited number of common units within that period as consideration in connection with accretive acquisitions, including in order to pay the cash portion of any consideration or to repay indebtedness incurred in connection with any such acquisition. Please read “Units Eligible for Future Sale” and “Underwriting—Lock-Up Agreements” for a description of the lock-up provisions.

We may issue an unlimited number of additional units, including units that are senior to the common units, without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional common units or other equity securities that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;

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the amount of cash available for distribution on each unit may decrease;

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the ratio of taxable income to distributions may increase;

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the common units may be subordinated in rights of distribution, liquidation or voting;

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the relative voting strength of each previously outstanding unit may be diminished; and

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the market price of our common units may decline.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-

current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Upon completion of this offering, Abraxas Investments, an affiliate of our general partner, will own approximately 41.0% of our outstanding common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and that Abraxas Petroleum does not purchase any common units in this offering. Please read “The Partnership Agreement—Limited Call Right.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Our partnership is organized under Delaware law, and we currently conduct business in a number of states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do (or may do) business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency determined that:

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we were conducting business in a state but had not complied with that particular state’s partnership statute; or

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your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other unitholder actions as provided in our partnership agreement, is deemed to constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully made to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions if such distributions would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received such distribution and who knew at the time of the distribution that it violated Delaware law, will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Common units held by persons who are not Eligible Holders will be subject to the possibility of redemption.

We own interests in oil and gas leases on federal lands that are subject to certain U.S. laws relating to ownership of such interests. In order to comply with those laws, our partnership agreement requires that a transferee of common units properly complete and deliver to us a transfer application containing a certification as to a number of matters, including the status of the transferee, or all of its owners, as being an Eligible Holder, and that from time to time, upon the request of our general partner, an existing unitholder re-certify such status to the partnership. As used herein, Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. If a transferee or a unitholder, as the case may be, does not properly complete a transfer application or re-certification, as applicable, for any reason, the transferee or unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we have the right to redeem such units at a price which is equal to the average daily closing price per common unit for the 20 consecutive trading days prior to the date of determination of the price at which such units will be redeemed. Please read “Description of the Common Units—Transfer of Common Units” and “The Partnership Agreement—Non-Eligible Holders; Redemption.”

Unitholders may have limited liquidity for their units, a trading market may not develop for our common units, and you may not be able to resell your common units at the initial public offering price.

Prior to this offering, there has been no public market for our common units. After this offering, there will be 1,335,000 publicly traded common units, or 1,535,250 publicly traded common units if the underwriters exercise their over-allotment option to purchase additional common units in full. Please read “—Units eligible for future sale may have adverse effects on our unit price and the liquidity of the market for our common units.” We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.

In addition, trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of securities. The market price of our common units could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we are treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to our unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Thus, any treatment of us as a corporation for federal tax purposes could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and, therefore, result in a substantial reduction in the value of our units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we may be subject to a new entity-level state tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax may be imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. Additionally, it is possible that any income from non-Texas activities may be taxed under the Texas margin tax. We are currently considered a passive-entity and not subject to the Texas margin tax. If other states in which we operate were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

It is possible that all or a portion of gain or loss on disposition of common units may be recognized as ordinary income, subject to your marginal rate.

If our unitholders sell any of their units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price our unitholders receive is less than their original cost. A substantial portion of the gain recognized, whether or not representing actual appreciation, may be ordinary income to our unitholders. In addition, if our unitholders sell units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of units and could have a negative impact on the value of our units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material Tax Consequences—Uniformity of Units,” for a further discussion of the effect of the depletion, depreciation and amortization positions we will adopt.

We will be deemed to have terminated as a partnership for federal tax purposes if there is a sale or exchange of 50% or more of our interests within a twelve-month period.

If there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period, we will be considered to have terminated for federal tax purposes. A constructive termination would, among other things, result in the closing of our taxable year for all unitholders and, in the case of unitholders reporting on a taxable year other than a fiscal year ending December 31, may result in more than twelve months of our taxable income or loss being includable in the unitholders’ taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. Additionally, all federal tax elections we have made will be terminated, and the depreciable lives of our depreciable property will be started anew.

Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not reside in any of those jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We conduct business and own assets in a number of states. As we make acquisitions or expand our business, we may conduct business or own assets in additional states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the units.

The White House released a preview of its budget for Fiscal Year 2010 on February 26, 2009, entitled “A New Era of Responsibility: Renewing America’s Promise.” Among the new administration’s proposed changes are the outright elimination of many of the key federal income tax benefits historically associated with oil and gas. Although presented in very summary form, among other significant energy tax items, the administration’s budget appears to propose the complete elimination of (i) expensing of intangible drilling costs, and (ii) the “percentage depletion” method of deduction with respect to oil and gas wells. Additionally, the budget proposes to reinstate for single individuals making greater than $200,000 per year, and for couples making greater than $250,000 per year, the maximum ordinary income rates of 36% and 39.6%, and the maximum long-term capital gain rate of 20%.

Although no legislation has yet been formally introduced, the administration’s apparent effective date would be January 1, 2011. It is unclear whether such proposal will be proposed as actual legislation and, if so, whether it will actually be enacted. In addition, there are other significant tax changes under discussion in the Congress. If this proposal (or others) is enacted into law, it could represent an extremely significant reduction in the tax benefits that have historically applied to certain investments in oil and gas. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” and “—Tax Treatment of Operations—Potential Changes to Legislation.”

USE OF PROCEEDS

We expect the estimated net proceeds from this offering and the proportionate capital contribution from our general partner of $0.2 million to be $9.3 million, after deducting the underwriting discount of $0.5 million and offering expenses of approximately $0.4 million to be paid with proceeds from this offering, based on an assumed offering price of $7.50 per unit. We intend to use the net proceeds of this offering, together with our general partner’s proportionate capital contribution of approximately $0.2 million, to partially repay indebtedness outstanding under our subordinated credit facility. Our general partner’s proportionate capital contribution of $0.2 million will result in the issuance of an additional 29,522 general partner units, for a total of 256,754 general partner units, and maintenance of its 2% general partner interest. We have previously paid approximately $1.8 million in offering expenses out of available cash.

At March 2, 2009, we had borrowings of $40.0 million outstanding under our subordinated credit facility. We used the borrowings under our subordinated credit facility to partially finance the St. Mary Acquisition. Outstanding amounts under our subordinated credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR, plus in each case (b) 7.50% or, if we elect, at the greater of (a) 2.0% and (b) LIBOR, in each case, plus 8.50%. At March 2, 2009, the interest rate on our subordinated credit facility was approximately 10.5%. The maturity date of our subordinated credit facility is July 1, 2009. We intend to partially repay indebtedness outstanding under our subordinated credit facility with proceeds from this offering. We also intend to re-finance the indebtedness outstanding under our subordinated credit facility prior to its scheduled maturity date; however, there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial advisor to assist us in this re-financing. An increase or decrease in the initial public offering price of $1.00 per common unit, together with the proportionate capital contribution from our general partner, would cause the net proceeds from the offering, after deducting the underwriting discount and all estimated offering expenses payable by us, to increase or decrease by approximately $1.2 million.

CAPITALIZATION

The following table shows:

•

our historical cash and capitalization as of December 31, 2008; and

•

our cash and capitalization as of December 31, 2008, as adjusted to reflect the sale of 1,335,000 units in this offering at an assumed offering price of $7.50 per unit less the underwriting discount and estimated offering expenses, our general partner’s proportionate capital contribution of approximately $0.2 million and the application of the net proceeds we expect to receive as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with the historical financial statements and the accompanying notes included elsewhere in this prospectus.


	Abraxas Energy
	As of December 31, 2008
	Historical			As Adjusted for this Offering(1)
	(In thousands)
Cash and cash equivalents	$	1,924		$	1,924

Current maturities of long-term debt		40,000			32,467
Long-term debt		125,600			125,600
Total partners’ capital		(12,492	)		(4,959	)

Total capitalization	$	153,108		$	153,108

(1)

A $1.00 increase or decrease in the assumed public offering price per common unit, together with the proportionate capital contribution from our general partner, would increase or decrease our total partners’ capital by $1.2 million, assuming 1,335,000 common units offered by us and after deducting the underwriting discount and all estimated offering expenses payable by us.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of units sold in this offering will exceed the net tangible book value per common unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $7.50 per common unit, as of December 31, 2008, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value would have been $(5.2) million, or $(0.40) per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit				$	7.50
Net tangible book value per common unit before this offering(1)	$	(1.10	)
Increase in net tangible book value per common unit attributable to purchasers in this offering		0.70

Less: net tangible book value per common unit after this offering(2)					(0.40	)

Immediate dilution in net tangible book value per common unit to new investors(3)				$	7.90

(1)

Determined by dividing the net tangible book value of our assets as of December 31, 2008 by the number of units (11,378,178 common units and 227,232 general partner units) that were issued to our general partner and its affiliates and to the Private Investors in connection with the Formation Transactions.

(2)

Determined by dividing the total number of units to be outstanding after this offering (12,528,946 common units and 256,754 general partner units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and that Abraxas Petroleum does not purchase any common units in this offering), into our net tangible book value, after giving effect to the application of the expected net proceeds of this offering.

(3)

If the initial public offering price were to increase by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $8.80. If the initial public offering price were to decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $7.00.

The following table sets forth the number of units that have been issued and the total consideration contributed to us by the Private Investors, our general partner and its affiliates with respect to their units and by the purchasers of common units in this offering:


	Units Acquired			Total Consideration
	Number	Percent		Amount		Percent
	(In thousands)			(In thousands)
Private Investors plus the general partner and its affiliates(1)(2)	11,451	89.5	%	$	34,324	77.4	%
New investors	1,335	10.5	%		10,013	22.6	%

Total	12,786	100.0	%	$	44,337	100.0	%

(1)

The Private Investors currently own 6,009,987 common units, representing a 47.0% interest in us after this offering. Our general partner will own 256,754 general partner units, representing a 2% interest in us after this offering, its affiliate, Abraxas Investments owns 5,131,959 common units, representing a 40.1% interest in us, and the restricted unitholders own 52,000 common units, representing a 0.4% interest in us after this offering.

(2)	The assets contributed by affiliates of our general partner were recorded at historical cost in accordance with GAAP. Total consideration provided by the Private Investors, our general partner and its affiliates is equal to the net tangible book value of such assets as of December 31, 2008.

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please see “—Assumptions and Considerations” below. In addition, you should read “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” beginning on page 20 for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

All information in this section refers to Abraxas Energy and our properties. For additional information regarding our historical and pro forma operating results, you should refer to the unaudited pro forma consolidated financial statements and the notes thereto of Abraxas Energy for the year ended December 31, 2008, the audited consolidated financial statements and the notes thereto of Abraxas Petroleum for the year ended December 31, 2006 and for the period from January 1 to May 24, 2007 and the audited consolidated financial statements and the notes thereto of Abraxas Energy for the period from May 25 to December 31, 2007 and for the year ended December 31, 2008, included elsewhere in this prospectus.

Our Cash Distribution Policy

General

Our partnership agreement requires us to distribute all of our available cash quarterly. Under our partnership agreement, available cash is generally defined to mean all cash on hand as of the date of determination of available cash for any fiscal quarter, less the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business (including reserves for future capital expenditures and for acquisitions of additional oil and gas properties);

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distribution to our unitholders for any one or more of the next four quarters.

We intend to fund our capital expenditures with cash flow from operations, borrowings under our credit facility, and sales of debt or equity securities. We may also borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused cash available from operations to be insufficient to pay the distribution at the current level. Our credit facility restricts our ability to incur additional indebtedness and further restricts our ability to pay cash distributions under certain circumstances. Under the terms of our credit facility, we may make cash distributions if, after giving effect to such distributions, we are not in default under our credit facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under our credit facility is greater than or equal to 10% of the lesser of our borrowing base (which is currently $140.0 million) or the total commitment amount of our credit facility (which is $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under our credit facility after giving effect to such distribution exceeds $20.0 million, or (ii) our subordinated credit facility shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while our subordinated credit facility is outstanding. Additionally, while our subordinated credit facility is outstanding, our capital expenditures are limited to $12.5 million. We are not currently a party to any other agreement which restricts our ability to pay cash distributions, and our partnership agreement does not restrict our ability to borrow to pay distributions.

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. However, the amount

of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our operations and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Our cash distribution policy, as detailed in our partnership agreement, may not be modified or rescinded without amending our partnership agreement. Our partnership agreement may be amended under certain circumstances with the approval of our general partner only and under other circumstances with the approval of our general partner and holders of a majority of our outstanding common units. See “The Partnership Agreement—Amendments to Our Partnership Agreement.”

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions. Some of the circumstances which could require us to change our distribution policy could come as a result of any of the following:

•

The prices at which we sell our future production will be volatile and could decrease substantially. While we believe that our commodity price hedging program will reduce the effect of this volatility for several years, any prolonged decrease in commodity prices will reduce our cash available for distribution.

•

The prices at which we hedge our oil and gas production could be less than prevailing market prices. While we believe that our commodity price hedging program is effective in reducing cash flow volatility, we will not benefit if prevailing market prices are higher than our contract prices, which could affect our ability to increase cash distributions during periods of high prices.

•

Our cash distribution policy is subject to restrictions on distributions under our credit facility. Should we be unable to comply with the covenants under our credit facility, or if we are otherwise in default under our credit facility, we would be prohibited from making distributions to you notwithstanding our cash distribution policy. These covenants are described more fully in this prospectus under the captions “Our Cash Distribution Policy—General,” “—Our Initial Distribution Rate” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.”

•

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our cash distribution policy. Any determination to establish reserves made by our general partner in good faith will be binding on all of our unitholders.

•

We intend to reserve a substantial portion of our cash flow from operations to fund our maintenance capital expenditures. We define maintenance capital expenditures as those expenditures necessary to replace our reserves and maintain our current level of production. If we do not set aside sufficient cash reserves or make sufficient capital expenditures to replace our reserves and maintain our current production level, we will be unable to pay distributions at the current level and would therefore expect to reduce our distributions. Over the long term, we are unlikely to be able to sustain our currently anticipated level of distributions without making capital expenditures for accretive acquisitions that

maintain or grow our asset base. We define growth capital expenditures as those expenditures necessary to increase our production and grow our asset base. We intend to finance our growth capital expenditures with a combination of cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities.

•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended by a vote of the general partner and the holders of a majority of our common units.

•

Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

•

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reduced production from our wells, lower prices for the oil and gas we sell, increases in operating or general and administrative expenses, principal and interest payments on any current or future debt, capital expenditures, working capital requirements and anticipated cash needs.

Our Ability to Grow Depends on Our Ability to Access External Growth Capital

We will require capital to replace the reserves we produce, maintain our current level of production and to grow our asset base. We intend to reserve sufficient cash provided by our operations to fund capital expenditures necessary to replace our reserves and maintain our current level of production. We refer to these capital expenditures as our maintenance capital expenditures. We intend to fund maintenance capital expenditures out of cash flow from operations.

In order to increase our production and grow our asset base, we will need either to make accretive acquisitions of oil and gas properties with low-risk exploitation and development opportunities or to accelerate drilling activity on our existing properties, or both. We refer to these capital expenditures as growth capital expenditures. We intend to fund growth capital expenditures with a combination of cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities. We cannot assure you that any of these sources of capital will be available to us either in the amounts necessary or on terms acceptable to us. If we do not have sufficient capital, we will likely be required to reduce the amount of cash distributions. For more information on our sources of capital, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our Initial Distribution Rate

The board of directors of our general partner has adopted a cash distribution policy pursuant to which, after completion of this offering, we will pay an initial quarterly distribution of $0.375 per unit, or $1.50 per unit per year, which will be paid no later than 45 days after the end of each quarter. This equates to an aggregate cash distribution of approximately $4.8 million per quarter, or approximately $19.2 million per year, based on the units outstanding immediately after completion of this offering. If the underwriters’ fully exercise their over-allotment option to purchase 200,250 additional common units, then the aggregate cash distribution would increase to approximately $4.9 million per quarter, or approximately $19.5 million per year. We currently make quarterly distributions of $0.375 per unit ($1.50 per unit on an annualized basis) to our unitholders. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy,” and by the terms of our credit facility. Under the terms of our credit facility, we may make cash distributions if, after giving effect to such distributions, we are not in default under our credit facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of

any advance unless the unused portion of the amount then available under our credit facility is greater than or equal to 10% of the lesser of our borrowing base (which is currently $140.0 million) or the total commitment amount of our credit facility (which is $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under our credit facility after giving effect to such distribution exceeds $20.0 million, or (ii) our subordinated credit facility shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while our subordinated credit facility is outstanding. Additionally, while our subordinated credit facility is outstanding, our capital expenditures are limited to $12.5 million.

The following table sets forth the number of outstanding units (assuming no exercise and full exercise of the underwriters’ over-allotment option to purchase additional common units) upon the closing of this offering and the aggregate distribution amounts payable on such units following the closing of this offering at our initial distribution rate of $0.375 per unit per quarter ($1.50 per unit on an annualized basis):


	No Exercise of the Underwriters’ Over-Allotment Option to Purchase Additional Common Units					Full Exercise of the Underwriters’ Over-Allotment Option to Purchase Additional Common Units
		Distributions					Distributions
	Number of Units	One Quarter		Four Quarters		Number of Units	One Quarter		Four Quarters
Public common units	1,335,000	$	500,625	$	2,002,500	1,535,250	$	575,719	$	2,302,875
Private Investor common units	6,009,987		2,253,745		9,014,981	6,009,987		2,253,745		9,014,981
Common units held by Abraxas Petroleum and its affiliates	5,131,959		1,924,485		7,697,939	5,131,959		1,924,485		7,697,939
General partner units	256,754		96,283		395,130	260,840		97,815		391,260
Restricted units	52,000		19,500		78,000	52,000		19,500		78,000

Total	12,785,700	$	4,794,638	$	19,178,550	12,990,036	$	4,871,264	$	19,485,054

Distributions will not be cumulative. Consequently, if distributions on our units are not paid with respect to any fiscal quarter, our unitholders, including our general partner, will not be entitled to receive any shortfall or missed payments in the future. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We have paid the following distributions to our unitholders:


Date Paid	Period	Distribution Per Unit
August 14, 2007	May 25-June 30, 2007	$	0.1520
November 14, 2007	Quarter Ended September 30, 2007	$	0.3750
February 14, 2008	Quarter Ended December 31, 2007	$	0.3750
May 14, 2008	Quarter Ended March 31, 2008	$	0.4000
August 14, 2008	Quarter Ended June 30, 2008	$	0.4375
November 14, 2008	Quarter Ended September 30, 2008	$	0.4400
February 13, 2009	Quarter Ended December 31, 2008	$	0.3750

Assuming that we complete this offering before June 30, 2009, we will pay unitholders a prorated distribution for the period from the first day our common units are publicly traded to and including June 30, 2009.

Pro Forma Financial Information and Estimated Cash Available for Distributions

In the sections that follow, we present the basis for our belief that we will be able to fully fund our initial quarterly distribution rate of $0.375 per unit for the twelve months ending June 30, 2010. In those sections we present two tables, including:

•

Our “Estimated Cash Available For Distribution” in which we present the estimated cash available to pay distributions at the initial distribution rate on all of our units for the twelve months ending June 30, 2010.

•

Our “Unaudited Pro Forma Consolidated Available Cash,” in which we present the amount of cash we would have had available for distribution with respect to the year ended December 31, 2008 derived from our unaudited pro forma consolidated financial statements that are included in this prospectus. The unaudited pro forma consolidated financial statements are based on the audited historical consolidated financial statements of Abraxas Energy for the year ended December 31, 2008, as adjusted to reflect the sale of common units in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds.” Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

Estimated Cash Available for Distribution for the Twelve Month Period Ending June 30, 2010

Set forth below is a Statement of Estimated Cash Available for Distribution that reflects our estimate of our ability to generate sufficient cash flow to be able to pay the initial quarterly distributions on all of our units for the twelve months ending June 30, 2010. The estimated cash available for distribution should not be viewed as our projection of the actual available cash from operations that we will generate during the twelve months ending June 30, 2010.

We believe that we will be able to generate the estimated cash available for distribution and pay distributions to all of our unitholders at the initial quarterly distribution rate for the twelve months ending June 30, 2010. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this belief. We cannot assure you that our assumptions will be realized or that we will generate the estimated cash available for distribution, in which event we may not be able to pay the initial quarterly distributions on our units (absent borrowings under our credit facility, to the extent permitted). When considering how we calculate estimated cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus which discuss factors that could cause cash available for distribution to vary significantly from our estimates.

We do not as a matter of course make public projections as to future revenue, earnings or other results. However, we have prepared the estimated financial information set forth below in the table entitled “Statement of Estimated Cash Available for Distribution.” The accompanying estimated financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to estimated financial information, but was prepared, in our view, on a reasonable basis and reflects our current estimates and judgments to the best of our knowledge and belief, that we can generate the cash necessary to pay distributions on all of our units at the initial distribution rate. However, this information is not factual and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the estimated financial information.

Neither our independent auditors nor any other independent accountants have compiled, examined or performed any procedures with respect to the estimated financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability. Accordingly, they assume no responsibility for the estimated financial information. The auditors’ reports included in this prospectus relate to our historical financial information and they do not extend to the estimated financial information and should not be read to do so.

We do not undertake any obligation to publicly release the results of any future revisions we may make to the estimated financial information or to update the estimated financial information or the assumptions used to prepare it to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate our estimated cash available necessary to pay the initial quarterly distributions on all of our units for the twelve months ending June 30, 2010.

Abraxas Energy

Statement of Estimated Cash Available for Distribution


	Twelve Months Ending June 30, 2010
	Assuming no exercise of underwriters’ over-allotment option			Assuming exercise of underwriters’ over- allotment option
	(In thousands, except per unit amounts)
Operating revenues	$	41,128		$	41,128
Operating expenses
Lease operating expenses		13,949			13,949
Production taxes		3,907			3,907
General and administrative		3,383			3,383

Total operating expenses		21,239			21,239
Depreciation, depletion and amortization		15,166			15,166
Amortization of deferred financing fees		1,082			1,082
Loss (gain) on derivative contracts		(22,659	)		(22,659	)
Equity-based compensation		200			200
Net interest expense(a)		10,722			10,632

Net income		15,378			15,468
Adjustments to reconcile net income to Adjusted EBITDA:
Plus:
Depreciation, depletion and amortization		15,166			15,166
Amortization of deferred financing fees		1,082			1,082
Net interest expense(a)		10,722			10,632	(b)

Estimated Adjusted EBITDA(c)		42,348			42,348
Adjustments to reconcile Estimated Adjusted EBITDA to Estimated Cash Available for Distribution:
Less:
Cash interest expense		10,322			10,232
Equity-based compensation		(200	)		(200	)
Cash payment on phantom units(d)		—			—
Maintenance capital expenditures(e)		10,637			10,637
Growth capital expenditures		—			—

Estimated Cash Available for Distribution	$	21,589		$	21,679

Distributions:
Distribution per unit	$	1.50		$	1.50
Distributions to:
General partner	$	385		$	391
Public common unitholders		2,003			2,303
Private Investors		9,015			9,015
Restricted unitholders		78			78
Abraxas Petroleum and its affiliates		7,698			7,698

Total cash distributions	$	19,179		$	19,485

Excess of Estimated Cash Available for Distribution over Total cash distributions	$	2,410		$	2,194

(a)	Net interest expense includes non-cash accretion of our asset retirement obligation.

(b)	We have assumed that the net proceeds from the exercise in full of the underwriters’ over-allotment option would be used to further reduce indebtedness outstanding under our subordinated credit facility which would reduce interest expense by $0.1 million.

(c)

For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, which we refer to as GAAP, please see “Prospectus Summary—Abraxas Energy Partners, L.P.—Non-GAAP Financial Measures.”

(d)

We have assumed that the portion of phantom units that will vest during the twelve months ending June 30, 2010 will not achieve the performance milestone multiplier of 1.0: therefore, the cash settlement equals $0. For more information on the phantom units, see “Management—Executive Compensation” and “—Long-Term Incentive Plan—Phantom Unit Awards.”

(e)	For purposes of this table, we have assumed that we will fund all of our maintenance capital expenditures for the twelve months ending June 30, 2010 with cash flow from operations.

Unaudited Pro Forma Consolidated Available Cash for the Year Ended December 31, 2008

If we had completed this offering on January 1, 2008, our pro forma available cash for the year ended December 31, 2008 would have been approximately $26.1 million. These amounts would have been sufficient by approximately $6.9 million to pay the full initial distribution amount on all of our units for the year ended December 31, 2008.

We believe that we will have sufficient cash available for distribution to pay the full quarterly distributions at the initial distribution rate of $0.375 per unit on all of our units for each quarter during the twelve months ending June 30, 2010. See “—Assumptions and Considerations” below for the specific assumptions underlying this belief.

Unaudited pro forma consolidated available cash includes $0.8 million per year of incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and director, accounting, reservoir engineering and legal fees. Pursuant to our omnibus agreement, we currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and administrative expenses, subject to annual adjustments for inflation and acquisition or other expansion adjustments. For more information, please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement.” Incremental expenses are not reflected in our pro forma consolidated financial statements for the year ended December 31, 2008.

The pro forma financial statements upon which pro forma available cash is based do not purport to present our results of operations had this offering actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distribution that we might have generated had we been formed in earlier periods.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2008, the amount of cash we would have had available for distributions to our unitholders, assuming in each case that this offering had been consummated at the beginning of the period presented.

Abraxas Energy

Unaudited Pro Forma Consolidated Available Cash


	Year Ended December 31, 2008
	Assuming no exercise of the underwriters’ over-allotment option			Assuming exercise of the underwriters’ over-allotment option
	(In thousands, except per unit data)
Pro Forma Net Loss(a)	$	(41,610	)	$	(41,521	)
Plus:
Depreciation, depletion and amortization		20,955			20,955
Amortization of deferred financing fees		1,054			1,054
Net interest expense(b)		10,116			10,027	(c)
Unrealized loss (gain) on derivative contracts		(37,860	)		(37,860	)
Ceiling-test impairment(d)		97,121			97,121

Adjusted EBITDA(e)	$	49,776		$	49,776
Less:
Cash interest expense(f)		9,610			9,521
Cash payment on phantom units(g)		267			267
Capital expenditures(h)		13,400			13,400
Incremental expenses(i)		800			800
Financing fees(j)		(358	)		(358	)

Pro Forma Available Cash	$	26,057		$	26,146

Distributions per unit	$	1.50		$	1.50

Pro Forma Cash Distributions:
Distributions to:
General partner	$	385		$	391
Public common unitholders		2,003			2,303
Private Investors		9,015			9,015
Restricted unitholders		78			78
Abraxas Petroleum and its affiliates		7,698			7,698

Total cash distributions	$	19,179		$	19,485

Excess	$	6,878		$	6,661

(a)	Reflects net loss of Abraxas Energy derived from its audited historical consolidated financial statements for the year ended December 31, 2008, giving pro forma effect to this offering.

(b)	Net interest expense includes non-cash accretion of our asset retirement obligation.

(c)	We have assumed that the net proceeds from the exercise in full of the underwriters’ over-allotment option would be used to further reduce indebtedness outstanding under our subordinated credit facility which would reduce interest expense by $0.1 million.

(d)	Reflects the ceiling-test impairment recorded as a result of the standardized measure of future net cash flows from our proved reserves at December 31, 2008 being lower than our full-cost pool.

(e)

(f)	Cash interest expense includes interest associated with borrowings under our credit facility and subordinated credit facility.

(g)

We have assumed that 25% of the phantom units awarded in connection with the St. Mary Acquisition vested during the twelve month period and achieved the maximum performance milestone multiplier of 2.0. We further assumed a market price of $7.67 per unit and a gradual increase in quarterly cash distributions from $0.375 per unit to $0.44 per unit.

(h)	These capital expenditures reflect the actual capital that Abraxas Energy spent on our properties for exploitation and development activities.

(i)

Represents the incremental expenses that we expect to incur as a result of being a publicly traded partnership of approximately $0.8 million per year. These costs include annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and director, accounting, reservoir engineering and legal fees.

(j)	Reflects an in-kind payment to the Private Investors of $0.0625 per unit for the fourth quarter of 2008 pursuant to amendment no. 1 of the exchange and registration rights agreement.

Assumptions and Considerations

Based on the assumptions outlined below, we expect to generate cash flow from operations in an amount sufficient to fund our budgeted capital expenditures, establish cash reserves and pay quarterly distributions on all of our units at the initial quarterly distribution rate for the twelve months ending June 30, 2010.

While we believe that these assumptions are reasonable in light of our current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to pay the full initial quarterly distribution (absent borrowings under our credit facility, to the extent permitted), or any amount, in which event the market price of our common units is likely to decline substantially. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient capital expenditures to maintain or grow our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distribution may be considered a return of part of your investment in us as opposed to a return on your investment. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors,” and “Cautionary Note Regarding Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production. The following table sets forth information regarding net production of oil and gas for the year ended December 31, 2008 and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008	Estimated Twelve Months Ending June 30, 2010
Production:
Oil (MBbl)	452	484
Gas (MMcf)	5,505	5,074
Gas equivalents (MMcfe)	8,218	7,982
Daily Production:
Oil (Bopd)	1,235	1,328
Gas (Mcfpd)	15,040	13,901
Gas equivalents (Mcfepd)	22,453	21,869

We estimate that our production for the twelve months ending June 30, 2010 will be 8.0 MMcfe, which represents a decline of 3% as compared to the year ended December 31, 2008. Our estimated production for the twelve months ending June 30, 2010 reflects natural field declines offset by production that we believe will be generated by our maintenance capital expenditures.

We define maintenance capital expenditures as those expenditures necessary to replace our reserves and maintain our current level of production. Growth capital expenditures are those expenditures necessary to increase our production and grow our asset base. We estimate that 86% of our production for the twelve months ending June 30, 2010 will be produced from wells producing on December 31, 2008 and that the remaining 14% will be produced from new wells and recompletion/workover projects, including production from wells that are currently classified as proved undeveloped. Historically, on the properties contributed to us by Abraxas Petroleum, we have added 1.0 Mcfepd of production for every $3,300 of capital expended. During the twelve months ending June 30, 2010, we estimate that we will spend $10.6 million on maintenance capital expenditures,

which includes new wells and recompletion/workover projects on our properties. We have not included any growth capital expenditures in our estimates for increasing our production or growing our asset base. We have assumed that we will be successful in finding oil and gas in commercial quantities based on our past drilling results. For the five years ended December 31, 2007, Abraxas Petroleum drilled 13 gross (10.2 net) wells on the properties contributed to us, of which 100% resulted in commercially productive wells. For the year ended December 31, 2008, Abraxas Petroleum and other operators drilled 40 gross (1.6 net) wells on our properties, of which 100% resulted in commercially productive wells.

Prices. The table below illustrates the relationship between realized prices and NYMEX prices for the year ended December 31, 2008 as compared to our estimate for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Estimated Twelve Months Ending June 30, 2010
Oil ($/Bbl):
Average NYMEX price	$	100.21	$	50.00
Realized price		92.89		43.50

Differential to NYMEX	$	7.31	$	6.50

Gas ($/Mcf):
Average NYMEX price	$	8.88	$	5.25
Realized price		7.52		3.95

Differential to NYMEX	$	1.36	$	1.30

Gas Equivalents ($/Mcfe):
Realized price	$	10.15	$	5.15

We have estimated average NYMEX oil and gas prices of $50.00 per barrel and $5.25 per Mcf, respectively, for the twelve months ending June 30, 2010 based on NYMEX futures prices on March 2, 2009 that averaged $52.63 per barrel for oil and $5.44 per Mcf for gas for the twelve months ending June 30, 2010. For the year ended December 31, 2008, average NYMEX oil and gas prices were $100.21 per barrel and $8.88 per Mcf, respectively. We have applied differentials to the NYMEX prices which reflect our historical averages and result in estimated realized prices for the twelve months ending June 30, 2010. For the year ended December 31, 2008, the average NYMEX price reflects the average daily spot (or cash) price for WTI (West Texas Intermediate) oil and Henry Hub gas.

Our oil price differential to the average NYMEX price is expected to average $6.50 for the twelve months ending June 30, 2010 as compared to $7.31 for the year ended December 31, 2008. Our gas price differential to the average NYMEX price is expected to average $1.30 for the twelve months ending June 30, 2010 as compared to $1.36 for the year ended December 31, 2008. We expect that our differentials will be lower for the twelve months ending June 30, 2010 due to lower NYMEX oil and gas prices as compared to the year ended December 31, 2008 as the majority of our marketing agreements are based on a percentage of the prevailing market price.

Hedging. The following table summarizes our realized oil and gas prices for the year ended December 31, 2008 and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Estimated Twelve Months Ending June 30, 2010
Oil ($/Bbl):
Realized price	$	92.89	$	43.50
Realized loss (gain) on derivative contracts		13.75		(23.76	)

Combined realized oil price	$	79.14	$	67.26

Gas ($/Mcf):
Realized price	$	7.52	$	3.95
Realized loss (gain) on derivative contracts		0.55		(2.20	)

Combined realized gas price	$	6.97	$	6.15

Gas Equivalents ($/Mcfe):
Combined realized price	$	9.02	$	7.99

We estimate a realized gain or loss on derivative contracts for the twelve months ending June 30, 2010 based upon the derivative contracts, which we sometimes refer to as hedging arrangements, that we have entered into, as detailed below. For the twelve months ending June 30, 2010, we have hedging arrangements covering an average 948 barrels of oil per day at a weighted average price of $83.28 per barrel and 9,869 Mcf of gas per day at a weighted average price of $8.34 per MMbtu, or 71% of our total estimated daily production. These hedging arrangements result in a realized gain of $33.28 per barrel and a realized gain of $3.09 per Mcf for the volumes subject to the derivative contracts and a realized gain of $23.76 per barrel and a realized gain of $2.20 per Mcf when applied to our total estimated production for the twelve months ending June 30, 2010. We have elected out of hedge accounting as prescribed by applicable accounting rules. For more information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives.” Gas, including NYMEX futures, spot prices and hedging arrangements, is priced in MMbtu; however, gas volumes are typically reported in Mcf (1 MMbtu equals 1 Mcf of gas with a heating value of 1,000 Btu). We have presented gas prices in Mcf, unless the prices are directly related to a hedging arrangement. For the year ended December 31, 2008, we realized a loss of $13.75 per barrel of oil and a loss of $0.55 per Mcf of gas on our derivative contracts.

The following table summarizes our oil derivative contracts at December 31, 2008:


	NYMEX-based Fixed Price Swaps
	Barrels per day	Price ($/Bbl)
Year 2009	1,000	$	83.80
Year 2010	895	$	83.26
Year 2011	810	$	86.45

The following table summarizes our gas derivative contracts at December 31, 2008:


	NYMEX-based Fixed Price Swaps
	MMbtu per day	Price ($/MMbtu)
Year 2009	10,595	$	8.45
Year 2010	9,130	$	8.22
Year 2011	8,010	$	8.10

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk” for more information.

Oil and Gas Revenues. The following table illustrates the primary components of our oil and gas revenues and our realized loss (gain) on derivative contracts for the year ended December 31, 2008 and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Estimated Twelve Months Ending June 30, 2010
	(In thousands)
Oil revenues	$	42,003	$	21,086
Gas revenues		41,388		20,042

Total oil and gas revenues	$	83,391	$	41,128

Realized loss (gain) on oil derivative contracts	$	6,220	$	(11,516	)
Realized loss (gain) on gas derivative contracts		3,047		(11,143	)

Total realized loss (gain) on derivative contracts	$	9,267	$	(22,659	)

We estimate oil and gas revenues for the twelve months ending June 30, 2010 based upon our estimated production multiplied by the estimated average NYMEX price less the estimated differential. Realized loss (gain) on derivative contracts is based upon our hedging arrangements and reflect the difference between the estimated NYMEX price and the weighted average price in our derivative contracts for the production volumes subject to our derivative contracts for the twelve months ending June 30, 2010. At December 31, 2008 and continuing through December 2011, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas. For the year ended December 31, 2008, our oil and gas revenues were $83.4 million.

Gas comprises 64% and oil comprises 36% of our total estimated production for the twelve months ending June 30, 2010. As a consequence, our revenues are more sensitive to changes in gas prices than to changes in oil prices. The following tables show estimated Adjusted EBITDA sensitivities under various assumed NYMEX gas and oil prices for the twelve months ending June 30, 2010. The estimated Adjusted EBITDA amounts shown below are based on realized gas prices that take into account our average NYMEX gas price differential assumption of $1.30 and realized oil prices that take into account our average NYMEX oil price differential assumption of $6.50 and also include realized gains and losses on derivative contracts based on our current hedging arrangements. We have assumed no changes in our production based on changes in prices and that our swap counter-party will perform as expected.


Gas Price Sensitivities:	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data and percentages)
NYMEX gas price ($/Mcf)	$	4.25		$	5.25		$	6.25		$	7.25
NYMEX oil price ($/Bbl)	$	50.00		$	50.00		$	50.00		$	50.00
Equivalent daily production (Mcfepd)		21,869			21,869			21,869			21,869
Percentage gas		64	%		64	%		64	%		64	%
Total revenues	$	35,983		$	41,128		$	46,298		$	51,493
Lease operating expenses		13,949			13,949			13,949			13,949
Production taxes		3,418			3,907			4,398			4,892
General and administrative		3,383			3,383			3,383			3,383
Equity-based compensation		200			200			200			200
Realized loss (gain) on derivative contracts		(26,261	)		(22,659	)		(19,057	)		(15,455	)

Adjusted EBITDA	$	41,294		$	42,348		$	43,425		$	44,524


Oil Price Sensitivities:	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data and percentages)
NYMEX oil price ($/Bbl)	$	40.00		$	50.00		$	60.00		$	70.00
NYMEX gas price ($/Mcf)	$	5.25		$	5.25		$	5.25		$	5.25
Equivalent daily production (Boepd)		3,645			3,645			3,645			3,645
Percentage oil		36	%		36	%		36	%		36	%
Total revenues	$	36,208		$	41,128		$	46,065		$	51,019
Lease operating expenses		13,949			13,949			13,949			13,949
Production taxes		3,440			3,907			4,376			4,847
General and administrative		3,383			3,383			3,383			3,383
Equity-based compensation		200			200			200			200
Realized loss (gain) on derivative contracts		(26,119	)		(22,659	)		(19,199	)		(15,739	)

Adjusted EBITDA	$	41,355		$	42,348		$	43,356		$	44,379

As NYMEX oil and gas prices decline, our Adjusted EBITDA does not decline proportionately due to the effects of our derivative contracts. However, the change in production taxes, which are calculated as a percentage of our oil and gas revenues, excluding the effects of our derivative contracts, is correlated with commodity prices. Furthermore, we have assumed no changes in production, lease operating expenses or differentials during the twelve months ended June 30, 2010. Over the long-term, a sustained decline in oil and gas prices would likely lead to a decline in production and lease operating expenses as well as a reduction in our realized oil and gas prices. Therefore, the foregoing table is not illustrative of the effects of changes in commodity prices for periods subsequent to June 30, 2010.

For the year ended December 31, 2008, approximately 43% of our production was produced from our properties located in the Rocky Mountain and Mid-Continent regions of the United States. Historically, production from these regions has experienced times of widening differentials from NYMEX. Approximately 45% of our total estimated production for the twelve months ending June 30, 2010 is estimated to be produced from our properties located in the Rocky Mountain and Mid-Continent regions of the United States. The following table shows estimated Adjusted EBITDA sensitivities under various assumed differentials to NYMEX for the twelve months ending June 30, 2010. The estimated Adjusted EBITDA amounts shown below are based on estimated average NYMEX prices of $50.00 per barrel of oil and $5.25 per Mcf of gas for the twelve months ending June 30, 2010 for the volumes not subject to our derivative contracts and also include realized gains and

losses on production volumes subject to our current derivative contracts. We have assumed no changes in our production based on changes in prices and that our swap counter-party will perform as expected.


	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data)
NYMEX oil price ($/Bbl)	$	50.00		$	50.00		$	50.00		$	50.00
Oil price differential ($/Bbl)	$	5.00		$	6.50		$	7.50		$	10.00
NYMEX gas price ($/Mcf)	$	5.25		$	5.25		$	5.25		$	5.25
Gas price differential ($/Mcf)	$	1.00		$	1.30		$	1.50		$	2.00
Equivalent daily production (Mcfepd)		21,869			21,869			21,869			21,869
Total revenues	$	43,600		$	41,128		$	39,494		$	35,458
Lease operating expenses		13,949			13,949			13,949			13,949
Production taxes		4,142			3,907			3,752			3,368
General and administrative		3,383			3,383			3,383			3,383
Equity-based compensation		200			200			200			200
Realized loss (gain) on derivative contracts		(22,659	)		(22,659	)		(22,659	)		(22,659	)

Adjusted EBITDA	$	44,585		$	42,348		$	38,869		$	37,217

As oil and gas differentials increase, our Adjusted EBITDA will decline proportionately due to the effects of our hedging arrangements, which are NYMEX based. We have not hedged basis differentials; therefore, our Adjusted EBITDA will decrease or increase if differentials differ from our historical averages. We have assumed no changes in production, lease operating expenses or NYMEX prices during the twelve months ending June 30, 2010. Over the long-term, a sustained increase in oil and gas differentials would likely lead to a decline in production and lease operating expenses as well as a reduction in our realized oil and gas prices. Therefore, the foregoing table is not illustrative of the effects of changes in differentials for periods subsequent to June 30, 2010.

We estimate that our production for the twelve months ending June 30, 2010 will be 8.0 Bcfe, or 21.9 MMcfepd. Our production levels may vary from our estimates for a number of reasons; therefore, the following table shows Adjusted EBITDA sensitivities under various percentages of estimated production for the twelve months ending June 30, 2010.


	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data and percentages)
Percentage of estimated production		95	%		100	%		105	%
NYMEX oil price ($/Bbl)	$	50.00		$	50.00		$	50.00
NYMEX gas price ($/Mcf)	$	5.25		$	5.25		$	5.25
Equivalent daily production (Mcfepd)		20,776			21,869			22,963
Total revenues	$	39,072		$	41,128		$	43,185
Lease operating expenses		13,252			13,949			14,647
Production taxes		3,712			3,907			4,103
General and administrative		3,383			3,383			3,383
Equity-based compensation		200			200			200
Realized loss (gain) on derivative contracts		(22,659	)		(22,659	)		(22,659	)

Adjusted EBITDA	$	41,184		$	42,348		$	43,509

As production increases or decreases, our Adjusted EBITDA changes accordingly as a result of changes in revenue, lease operating expenses and production taxes. We have assumed no changes in general and administrative expenses and equity-based compensation. Over the long-term, a sustained decline in oil and gas production would likely lead to a decline in Adjusted EBITDA. Therefore, the foregoing table is not illustrative of the effects of changes in estimated production for periods subsequent to June 30, 2010.

Capital Expenditures and Expenses

Capital Expenditures. We estimate that our cash capital expenditures for the twelve months ending June 30, 2010 will be approximately $10.6 million as compared to $26.2 million, $12.3 million and $131.9 million, respectively, on a pro forma basis for the years ended December 31, 2006, 2007 and 2008. The historical amounts reflect the actual capital expenditures spent on our properties, including capital expenditures of $118.5 million for property acquisitions for the year ended December 31, 2008. The $10.6 million of capital expenditures for the twelve months ending June 30, 2010, which we refer to as maintenance capital expenditures, are expected to consist of new wells and a number of recompletion and workover projects on our existing properties. Historically, on the properties contributed to us by Abraxas Petroleum, we have added 1.0 Mcfepd of production for every $3,300 of capital expended. We have used this historical average in our production estimate for the twelve months ending June 30, 2010 because we anticipate that most of our capital spending will be made on the properties contributed to us by Abraxas Petroleum. We expect to finance these maintenance capital expenditures out of cash flow from operations. We intend to fund growth capital with a combination of cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities. We cannot assure you that any of these sources of capital will be available to us either in the amounts necessary or on terms acceptable to us.

Lease Operating Expenses. The following table summarizes lease operating expenses on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2008 and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data)
Lease operating expenses	$	14,608	$	13,949
Lease operating expenses ($/Mcfe)	$	1.78	$	1.75

We estimate that our lease operating expenses for the twelve months ending June 30, 2010 will be approximately $13.9 million as compared to $14.6 million for the year ended December 31, 2008.

Production Taxes. The following table summarizes production taxes, which include ad valorem taxes, on an aggregate basis and as a percentage of oil and gas revenues for the year ended December 31, 2008 and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008			Estimated Twelve Months Ending June 30, 2010
	(In thousands, except percentages)
Oil and gas revenues	$	83,391		$	41,128
Production taxes	$	7,968		$	3,907
Production taxes as a percentage		9.6	%		9.5	%

Our production taxes are calculated as a percentage of our oil and gas revenues. In general, as prices and volumes increase, our production taxes increase and as prices and volumes decrease, our production taxes decrease.

General and Administrative Expenses. We estimate that our general and administrative expenses for the twelve months ending June 30, 2010 will be approximately $3.4 million, which includes $0.8 million of incremental expenses that we expect to incur as a result of being a publicly traded partnership. We expect our incremental expenses will include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and director, accounting, reservoir engineering and legal fees. Pursuant to our omnibus agreement, we currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and administrative expenses, subject to annual adjustments for inflation and acquisition or other expansion adjustments. For more information, please read “Certain Relationships and Related Party Transactions—Omnibus Agreement.”

Interest Expense. We intend to use the net proceeds from this offering, together with our general partner’s proportionate capital contribution to partially repay the indebtedness outstanding under our subordinated credit facility. We have estimated $10.3 million of net cash interest expense for the twelve months ending June 30, 2010. In addition, we have also estimated that we will fund our maintenance capital expenditures for the twelve months ending June 30, 2010 of $10.6 million out of cash flow from operations.

Regulatory, Industry and Economic Factors. Our estimate for the twelve months ending June 30, 2010 is based on the following significant assumptions related to regulatory, industry and economic factors:

•

There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

•

There will not be any major adverse change in the portions of the energy industry or in general economic conditions; and

•

Market, insurance and overall economic conditions will not change substantially.

Distributions

Distributions on our units for the twelve months ending June 30, 2010 are expected to be $19.2 million in the aggregate (assuming no exercise of the over-allotment option). Quarterly distributions will be paid within 45 days after the close of each quarter.

How We Make Cash Distributions

Distributions of Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to all of our unitholders of record on the applicable record date. We will adjust the initial quarterly distribution for the period from the closing of this offering through June 30, 2009 based on the actual length of the period. We will distribute 98% of our available cash to our common unitholders, pro rata, and 2% of our available cash to our general partner.

The term “available cash,” for any fiscal quarter, means all cash on hand as of the date of determination of available cash for such quarter, less the amount of cash reserves established by our general partner to:

•

provide for the proper conduct of our business (including reserves for future capital expenditures and for acquisitions of additional oil and gas properties);

•

comply with applicable law, any of our debt instruments or other agreements; or

•

provide funds for distribution to our unitholders for any one or more of the next four quarters.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

The following table shows selected historical consolidated financial data of Abraxas Petroleum and our historical and pro forma consolidated financial data for the periods and as of the dates indicated. The selected consolidated historical financial data as of and for the years ended December 31, 2004, 2005 and 2006, and the periods from January 1 to May 24, 2007 and from May 25 to December 31, 2007, and for the year ended December 31, 2008 are derived from Abraxas Petroleum’s and our audited consolidated financial statements. Our selected historical consolidated financial data as of December 31, 2007 are derived from our audited consolidated financial statements. The financial condition and results of operations of Abraxas Petroleum for the periods up to May 24, 2007 are referred to in this prospectus as “Predecessor,” and the financial condition and results of operations for periods subsequent to May 24, 2007 are referred to as “Successor” and represent only those of Abraxas Energy. The selected pro forma consolidated financial data for the year ended December 31, 2008 are derived from our unaudited pro forma consolidated financial statements included in this prospectus beginning on page F-2 and give effect to the St. Mary Acquisition and the completion of this offering and the use of proceeds from this offering as described in “Use of Proceeds.”

The unaudited pro forma consolidated statement of operations data for the year ended December 31, 2008 assume that the St. Mary Acquisition and this offering occurred on January 1, 2008.


	Predecessor											Successor
	Abraxas Petroleum											Abraxas Energy
	Year Ended December 31,								January 1 - May 24, 2007			May 25 - December 31, 2007			Year Ended December 31,
	2004			2005		2006			January 1 - May 24, 2007			May 25 - December 31, 2007			2008
	(In thousands, except per share/unit data)
Consolidated Statements of Operations Data:
Operating revenue:
Oil and gas production revenues	$	33,073		$	47,905	$	49,448		$	18,791		$	22,148		$	83,391
Other(1)		781			1,311		1,629			514			—			—

Total operating revenue		33,854			49,216		51,077			19,305			22,148			83,391
Operating costs and expenses:
Lease operating and production taxes		8,567			11,094		11,776			4,757			5,136			22,577
Depreciation, depletion and amortization		7,213			8,914		14,939			5,773			7,039			20,063
Ceiling-test impairment		—			—		—			—			—			97,121
General and administrative		5,238			5,757		5,160			1,867			987			2,657
Other		671			756		819			295			—			—

Total operating expenses		21,689			26,521		32,694			12,692			13,162			142,418

Operating income (loss)		12,165			22,695		18,383			6,613			8,986			(59,027	)
Net interest expense		17,857			13,970		16,738			6,371			1,774			10,181
Amortization of deferred financing fees		1,848			1,589		1,591			632			121			988
Financing fees		1,657			—		—			—			—			359
(Gain) on debt redemption		(12,561	)		—		—			—			—			—
Loss (gain) on derivative contracts		—			591		(646	)		218			4,125			(28,333	)
Loss on debt extinguishment		—			—		—			—			6,455			—
Other expense		387			274		—			—			—			1,105

Income (loss) from continuing operations before income tax		2,977			6,271		700			(608	)		(3,489	)		(43,327	)
Income tax (benefit)		(6,060	)		—		—			—			—			—

Income (loss) from continuing operations(3)	$	9,037		$	6,271	$	700		$	(608	)	$	(3,489	)	$	(43,327	)

Income (loss) per common share/unit from continuing operations—diluted	$	0.23		$	0.15	$	0.02		$	(0.01	)	$	(0.31	)	$	(3.81	)

Weighted average common shares/units outstanding—diluted(2)		38,895			41,164		43,862			42,795			11,362			11,360

(1)	Includes rig and other revenue.

(2)

For the periods January 1 - May 24, 2007, and May 25 - December 31, 2007 and for the year ended December 31, 2008 shares/units issuable in connection with options or warrants are not included in diluted shares/units. Inclusion of these shares/units would be antidilutive due to losses incurred in these periods.

(3)	Excludes net income from discontinued operations of $3.3 million and $12.8 million in 2004 and 2005, respectively, of the Predecessor as the information is not relevant to the properties contributed to the Successor.


	Pro Forma
	Abraxas Energy
	St. Mary Acquisition			After Offering
	Year Ended December 31,
	2008
	(In thousands, except per unit data)
Unaudited Consolidated Statements of Operations Data:
Oil and gas production revenue	$	87,045		$	87,045
Lease operating and production taxes		23,621			23,621
Depreciation, depletion and amortization		20,955			20,955
General and administrative		2,657			2,657
Net interest expense		10,704			10,116
Amortization of deferred financing fees		1,054			1,054
Financing Fees		359			359
Loss (gain) on derivative contracts		(28,333	)		(28,333	)
Ceiling-test impairment		97,121			97,121
Other		1,105			1,105

Net loss	$	(42,198	)	$	(41,610	)

Net loss per common unit-basic and diluted	$	(3.30	)	$	(3.25	)

Common units outstanding-basic and diluted		12,786			12,786


	Predecessor									Successor					Pro Forma After Offering
	Abraxas Petroleum									Abraxas Energy
	At December 31,									At December 31,		At December 31,
	2004			2005			2006			2007		2008
	(In thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	(4,592	)	$	(4,880	)	$	(3,719	)	$	3,740	$	(14,595	)	$	(7,062	)
Total assets		152,685			121,866			116,940			105,703		169,240			169,240
Current maturities of long-term debt		—			—			—			—		40,000			32,467
Long-term debt		126,425			129,527			127,614			45,900		125,600			125,600
Stockholders’/partners’ equity (deficit)		(53,464	)		(23,701	)		(22,165	)		49,688		(12,492	)		(4,959	)
Other Data:
Capital expenditures for the period	$	9,269		$	35,350		$	26,346		$	20,708	$	131,900		$	131,900

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical and Pro Forma Consolidated Financial Data” and the financial statements and the related notes thereto included elsewhere in this prospectus. The following discussion and analysis of our results of operations for 2007 combines the results of operations for Abraxas Petroleum from January 1 to May 24, 2007 and our results from May 25 to December 31, 2007. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

General

We are a holding company, and our operating assets are owned directly or indirectly by our operating subsidiary, Abraxas Operating. Our general partner is a wholly-owned subsidiary of Abraxas Petroleum, and has sole responsibility for conducting our business and managing our operations. Upon the completion of this offering, Abraxas Petroleum will continue to beneficially own a 2% general partner and a 40.1% limited partner interest in us, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and that Abraxas Petroleum does not purchase any common units in this offering.

Basis of Presentation

Because we were not formed until May 2007, our historical financial statements as well as the discussion of the results of operations and period-to-period comparisons covering these historical results include the historical financial statements of Abraxas Petroleum for periods up to May 24, 2007 and our historical financial statements for the period from May 25 to December 31, 2007 and the year ended December 31, 2008. Because the 2007 historical results of Abraxas Petroleum include combined information for the properties retained by Abraxas Petroleum as well as our oil and gas properties, these historical results of operations and period-to-period comparisons are not indicative of our future results. Please see “Selected Historical and Pro Forma Consolidated Financial and Operating Data” and our Unaudited Historical Pro Forma Consolidated Financial Statements for financial information relating to us, as of the dates and for the periods indicated.

Formation Transactions

In May 2007, we entered into the following transactions which we refer to as the Formation Transactions:

•

Abraxas Petroleum contributed properties to Abraxas Operating;

•

we borrowed $35.0 million under our credit facility; and

•

we issued and sold 6,002,408 of our common units to certain private investors, in consideration for gross proceeds of approximately $100.0 million.

•

$139.3 million was used to refinance and repay Abraxas Petroleum’s Floating Rate Secured Notes due 2009 (including a call premium and accrued and unpaid interest of $14.3 million);

•

$0.9 million was used to repay indebtedness under Abraxas Petroleum’s credit facility;

•

$10.3 million was used to pay fees and expenses, including placement fees to A.G. Edwards & Sons, Inc. of $8.6 million and legal and accounting fees of $1.7 million; and

•

$7.0 million was used to make a distribution of excess capital to Abraxas Petroleum.

St. Mary Acquisition

On January 31, 2008, we acquired certain oil and gas properties from St. Mary for $126.0 million. The properties are located in a number of basins throughout the central portion of the United States, principally in the Rocky Mountain and Mid-Continent regions. We borrowed $79.7 million under our credit facility and $50.0 million under our subordinated credit facility, for a total of $129.7 million, to finance this acquisition and pay fees and expenses incurred in connection with the acquisition.

How We Evaluate Our Operations

Our financial results depend upon many factors which significantly affect our results of operations including the following:

•

the oil and gas volumes we produce;

•

the sales price of our oil and gas production;

•

the level of our operating and general and administrative expenses;

•

the availability of capital;

•

the level of and interest rates on borrowings; and

•

the level and success of exploitation and development activity.

Production Volumes. Because our proved reserves will decline as oil and gas are produced, unless we conduct successful exploitation and development activities, or acquire additional properties containing proved reserves, our reserves and production will decrease. Approximately 92% of the estimated ultimate recovery of our proved developed reserves as of December 31, 2008 had been 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, exploitation and development projects.

Abraxas Energy had cash capital expenditures for 2008 of $131.9 million which included $118.5 million for property acquisitions. We have a capital budget for 2009 of $12.0 million, the exact amount of which will depend on our success rate, production levels and commodity prices.

The following table presents historical net production volumes for the years ended December 31, 2006, 2007 and 2008:


	Year Ended December 31,
	2006	2007	2008
Total production (MMcfe)	7,718	5,984	8,218
Average daily production (Mcfepd)	21,144	16,394	22,453

Commodity Prices and Hedging Activities. The results of our operations are highly dependent upon the prices received for our oil and gas. The prices we receive for our oil and gas are dependent upon spot market prices, our differentials and the effectiveness of our hedging arrangements.

Substantially all of our oil and gas sales are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices we receive for our oil and gas are dependent upon numerous factors beyond our control. Significant declines in commodity prices could have a material adverse effect on our financial condition, results of operations, quantities of reserves recoverable on an economic basis, and the distributions we can make to our unitholders. Recently, oil and gas prices have been volatile. Supply and geopolitical uncertainties resulted in significant price volatility during 2008 with oil prices rising during the first half of the year to record levels before falling by approximately 70% during the second half of the year. Spot prices for West Texas Intermediate (WTI) oil averaged $100.21 per barrel for the year, with a low price of $33.87 per barrel in December 2008 and a high price of $145.28 per barrel in July 2008. During 2008, the gas market continued to be driven by high storage inventories and mild weather conditions across much of the country. Spot prices for Henry Hub gas averaged $8.88 per MMbtu for the year, with a low price of $5.40 per MMbtu in December 2008 and a high price of $13.28 per MMbtu in July 2008. The NYMEX futures prices for oil and gas were $44.60 per barrel and $5.62 per MMbtu at December 31, 2008 and $44.76 per barrel and $4.20 per MMbtu at March 2, 2009. The current global recession has had a significant impact on commodity prices and our operations. If commodity prices remain depressed, our revenues, profitability and cash flow from operations will decrease which could cause us to alter our business plan including reducing our drilling activity and the level of cash distributions to our unitholders.

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

•

basis differentials which are dependent on actual delivery location;

•

adjustments for quality and Btu content; and

•

gathering, processing and transportation costs.

During 2008, our differentials averaged $7.31 per barrel of oil and $1.36 per Mcf of gas. We expect these differentials will decrease as a result of lower commodity prices because the majority of our marketing agreements are based on a percentage of the prevailing market price. On a pro forma basis during 2008, our differentials would have averaged $8.11 per barrel of oil and $1.40 per Mcf of gas before any impact from our derivative contracts.

Our credit facility required us to enter into hedging arrangements for specified volumes, which equated to approximately 85% of our estimated oil and gas production through 2011. At December 31, 2008 and continuing through December 2011, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas. We intend to enter into derivative contracts, which we sometimes refer to as hedging arrangements, in the future to reduce the impact of oil and gas price volatility on our cash flow. By removing a significant portion of price volatility of our future oil and gas production, we believe we have mitigated, but not eliminated, the potential effects of changing oil and

gas prices on our cash flow from operations for those periods. 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 our contract prices are higher than prevailing market prices, we will sustain realized and unrealized gains on our derivative contracts. Current market conditions also elevate concern over counter-party risks related to our commodity derivative contracts.

We actively monitor the credit exposure and risks associated with our counterparties. We have all of our commodity swaps with one major financial institution, Société Générale. Should this counterparty not perform, we may not realize the benefit of our hedging arrangements when market prices are below our contract prices. We are not currently aware of any inability on the part of our counterparty to perform under our contracts. Notwithstanding, we are not able to predict sudden changes in the credit worthiness of our counterparty.

We have elected out of hedge accounting as prescribed by applicable accounting rules. Please read “Risk Factors—Risks Related to Our Business—Our hedging activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions,” “Risk Factors—Risks Related to Our Business—If the prices at which we hedge our oil and gas production are less than prevailing market prices, our ability to maintain or increase cash distributions could be adversely affected,” “—Critical Accounting Policies—Accounting for Derivatives” and “—Quantitative and Qualitative Disclosure about Market Risk—Hedging Activity and Sensitivity.”

At December 31, 2008, we had the following derivative contracts in place:


Period Covered	Product	Volume (Production per Day)	Fixed Price
Year 2009	Gas	10,595 MMbtu	$	8.45
Year 2009	Oil	1,000 Bbl	$	83.80
Year 2010	Gas	9,130 MMbtu	$	8.22
Year 2010	Oil	895 Bbl	$	83.26
Year 2011	Gas	8,010 MMbtu	$	8.10
Year 2011	Oil	810 Bbl	$	86.45

Operating and General and Administrative Expenses

In evaluating our operations, we frequently monitor and assess our lease operating and general and administrative, or G&A expenses, in terms of absolute dollars and on a per Mcfe basis. We believe that this measure allows us to better evaluate our operating efficiency and is used by us in reviewing the economic feasibility of a potential acquisition or development project.

Operating Expenses. Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Operating expenses do not include G&A expenses. A majority of our operating cost components are variable and increase or decrease as the level of production increases or decreases. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed and do not fluctuate with changes in production volumes, but can fluctuate depending on activities performed during a specific period. Abraxas Petroleum and Abraxas Operating have entered into an operating agreement, under which Abraxas Petroleum will operate our oil and gas properties that are not subject to operating agreements with other parties. Abraxas Petroleum will continue to operate our properties that are subject to operating agreements, to the extent Abraxas Petroleum is the operator of record. We will reimburse Abraxas Petroleum for its costs in performing the services on our behalf under the operating agreements, plus related expenses. Our operating expenses on a per unit basis increased in 2008 as a result of the St. Mary Acquisition because the producing properties we acquired from St. Mary are primarily pumping oil wells which cost more to operate than the producing properties contributed to us from Abraxas Petroleum which are primarily flowing gas wells.

States regulate the development, production, gathering and sale of oil and gas, including imposing production and other taxes and requirements for obtaining drilling permits. Many states currently impose a production tax on oil and gas production. In addition to production taxes, a number of states impose ad valorem taxes on oil and gas properties and production equipment.

General and Administrative Expenses. Pursuant to our omnibus agreement, Abraxas Petroleum will perform administrative services for us and for Abraxas Operating, such as accounting, finance, land and engineering. We currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and administrative expenses, subject to annual adjustments for inflation and acquisition or other expansion adjustments. Thereafter, our payment obligations for general and administrative expenses to Abraxas Petroleum on our behalf are not fixed. We do not believe these expenses will materially increase, except in connection with acquisitions. We also expect to incur $0.8 million per year of incremental expenses as a result of being a publicly traded partnership.

Availability of Capital. As described more fully under “—Liquidity and Capital Resources” below, our sources of capital going forward will primarily be cash flow from operations, borrowings under our credit facility and proceeds from the sale of debt or equity securities. At March 2, 2009, we had $14.4 million of availability under our credit facility and after giving effect to the application of the net proceeds of this offering, we will have availability of $14.4 million from the current amount of our borrowing base of $140.0 million. For a description of our credit facility, please see “—Liquidity and Capital Resources—Credit Facility.”

Borrowings and Interest. At March 2, 2009, we had outstanding indebtedness of $165.6 million, of which $40.0 million was outstanding under our subordinated credit facility and $125.6 million was outstanding under our credit facility. In 2008, our cash interest expense for a full year would have been $10.2 million on a pro forma basis giving effect to the St. Mary Acquisition as if it had occurred on January 1, 2008. If our cash interest expense increases as a result of higher interest rates or increased borrowings under our credit facility, more cash flow from operations would be used to meet our 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 our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, as amended in February 2009, to fix our floating LIBOR based debt. Our 2-year interest rate swap arrangement for $100.0 million is at a fixed rate of 2.95%. The arrangement expires on August 12, 2010.

Exploitation and Development Activity. We believe that our quality asset base and our large inventory of drilling projects will help provide stability and growth in our cash distributions per unit over time. Abraxas Petroleum operates properties comprising over 75% of our estimated proved reserves at December 31, 2008, allowing for substantial control over the timing and incurrence of capital expenditures. We have identified 226 additional drilling locations (of which 129 were classified as proved undeveloped at December 31, 2008) on our existing leasehold, the successful development of which we believe could significantly increase our production and proved reserves. For the five years ended December 31, 2007, Abraxas Petroleum drilled 13 gross (10.2 net) wells on the properties contributed to us, of which 100% resulted in commercially productive wells. For the year ended December 31, 2008, Abraxas Petroleum and other operators drilled 40 gross (1.6 net) wells on our properties, of which 100% resulted in commercially productive wells.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire, exploit and develop additional reserves. The rate of production from our properties and our proved reserves will decline as our reserves are produced unless we conduct successful development and exploitation activities, acquire additional properties containing proved reserves, or, through engineering studies that identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploitation and development activities will result in increases in our proved reserves. If our proved reserves continue to decline in the future, our production will also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility will also decline, and we may be unable to pay distributions to our unitholders. In addition, approximately 39% of our total estimated proved reserves at December 31, 2008 were undeveloped. By their nature, estimates of undeveloped reserves are less certain than proved developed reserves. Recovery of such reserves will require significant capital expenditures and successful drilling

operations. For a more complete discussion of these risks please see “Risk Factors—Risks Related to Our Business—The estimated proved reserves we present are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Outlook

Oil and gas prices have been volatile over the past several years. Significant factors that will impact near-term commodity prices include the following:

•

the domestic and foreign supply of and demand for oil and gas;

•

the level of consumer product demand;

•

weather conditions;

•

political and economic conditions and events in foreign oil and gas producing countries, including those in the Middle East, South America and Russia;

•

actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;

•

technological advances affecting energy consumption and supply;

•

domestic and foreign governmental regulations and taxation;

•

the impact of energy conservation efforts;

•

the price and availability of alternative fuels.

A substantial portion of our estimated production is currently hedged through December 2011, and we intend to continue to enter into derivative contracts in the future, to help mitigate the impact of price volatility on our cash flow. At December 31, 2008 and continuing through December 2011, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas which are significantly higher than market prices on March 2, 2009 of $44.76 per barrel of oil and $4.20 per MMbtu of gas. While these derivative contracts will protect us when market prices are below our contract prices, they also prevent us from realizing an increase in cash flow when market prices are higher than our contract prices. We will sustain realized and unrealized losses to the extent our contract prices are lower than market prices and conversely, we will sustain realized and unrealized gains to the extent our contract prices are higher than market prices.

During the first half of 2008, the increase in commodity prices resulted in increased drilling activity and demand for drilling rigs, equipment and crews. However, during the second half of 2008, commodity prices declined approximately 70% which resulted in reduced drilling activity. Due to the low commodity price environment, we anticipate drilling service and labor costs, as well as costs of equipment and raw materials, to decline from recent historically high levels. Our operating expenses increased in 2008 as a result of the St. Mary Acquisition because the producing properties we acquired from St. Mary were primarily pumping oil wells which cost more to operate than the producing properties contributed to us from Abraxas Petroleum which are primarily flowing gas wells.

We expect to fund our capital expenditures with cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities. We estimate that we will have sufficient cash flow from operations after funding maintenance capital expenditures to enable us to pay the initial quarterly distribution of $0.375 per unit to unitholders for each quarter for the twelve months ending June 30, 2010. Please read “—Liquidity and Capital Resources” and “Cash Distribution Policy and Restrictions on Distributions” for more information.

We expect to continue to pursue acquisition opportunities in the future but we expect to experience competition for these assets from third parties. Moreover, Abraxas Petroleum is not prohibited from competing with us and will continue to evaluate acquisitions and dispositions that do not involve us. We believe that our structure as a pass-through vehicle for tax purposes with no incentive distribution rights will allow us to have a lower cost of capital for acquisition opportunities than many of our tax-paying competitors. Since the Formation Transactions, we successfully closed an acquisition of certain oil and gas properties from St. Mary for $126.0 million. These properties are located in numerous basins throughout the central portion of the United States, principally in the Rocky Mountain and Mid-Continent regions.

Factors Affecting Comparability of Future Results

You should read the discussion of our financial condition and results of operations in conjunction with the historical and pro forma financial statements included elsewhere in this Prospectus. Our future results could differ materially from our historical and pro forma results due to a variety of factors, including the following:

Historical results include properties retained by Abraxas Petroleum. Because we were not formed until May 2007, our historical financial statements as well as the discussion of the results of operations and period-to-period comparisons covering these historical results include the historical financial statements of Abraxas Petroleum for periods up to May 24, 2007 and our historical financial statements for the period from May 25 to December 31, 2007 and the year ended December 31, 2008 in this prospectus. Because the historical results of Abraxas Petroleum include combined information for the properties retained by Abraxas Petroleum as well as our oil and gas properties, these historical results of operations and period-to-period comparisons are not indicative of our future results.

Historical results prior to 2008 do not include the St. Mary Acquisition. The discussion of our historical results prior to 2008 does not include any results relating to the properties we acquired from St. Mary in January 2008 or the debt we incurred to finance the acquisition. The following table sets forth historical revenues and direct operating expenses related to the St. Mary properties:


	Year Ended December 31,
	2005		2006		2007
	(In thousands)
Revenues:
Oil sales	$	22,950	$	24,428	$	26,768
Gas sales		15,802		13,186		12,566

Total revenues		38,752		37,614		39,334
Direct operating expenses:
Lease operating expenses		9,739		11,874		12,271
Production taxes		3,513		2,988		3,278

Total direct operating expenses		13,252		14,862		15,549

Revenues in excess of direct operating expenses	$	25,500	$	22,752	$	23,785

The statements of revenues and direct operating expenses related to the St. Mary properties may not be indicative of future results for those properties.

Increase in Outstanding Indebtedness. In order to finance the St. Mary Acquisition, we borrowed a total of $129.7 million ($79.7 million under our credit facility and $50.0 million under our subordinated credit facility), of which $10.0 million represented the deposit we made in December 2007 and was reflected in our long-term debt of $45.9 million at December 31, 2007. For the period from May 25 to December 31, 2007, we paid a total of $1.8 million in interest. Our pro forma cash interest payments for 2008 would have been $9.6 million if the St. Mary Acquisition had occurred on January 1, 2008. We plan to use the net proceeds from this offering to partially repay indebtedness outstanding under our subordinated credit facility. We expect to have approximately $125.6 million outstanding under our credit facility and approximately

$30.0 million outstanding under our subordinated credit facility after completion of this offering which, based upon current interest rates and our interest rate swap arrangement, would require interest payments of $10.0 million for a 12-month period. We intend to re-finance the indebtedness outstanding under our subordinated credit facility prior to its scheduled maturity date of July 1, 2009; however there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial advisor to assist us in this re-financing.

We will experience realized and unrealized losses and gains on our derivative contracts. At December 31, 2008 and continuing through December 2011, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated net proved developed producing reserves at volume weighed average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas. At March 2, 2009, NYMEX futures prices were $44.76 per barrel of oil and $4.20 per MMbtu of gas. Because these derivative contracts, which we sometimes refer to as hedging arrangements, have at times been less and greater than then-current market prices, we have sustained both realized and unrealized losses and gains on our derivative contracts. In the future, we will sustain losses if market prices are higher than our contract prices and, conversely, we will sustain gains if market prices are lower than our contract prices. During the year ended December 31, 2008, we realized prices of $92.89 per barrel of oil and $7.52 per Mcf of gas before any impact from our derivative contracts. For the year ended December 31, 2008, we recognized a realized loss of $(9.3) million and an unrealized gain of $40.5 million on our commodity swaps. If the disparity between our contract prices and market prices continues, we will continue to sustain realized and unrealized gains and losses on our derivative contracts. While unrealized gains and losses do not impact our cash flow from operations or cash available for distribution, realized gains and losses impact both. In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices.

General and Administrative Expenses. We expect to incur approximately $0.8 million per year in incremental general and administrative expenses as a result of being a publicly traded partnership. These expenses include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and director, accounting, reservoir engineering and legal fees. These incremental general and administrative expenses are not reflected in our historical or pro forma financial statements. In addition, we are paying Abraxas Petroleum $2.6 million per year under our omnibus agreement. Prior to the consummation of the St. Mary Acquisition, we were paying Abraxas Petroleum $1.5 million per year.

Results of Operations

Comparison of Years Ended December 31, 2006, 2007 and 2008

The following table illustrates the primary components of revenue for the three years ended December 31, 2006, 2007 and 2008, as well as oil and gas sales volumes and average realized prices (net of impact from derivative contracts) for such periods.


	Years Ended December 31,
	2006		2007		2008
	(In thousands, except per unit data)
Operating revenue:
Oil sales	$	12,446	$	10,661	$	42,003
Gas sales		37,002		30,278		41,388
Rig and other		1,629		514		—

Total operating revenue	$	51,077	$	41,453	$	83,391

Operating income (loss)(1)	$	18,383	$	15,599	$	(59,027	)
Volumes:
Oil (MBbls)		200		157		452
Gas (MMcf)		6,515		5,044		5,055
Gas equivalents (MMcfe)		7,718		5,984		8,218
Realized oil price ($/Bbl)	$	62.10	$	63.08	$	79.14
Realized gas price ($/Mcf)	$	5.77	$	6.54	$	6.97

(1)	Operating loss in 2008 includes $97.1 million ceiling-test impairment.

The following table summarizes our expenses for the three years ended December 31, 2006, 2007 and 2008.


	Years Ended December 31,
	2006		2007		2008
	(In thousands)
Direct operating expenses:
Lease operating expenses	$	7,291	$	6,294	$	14,609
Production and other taxes		4,485		3,599		7,968

Total direct operating expenses	$	11,776	$	9,893	$	22,577

Comparison of Year Ended December 31, 2007 to Year Ended December 31, 2008

Revenues

Operating Revenue

During the year ended December 31, 2008, operating revenue increased by $41.9 million from $41.5 million in 2007 to $83.4 million in 2008. The increase was primarily due to increased volumes in 2008 as compared to 2007 as well as higher realized oil and gas prices in 2008 as compared to 2007. The increase in volumes contributed $23.4 million and higher realized prices (before the negative impact of realized losses on derivative contracts) contributed $18.5 million to operating revenue for the year ended December 31, 2008.

Oil volumes increased from 157 MBbls in 2007 to 452 MBbls during 2008 and gas volumes increased from 5.0 Bcf in 2007 to 5.1 Bcf in 2008. The increase was primarily due to the production attributable to the properties we acquired from St. Mary in January 2008. The properties acquired from St. Mary contributed 292 MBbls and 1.5 Bcf of production during 2008, which was partially offset by natural field declines.

Average realized prices in 2008 (net of realized loss on derivative contracts) were $79.14 per barrel of oil and $6.97 per Mcf of gas and average realized prices in 2007 (net of realized gain on derivative contracts) were $63.08 per barrel of oil and $6.54 per Mcf of gas.

Expenses

Direct Operating Expenses

Direct operating expenses increased from $9.9 million in 2007 to $22.6 million in 2008. The increase was primarily due to the operating expenses attributable to the properties that we acquired from St. Mary in January 2008. Direct operating expenses on a per Mcfe basis for the year ended December 31, 2008 were $2.75 per Mcfe compared to $1.65 per Mcfe in 2007. The increase in total operating expenses was primarily attributable to the producing properties we acquired from St. Mary in January 2008 which were predominately pumping oil wells which cost more to operate than the producing properties contributed to us by Abraxas Petroleum which were predominately flowing gas wells.

General and Administrative (“G&A”)

G&A, excluding equity-based compensation, decreased from $2.5 million in 2007 to $2.4 million in 2008. G&A on a per Mcfe basis decreased from $0.41 in 2007 to $0.29 in 2008. The decrease per Mcfe was due to the increased production attributable to the properties we acquired from St. Mary in January 2008.

Equity-Based Compensation

The Black-Scholes option pricing model is used to measure the fair value of stock/unit 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 year ended December 31, 2007, equity-based compensation expense was $393,000. On January 31, 2008, we awarded phantom units with distribution equivalency rights under our long-term incentive plan. For the year ended December 31, 2008, we incurred equity-based compensation expense of $242,000 relating to these phantom units.

Depreciation, Depletion and Amortization (“DD&A”)

DD&A increased from $12.8 million in 2007 to $20.1 million in 2008. The increase in DD&A was primarily due to the increased production as well as an increase in the depletion base from the properties we acquired from St. Mary in January 2008. DD&A on a per Mcfe basis for 2008 was $2.44 per Mcfe as compared to $2.14 per Mcfe in 2007. The increase per Mcfe was due to the increased production volumes and the increased depletion base in 2008 as compared to 2007.

Interest Expense

Interest expense increased to $10.2 million in 2008 from $8.2 million in 2007. The increase in interest expense was primarily due to the increase in long-term debt to fund the acquisition of properties from St. Mary in January 2008. Our debt increased from $45.9 million as of December 31, 2007 to $165.6 million as of December 31, 2008.

Income (loss) from derivative contracts

Accounting for gains and losses on our derivative contracts is based on realized and unrealized amounts. The realized gains and losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark-to-market valuation of our current derivative contracts. Our derivative contracts do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of these contracts are recognized in earnings during the current period. We have entered into a series of NYMEX-based fixed price commodity swaps, and as of December 31, 2008, the estimated unearned value of these contracts was an asset of approximately $39.2 million. For the year ended December 31, 2008, we recognized a realized loss of $(9.3) million and an unrealized gain of $40.5 million on these derivative contracts compared to a realized gain of $1.9 million and an unrealized loss of $(6.3) million for the year ended December 31, 2007.

We entered into a two-year interest rate swap in August 2008. For the first year, the notional amount of $100.0 million had a fixed rate of 3.367%. The interest rate swap was amended in February 2009 which reduced the fixed rate to 2.95% and increased the notional amount to $100.0 for the entire term of the contract. For the year ended December 31, 2008, we recognized a realized loss of approximately $(260,000) and an unrealized loss of $(2.7) million on this derivative contract. As of December 31, 2008, the estimated unearned value of this contract was a liability of approximately $3.0 million.

Ceiling-Test Impairment

We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our partners’ equity. The cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production, using commodity prices on the last day of the quarter, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the our financial statements. As of December 31, 2008, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $97.1 million. This amount was calculated considering 2008 year-end prices of $44.60 per Bbl for oil and $5.62 per Mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves as compared to each full cost pool.

The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our gas. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2007

Revenues

Operating Revenue

During the year ended December 31, 2007, operating revenue decreased by $9.6 million from $51.1 million in 2006 to $41.5 million in 2007. The decrease was primarily due to decreased volumes in 2007 as compared to 2006 offset by higher oil and gas prices realized in 2007 as compared to 2006. Lower volumes had a negative impact of $10.7 million which was partially offset by higher realized prices which contributed $1.1 million to operating revenue for the year ended December 31, 2007.

Oil volumes decreased from 200 MBbls in 2006 to 157 MBbls during 2007 and gas volumes decreased from 6.5 Bcf in 2006 to 5.0 Bcf in 2007. The decrease was primarily due to the 221 days of 2007 which did not include the properties retained by Abraxas Petroleum. Also contributing to lower gas volumes in 2007 was the sale of properties in Live Oak County, Texas effective August 1, 2006 and production from the La Escalera 1AH well in the Permian Basin which decreased from 2.2 Bcf in 2006 to 1.4 Bcf in 2007.

Average realized prices in 2007 (net of realized gain on derivative contracts) were $63.08 per barrel of oil and $6.54 per Mcf of gas and average realized prices in 2006 (net of realized gain on derivative contracts) were $62.10 per barrel of oil and $5.77 per Mcf of gas.

Accounting for gains and losses on our derivative contracts is based on realized and unrealized amounts. The realized gains and losses are determined by actual settlements during the period. Unrealized gains and losses are based on the periodic mark-to-market valuation of our current derivative contracts. Our derivative contracts do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of these contracts are recognized in earnings during the current period. We have entered into a series of NYMEX-based fixed price commodity swaps, and as of December 31, 2007, the estimated unearned value of these contracts was a liability of approximately $(9.1) million. For the year ended December 31, 2007, we recognized a realized gain of $1.9 million and an unrealized loss of $(6.3) million on these derivative contracts.

Expenses

Direct Operating Expenses

Direct operating expenses decreased from $11.8 million in 2006 to $9.9 million in 2007. The decrease was due to the 221 days of 2007 which did not include the properties retained by Abraxas Petroleum. Direct operating expenses on a per Mcfe basis for the year ended December 31, 2007 was $1.65 per Mcfe compared to $1.52 per Mcfe in 2006. The increase per Mcfe was primarily due to a decrease in production volumes in 2007 as compared to 2006 without a corresponding decrease in direct operating expenses.

General and Administrative (“G&A”)

G&A, excluding equity-based compensation, decreased from $4.2 million in 2006 to $2.5 million in 2007. The decrease in G&A in 2007 was primarily due to the terms of the omnibus agreement which governs the fee paid by us to Abraxas Petroleum for providing general and administrative services and the 221 days of 2007 which did not include the properties retained by Abraxas Petroleum. G&A on a per Mcfe basis decreased from $0.54 in 2006 to $0.44 in 2007. The decrease per Mcfe was due to decreased G&A in 2007 as compared to 2006 which was partially offset by decreased production volumes in 2007 as compared to 2006.

Equity-Based Compensation

Depreciation, Depletion and Amortization (“DD&A”)

DD&A decreased from $14.9 million in 2006 to $12.8 million in 2007. The decrease in DD&A was primarily due to the 221 days of 2007 which did not include the properties retained by Abraxas Petroleum. DD&A on a per Mcfe basis for 2007 was $2.14 per Mcfe as compared to $1.94 per Mcfe in 2006. The increase per Mcfe was due to the decreased production volumes in 2007 as compared to 2006.

Interest Expense

Interest expense decreased to $8.2 million in 2007 from $16.8 million in 2006. The decrease in interest expense was due to the redemption of Abraxas Petroleum’s senior secured notes due 2009 and refinancing and repayment of Abraxas Petroleum’s credit facility with Wells Fargo Foothill in May 2007 in connection with the Formation Transactions which was partially offset by the interest paid in connection with funds borrowed to effectuate the Formation Transactions.

Liquidity and Capital Resources

General. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt, make cash distributions and to fund:

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

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the acquisition of long-lived reserves with low-risk exploitation and development opportunities.

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

We expect that our sources of capital going forward will primarily be cash from operating activities, borrowings under our credit facility, and proceeds from the sale of debt and/or equity securities.

Sources of Capital. The historical net funds provided by and/or used in each of the operating, investing and financing activities, related to our continued operations, are summarized in the following table and discussed in further detail below:


	Year Ended December 31,
	2006			2007			2008
		(In thousands)
Net cash provided by operating activities	$	15,561		$	15,616		$	30,474
Net cash used in investing activities		(14,102	)		(20,708	)		(131,900	)
Net cash (used in) provided by financing activities		(1,458	)		8,637			101,591

Total	$	1		$	3,545		$	165

Operating activities for the year ended December 31, 2006 provided Abraxas Petroleum with $15.6 million of cash. Expenditures in 2006 of approximately $26.3 million were primarily for the development of oil and gas properties offset by proceeds from the sale of oil and gas properties of $12.2 million. Financing activities used $1.5 million during 2006, of which $20.4 million was provided from long-term borrowing offset by $22.4 million of payments on long-term debt.

Operating activities for the year ended December 31, 2007 provided Abraxas Petroleum and Abraxas Energy with $22.1 million of cash. Net income plus non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $2.2 million during 2007. Investing activities used $20.7 million during 2007 including $10.7 million for the development of existing properties and a $10.0 million deposit paid in December 2007 for the properties acquired from St. Mary in January 2008.

Operating activities for the year ended December 31, 2008 provided Abraxas Energy with $28.3 million of cash. Financing activities provided $103.7 million during the year ended December 31, 2008 to fund the St. Mary Acquisition. Investing activities used $131.9 million during the year ended December 31, 2008 predominately to acquire the properties from St. Mary, and for the development of our oil and gas properties.

Capital Expenditures. Capital expenditures made by Abraxas Petroleum and us related to the properties contributed to us by Abraxas Petroleum were $14.4 million and $7.0 million in 2006 and 2007, respectively. During 2006 and 2007, capital expenditures were primarily for development and exploitation activities on our properties. For the year ended December 31, 2008, our cash capital expenditures excluding the St. Mary Acquisition were $13.4 million. We anticipate making capital expenditures of $12.0 million during 2009 for the exploitation and development of our properties. Our capital expenditures could also include expenditures for acquisition of producing properties if such opportunities arise, but we currently have no agreements, arrangements or undertakings regarding any material acquisitions. We have no material long-term capital commitments and are consequently able to adjust the level of our capital expenditures as circumstances dictate. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of oil and gas continue to decline and if our costs of operations increase or if our production volumes decrease, our cash flow will decrease which may result in a reduction of our budgeted capital expenditures and could also lead to a decrease in cash distributions. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production volume decreases caused by natural field declines.

Future Capital Resources. We anticipate that we will have three principal sources of liquidity going forward: (i) cash from operating activities, (ii) borrowings under our credit facility, and (iii) sales of debt or equity securities, although we may not be able to complete such financings on terms acceptable to us, if at all.

Our cash flow from operations depends heavily on the prevailing prices of oil and gas and our production volumes. Although we have hedged approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves through 2011 and intend to continue this practice in the future, declines in oil and gas prices would have a material adverse effect on our overall results, and therefore, our liquidity. Falling oil and gas prices could also negatively affect our ability to raise capital on terms favorable to us or at all.

Our cash flow from operations will also depend upon the volume of oil and gas that we produce. Our production volumes will decrease as a result of natural field declines. To offset this loss, we must conduct successful exploitation and development activities or acquire additional producing properties. If our proved reserves decline in the future, our production will also decline and, consequently our cash flow from operations, the amount that we are able to borrow under our credit facility and the amount of our cash distributions may also decline.

We plan to make substantial capital expenditures in the future for the acquisition, exploitation and development of oil and gas properties. In estimating the amount of cash that we must generate to pay our initial quarterly distribution to our unitholders for the twelve months ending June 30, 2010, we have estimated that our maintenance capital expenditures for such twelve-month period will be approximately $10.6 million. Maintenance capital expenditures are capital expenditures necessary to replace our reserves and maintain our current level of production. We intend to finance these capital expenditures with cash flow from operations. Growth capital expenditures are capital expenditures necessary to increase our production and grow our asset base. We intend to finance these capital expenditures with a combination of cash flow from operations, borrowings under our credit facility and sales of debt or equity securities.

If cash flow from operations does not meet our expectations, we may fund a portion of our capital expenditures using borrowings under our credit facility, or from other sources, or we may reduce the expected level of capital expenditures or reduce our distributions to unitholders. Funding our capital program from sources other than cash flow from operations could limit our ability to make acquisitions. If we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions, we would reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so under our credit facility, sales of debt or equity securities or by other means. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Contractual Obligations. Pursuant to our omnibus agreement, Abraxas Petroleum will perform administrative services for us and for Abraxas Operating, such as accounting, finance, land, legal and engineering. We currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for performing these services, subject to annual adjustments for inflation and acquisition and other expansion adjustments. Thereafter, our payment obligations for general and administrative expenses to Abraxas Petroleum on our behalf are not fixed. Abraxas Petroleum and Abraxas Operating have entered into an operating agreement, under which Abraxas Petroleum will operate our oil and gas properties that are not subject to operating agreements with other parties. Abraxas Petroleum will continue as operator of our properties that are subject to operating agreements, to the extent Abraxas Petroleum is the operator of record. We will reimburse Abraxas Petroleum for its costs in performing the services performed under the operating agreements, plus related expenses. Please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “—Operating Agreement.”

Credit Facility. On May 25, 2007, we entered into a senior secured revolving credit facility with Société Générale, as administrative agent and issuing lender, and the lenders signatory thereto, which was amended and restated on January 31, 2008 and further amended on January 16, 2009, which we refer to as our credit facility. Our credit facility has a maximum commitment of $300.0 million. Availability under our credit facility is subject to a borrowing base. The borrowing base under our credit facility, which at December 31, 2008 was $140.0 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 December 31, 2008 of $140.0 million was determined based upon our reserve report dated June 30, 2008. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under our credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.5% - 2.5%, depending on the utilization of the borrowing base, or, if we elect, LIBOR plus 2.5% - 3.5% depending on the utilization of the borrowing base. After the termination of our subordinated credit facility, outstanding amounts under our credit facility will bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.0% - 2.0%, depending on the utilization of the borrowing base, or, if we elect, LIBOR plus 2.0% - 3.0%, depending on the utilization of the borrowing base. At March 2, 2009, the interest rate on the facility was 3.8%. Subject to earlier termination rights and events of default, the stated maturity date of our credit facility is January 31, 2013. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate our credit facility, and may, from time to time, permanently reduce the lenders’ aggregate commitment under our credit facility in compliance with certain notice and dollar increment requirements.

Each of our general partner and Abraxas Operating has guaranteed our obligations under our credit facility on a senior secured basis. Obligations under our credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances in all of our, our general partner’s, and Abraxas Operating’s material property and assets, excluding our general partner units.

Under our credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio (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. Our credit facility required us to enter into hedging arrangements for specified volumes, which equated to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2011. As of December 31, 2008, we had NYMEX-based fixed price commodity swaps on approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2011.

Under the terms of our credit facility, we may make cash distributions if, after giving effect to such distributions, we are not in default under our credit facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under our credit facility is greater than or equal to 10% of the lesser of our borrowing base (which is currently $140.0 million) or the total commitment amount of our credit facility (which is $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under our credit facility after giving effect to such distribution exceeds $20.0 million, or (ii) our subordinated credit facility shall have terminated and (c) no cash

distribution shall exceed $0.44 per unit per quarter while our subordinated credit facility is outstanding. Additionally, while our subordinated credit facility is outstanding, our capital expenditures are limited to $12.5 million.

In addition to the foregoing and other customary covenants, our credit facility contains a number of covenants that, among other things, will restrict our ability to:

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incur or guarantee additional indebtedness;

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transfer or sell assets;

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create liens on assets;

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

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

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permit a change of control.

Our 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.

Subordinated Credit Facility. On January 31, 2008, we entered into a subordinated credit facility which was amended on January 16, 2009 with Société Générale, as administrative agent, The Royal Bank of Canada, as syndication agent, and the lenders signatory thereto, which we refer to as our subordinated credit facility. Our subordinated credit facility has a maximum commitment of $40.0 million. Outstanding amounts under our subordinated credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR, plus in each case (b) 7.50% or, if we elect, at the greater of (a) 2.0% and (b) LIBOR, plus in each case 8.50%. At March 2, 2009, the interest rate on the facility was 10.5%. Principal payments under our subordinated credit facility must be made on May 14, 2009 in an amount, which we refer to as the May 14, 2009 Payment Amount, equal to the lesser of the amount of cash distributed to Abraxas Energy Investments, LLC, a wholly-owned subsidiary of Abraxas Petroleum, on or about February 14, 2009 and $2.25 million, with the balance due on the maturity date. The maturity date may be accelerated if any of our limited partners, other than Perlman Value Partners, exercises its right to convert its limited partner units into shares of common stock of Abraxas Petroleum pursuant to the terms of the exchange and registration rights agreement dated May 25, 2007, as amended, among Abraxas Petroleum, us and the purchasers named therein. If the initial public offering has not been consummated, the date on which the limited partners may first exchange their common units for Abraxas Petroleum common stock is April 30, 2009. Subject to earlier termination rights and events of default, the stated maturity date of our subordinated credit facility is July 1, 2009. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate our subordinated credit facility, and may, from time to time, permanently reduce the lenders’ aggregate commitment under our subordinated credit facility in compliance with certain notice and dollar increment requirements.

Each of our general partner and Abraxas Operating has guaranteed our obligations under our subordinated credit facility on a subordinated basis. Obligations under our subordinated credit facility are secured by a second priority perfected security interest, subject to certain permitted encumbrances in all of our, our general partner’s, and Abraxas Operating’s material property and assets, excluding our general partner units.

Under our subordinated credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio (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. Our subordinated

credit facility required us to enter into hedging arrangements for specified volumes, which equated to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2011 and was consistent with the hedging requirements under our credit facility. As of December 31, 2008, we had NYMEX-based fixed price commodity swaps on approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2011.

In addition to the foregoing and other customary covenants, our subordinated credit facility contains a number of covenants that, among other things, will restrict our ability to:

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incur or guarantee additional indebtedness;

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transfer or sell assets;

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create liens on assets;

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

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

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permit a change of control.

Our subordinated 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. In addition, as a result of the amendment to our subordinated credit facility, two events of default were added. The first event of default would occur if we fail to receive a letter of credit, which we refer to as the APC L/C, in our favor from Abraxas Petroleum equal to the May 14, 2009 Payment Amount, we fail to draw on the APC L/C on or before May 14, 2009 or we fail to use the proceeds of the APC L/C to make the principal payment due on May 14, 2009. This event of default would not occur in the event that we repay the principal payment due on May 14, 2009 with funds received from Abraxas Petroleum. Abraxas Petroleum and we have agreed that upon the occurrence of such a payment or our drawing on the APC L/C that, in consideration thereof, we would issue a number of additional units to Abraxas Petroleum determined by dividing the May 14, 2009 Payment Amount by 110% of the average trading yields of comparable E&P MLPs based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by us times four. The other event of default would occur if we fail to receive $20.0 million of proceeds from an equity issuance on or before April 30, 2009. We have no intention of pursuing any other equity offerings other than this offering prior to April 30, 2009. However, we do intend to re-finance the indebtedness outstanding under our subordinated credit facility prior to its scheduled maturity and we do not expect that any new subordinated or 2nd lien credit facility would contain a similar event of default.

We intend to partially repay indebtedness outstanding under our subordinated credit facility with proceeds from this offering. Our subordinated credit facility matures on July 1, 2009. We also intend to re-finance this indebtedness prior to its scheduled maturity; however there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial advisor to assist us in this re-financing. If we are unable to re-finance the indebtedness under our subordinated credit facility or unable to amend our existing credit facilities, we may be required to sell assets and reduce capital expenditures and cash distributions. We cannot assure you that we will be able to re-finance the indebtedness under our subordinated credit facility, sell assets, or obtain additional financing on terms acceptable to us, if at all.

Intercreditor and Subordination Agreement. On January 31, 2008, we entered into an intercreditor and subordination agreement which was amended on January 16, 2009 with Société Générale, as administrative agent for the lenders under our credit facility, and Société Générale, as administrative agent for the lenders under our subordinated credit facility, which we refer to as the intercreditor agreement. The intercreditor agreement sets forth the respective rights, obligations and remedies of each party with respect to our assets.

Hedging Activities. Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. Under the terms of our credit facility, we were required to enter into hedging arrangements for specified volumes, which equated to approximately 85% of the estimated oil and gas production through December 31, 2011 from our net proved developed producing reserves.

In order to mitigate our interest rate exposure, we entered into a 2-year interest rate swap in August 2008. For the first year, the notional amount of $100.0 million had a fixed rate of 3.367%. The interest rate swap was amended in February 2009 which reduced the fixed rate to 2.95% and increased the notional amount to $100.0 for the entire term of the contract.

Off-Balance Sheet Arrangements. At December 31, 2008, we had no 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 December 31, 2008 we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

Critical Accounting Policies

The discussion and analysis of financial condition and results of our operations are based upon the consolidated financial statements of Abraxas Energy, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate such estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of the more significant accounting policies, estimates and judgments. After this offering, the development, selection and disclosure of each of these policies will be discussed with and reviewed by our general partner’s audit committee. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our financial statements. Please read Note 1 of the Notes to the Consolidated Financial Statements of Abraxas Energy for a discussion of additional accounting policies and estimates made by management.

Full Cost Method of Accounting for Oil and Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in oil and gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and gas properties.

At the time it was adopted, we believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our oil and gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting.

Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flow from proved reserves on a pool by pool basis, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of our oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write- down.” This charge does not impact cash flow from operating activities, but does reduce our partners’ equity and reported earnings. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for our gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented.

Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

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the quality and quantity of available data;

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the interpretation of that data;

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the accuracy of various mandated economic assumptions; and

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the judgment of the persons preparing the estimate.

Our proved reserve information included in this prospectus was predominantly based on evaluations prepared by independent petroleum engineers. As of December 31, 2008, DeGolyer and MacNaughton estimated reserves for approximately 93% of the standardized measure of our properties. Reserve estimates for our remaining properties were prepared by Abraxas Petroleum personnel. The properties acquired from St. Mary included in the reserve report prepared by DeGolyer and MacNaughton were selected by us based upon the value we allocated to each property during our review of the acquisition. Reserve estimates for the higher valued properties were prepared by DeGolyer and MacNaughton and reserve estimates for the lower valued properties were prepared by Abraxas Petroleum personnel because we determined that it was not practical for DeGolyer and MacNaughton to prepare reserve estimates for all of the properties acquired from St. Mary due to the large volume of properties with relatively low values. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

You should not assume that the present value of future net cash flow is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flow from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

The estimates of proved reserves materially impact depreciation, depletion and amortization expense, which we refer to as DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields.

Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense.

Accounting for Derivatives. We use commodity price derivative contracts to limit our exposure to fluctuations in oil and gas prices. Fluctuations in the market value of these contracts are recognized in earnings during the current period.

Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which we refer to as SFAS 133, is effective for us. SFAS 133, as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. We have elected out of hedge accounting as prescribed by SFAS 133. Accordingly all of our derivatives, whether designated in hedging relationships or not, are required to be recorded at fair value on our balance sheet. Changes in fair value of contracts are recognized in earnings in the current period.

Due to the volatility of oil and gas prices and, to a lesser extent, interest rates, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments.

Share-Based Payments. In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123R, “Share-Based Payment.” SFAS No. 123R is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB 25. Among other items, SFAS 123R eliminates the use of APB 25 and the intrinsic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards, in the financial statements. Pro forma disclosure is no longer an alternative under the new standard. We adopted SFAS 123R on October 1, 2007.

SFAS 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. We have elected to use the “modified retrospective” method. Under the “modified retrospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS 123R for all share-based payments granted after that date, and based on the requirements of SFAS 123 for all unvested awards granted prior to the effective date of SFAS 123R. The “modified retrospective” method also permits entities to restate financial statements of previous periods based on pro forma disclosures made in accordance with SFAS 123. This standard requires the cost of all share-based payments, including stock/unit options, to be measured at fair value on the grant date and recognized in the statement of operations. In accordance with this standard, all periods prior to January 1, 2005 were restated to reflect the impact of the standard as if it had been adopted on January 1, 1995, the original effective date of SFAS No. 123, “Accounting for Stock-Based Compensation.” Also in accordance with the standard, the amounts that are reported in the statement of operations for the restated periods are the pro forma amounts previously disclosed under SFAS No. 123.

We currently utilize the Black-Scholes option pricing model to measure the fair value of stock/unit options granted to employees. While SFAS 123R permits entities to continue to use such a model, the standard also permits the use of a more complex binomial or “lattice” model. Based upon research done by us on the alternative models available to value option grants, and in conjunction with the type and number of stock/unit options expected to be issued in the future, it has determined that it will continue to use the Black-Scholes model for option valuation as of the current time.

SFAS 123R includes several modifications to the way that income taxes are recorded in the financial statements. The expense for certain types of option grants is only deductible for tax purposes at the time that the taxable event takes place, which could cause variability in Abraxas Petroleum’s effective tax rates recorded

throughout the year. SFAS 123R does not allow companies to “predict” when these taxable events will take place. Furthermore, it requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flow and increase net financing cash flow in periods after the effective date of the taxable event. These future amounts cannot be estimated, because they depend on, among other things, when employees exercise stock/unit options.

On January 31, 2008, in connection with the closing of the St. Mary Acquisition, the Board of Directors of our general partner awarded 63,008 phantom units with distribution equivalency rights under the long-term incentive plan of Abraxas Energy to key employees of Abraxas Petroleum. On February 2, 2009 the Board of Directors of our general partner awarded 52,000 restricted units to the employees of Abraxas Petroleum and directors of our general partner. In conjunction with the consummation of this offering, the Board of Directors of our general partner has approved the grant of 248,950 unit options to the executive officers of our general partner and certain key employees of Abraxas Petroleum.

Recent Accounting Pronouncements

Statement of Financial Accounting Standards No. 157

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. See Note 13 for further details of the impact of this statement on the consolidated financial statements.

Statement of Financial Accounting Standards No. 141R

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.

Statement of Financial Accounting Standards No. 160

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 Abraxas Petroleum’s investment in us, 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. Under current accounting rules, 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 owner of Abraxas Energy. For the year ended December 31, 2008, Abraxas Petroleum recorded a loss of $9.3 million relating to our loss in excess of the minority interest equity. Under SFAS No. 160, the loss in excess of capital would be a component of consolidated equity and would not be included in the earnings of the majority interest.

Statement of Financial Accounting Standards No. 159

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 have not elected the fair value treatment afforded by SFAS No. 159.

Statement of Financial Accounting Standards No. 161

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.

Statement of Financial Accounting Standards No. 162

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 our financial position, results of operations or cash flows.

Securities and Exchange Commission Rule Changes

On December 29, 2008, the Securities and Exchange Commission adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves.

The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago.

New disclosure requirements include:

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Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes.

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Enabling companies to additionally disclose their probable and possible reserves to investors. Currently, the rules limit disclosure to only proved reserves.

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Allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves.

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Requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit.

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Requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period—rather than the year-end price—to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We believe that this new requirement could have a significant impact on reported reserves and depletion rates when implemented.

Quantitative and Qualitative Disclosures about Market Risk

Forward-looking Information

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

As an independent oil and gas producer, our revenue, cash flow from operations, other income and equity earnings and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global political and economic conditions. Historically, prices received for oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our

production is sold at market prices. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the year ended December 31, 2008, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flow by approximately $8.3 million for the year.

Hedging Activity and Sensitivity

To achieve more predictable cash flow, we reduce our exposure to fluctuations in the prices of oil and gas. We have and may continue to enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production. Our credit facility required us to enter into hedging arrangements on specified volumes, which equated to approximately 85% of the projected oil and gas production from our net proved developed producing reserves through December 31, 2011. As of December 31, 2008, we had NYMEX-based fixed price commodity swaps on approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2011 at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas.

We adopted 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. We record our derivative instruments using the same method, accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded in other (income) expense in the current period.

At December 31, 2008, we had the following derivative contracts in place:


Period Covered	Product	Volume (Production per Day)	Fixed Price
Year 2009	Gas	10,595 MMbtu	$	8.45
Year 2009	Oil	1,000 Bbl	$	83.80
Year 2010	Gas	9,130 MMbtu	$	8.22
Year 2010	Oil	895 Bbl	$	83.26
Year 2011	Gas	8,010 MMbtu	$	8.10
Year 2011	Oil	810 Bbl	$	86.45

We expect to sustain realized and unrealized gains and losses as a result of our commodity 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 year ended December 31, 2008, we recognized a realized loss of $(9.3) million and an unrealized gain of $40.5 million on our commodity derivative contracts. The realized losses for the year ended December 31, 2008 were the result of the contract prices being significantly less than prevailing market prices during the first nine months of 2008. The unrealized gains were the result of the dramatic decline in commodity prices during the last three months of 2008 resulting in the contract prices being significantly greater than prevailing market prices. On December 31, 2008, NYMEX futures prices were $44.60 per barrel of oil and $5.62 per MMbtu of gas. We expect to continue to sustain realized and unrealized gains on our derivative contracts if prevailing market prices are lower than our contract prices.

Interest Rate Risk. We are subject to interest rate risk associated with borrowings under our credit facility that bear interest based on floating rates. As of December 31, 2008, the debt outstanding under our credit facility was $125.6 million. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, as amended in February 2009, to fix our floating LIBOR based debt. Our 2-year interest rate swap arrangement for $100.0 million is at a fixed rate of 2.95%. The arrangement expires on August 12, 2010.

BUSINESS

General

At December 31, 2008, our oil and gas properties had estimated net proved reserves of 110.3 Bcfe, of which 76% were gas, with a standardized measure of $118.6 million. Our estimated net proved reserves as of December 31, 2008 were 61% proved developed and 39% proved undeveloped. At December 31, 2008, we owned an average working interest of 18% in 1,639 gross (293 net) producing wells that produced 8.2 net Bcfe during 2008. Our properties are located in mature fields that exhibit relatively long-lived production, with a reserve to production index of 13.4 years (8.2 years for our proved developed properties) based on our estimated reserves as of December 31, 2008 and our production for the year ended December 31, 2008. Approximately 92% of the estimated ultimate recovery of our proved developed reserves as of December 31, 2008 had been produced. Abraxas Petroleum operates properties comprising over 75% of our estimated proved reserves at December 31, 2008. We have identified 226 drilling locations, of which 129 were classified as proved undeveloped as of December 31, 2008, which we believe provides us with a multi-year inventory of drilling opportunities. For the five years ended December 31, 2007, Abraxas Petroleum drilled 13 gross (10.2 net) wells on the properties contributed to us, of which 100% resulted in commercially productive wells. For the year ended December 31, 2008, Abraxas Petroleum and other operators drilled 40 gross (1.6 net) wells on our properties, of which 100% resulted in commercially productive wells.

We believe that our quality asset base, high degree of operational control and large inventory of drilling projects positions us for future growth, including growth in our cash distributions per unit. Our properties are concentrated in locations that facilitate economies of scale in drilling and production operations and efficient reservoir management practices. Abraxas Energy had $131.9 million of cash capital expenditures on our properties during 2008 (of which $118.5 million was attributable to the St. Mary Acquisition), and we have approved a capital budget of $12.0 million for 2009 for the development of our properties. The final amount of our capital expenditures in 2009 will depend upon our cash flow from operations which, in turn, is dependent upon our production volumes and the prices we receive for our oil and gas.

Our Properties

The following table sets forth certain historical information relating to our properties.





	As of December 31, 2008			As of December 31, 2008	Year Ended December 31, 2008
	Producing Wells	Average Working Interest		Estimated Net Proved Reserves (Bcfe)	Net Production (MMcfe)	Net Average Daily Production (MMcfepd)
Rocky Mountain	861	11	%	24.3	2,203	6.0
Mid-Continent	600	17	%	18.3	1,331	3.6
Permian Basin	114	45	%	33.8	2,528	6.9
Gulf Coast	64	74	%	33.9	2,156	5.9

Total	1,639	18	%	110.3	8,218	22.4

Rocky Mountain

Our Rocky Mountain properties are predominately located in the Williston, Powder River and Green River Basins. At June 30, 2008, we owned interests in 861 gross (91 net) producing wells in the Rocky Mountain region. These wells produce oil and gas from Paleozoic-aged carbonate reservoirs and Cretaceous-aged fractured shales and sandstones at depths ranging from 7,000 feet to 12,000 feet. Our estimated net proved reserves as of December 31, 2008 in the Rocky Mountain region were 5.4 Bcf of gas and 3.2 MBbl of oil, or 24.3 Bcfe. During the year ended December 31, 2008, our net production from the Rocky Mountain region was 2,203 MMcfe, or 6.0 MMcfe per day. We believe that development drilling on our Rocky Mountain properties is relatively low to moderate risk.

Our Rocky Mountain areas of operations are as follows:

Northern Rockies. Our Northern Rockies properties consist of wells located in the Williston Basin of Montana, North Dakota and South Dakota that produce oil from Paleozoic-aged carbonate reservoirs. Producing intervals range from the Madison formation at 8,000 feet down to the deeper Red River formation at 12,000 feet, including the Bakken at approximately 9,000 feet.

At December 31, 2008, we had identified five drilling locations in the Northern Rockies, including four proved undeveloped locations in the Medicine Pole Hills field located in Bowman County, North Dakota, which will target the Red River B formation at an approximate depth of 9,350 feet. The Medicine Pole Hills field wells are operated by Continental Resources and are being drilled on 320-acre spacing with enhanced recovery from air injection. One drilling location is located in the Hay Creek field in Richland County, Montana.

Southern Rockies. Our Southern Rockies properties consist of wells located in the Powder River, Green River and Uinta Basins of Wyoming, Colorado and Utah that produce oil from Cretaceous-aged fractured shale in the Niobrara formation and oil and gas from Cretaceous-aged sandstones in the Muddy and Frontier formations. Well depths range from 7,000 feet down to 10,000 feet.

At December 31, 2008, we had identified 71 drilling locations in the Southern Rockies, including 52 proved undeveloped locations. In the Natural Buttes field in Uintah County, Utah, 20 drilling locations will target the Wasatch formation at depths ranging from 6,500 feet to 7,800 feet. This 40-acre infill drilling program is operated by EOG Resources. In the Cow Hollow field in Lincoln County, Wyoming, 48 drilling locations will target the Frontier formation at a depth of 11,000 feet. This 40-acre downspacing program is operated by Kerr-McGee. Three drilling locations in the Buck Peak field in Moffatt County, Colorado will target the Niobrara formation in a separate fault block from the current producers. Abraxas Petroleum operates the Buck Peak field.

Mid-Continent

Our Mid-Continent properties are predominately located in the Arkoma and Anadarko Basins and the ARK-LA-TEX region. At December 31, 2008, we owned interest in 600 gross (103 net) producing wells in the Mid-Continent region. These wells produce gas from Pennsylvanian-aged sandstones and coals at depths ranging from 3,000 feet to 18,000 feet. Our estimated net proved reserves as of December 31, 2008 in the Mid-Continent region were 15.8 Bcf of gas and 0.4 MBbl of oil, or 18.3 Bcfe, During the year ended December 31, 2008, our net production from the Mid-Continent region was 1,331 MMcfe, or 3.6 MMcfe per day. We believe that development drilling on our Mid-Continent properties is relatively low to moderate risk.

Our Mid-Continent areas of operations are as follows:

Arkoma Basin. Our Arkoma Basin properties consist of wells located in eastern Oklahoma and western Arkansas that predominately produce coal bed methane from Hartshorne coals at 3,000 feet.

At December 31, 2008, we had identified 68 drilling locations in the Arkoma Basin, including 53 proved undeveloped locations in the Pittsburg County CBM field in Pittsburg County, Oklahoma, which will target the Hartshorne coals at a depth of 3,000 feet. These infill locations are located in the middle of the field near older vertical wells that were drilled to the Hartshorne sand beneath the coal. All of these vertical wells logged the overlying Hartshorne coals, which are currently being developed with horizontal wells. One drilling location in the Wilburton field in Pittsburg County, Oklahoma will target the Spiro formation.

Anadarko Basin. Our Anadarko Basin properties consist of wells located in Oklahoma, the Texas Panhandle and southwestern Kansas that predominately produce gas from Pennsylvania-aged sandstones. Our interests encompass the Woodford Shale play in the central Anadarko Basin.

At December 31, 2008, we had identified two drilling locations in the Anadarko Basin. One drilling location in the Tonkawa Creek field in Caddo County, Oklahoma will target the Wade formation and one drilling location is located in the Cherokee field in Custer County, Oklahoma.

ARK-LA-TEX Our ARK-LA-TEX properties consist of wells that produce from various formations, including the Cotton Valley and Travis Peak, and encompass the emerging Haynesville Shale play in northern Louisiana.

At December 31, 2008, we had one proved undeveloped location in the ARK-LA-TEX area that will target the Hartford formation at a depth of approximately 7,000 feet in the Booneville South field, which is operated by XTO Energy.

Permian Basin

Our Permian Basin operations are concentrated in the deep gas producing formations (Devonian, Montoya and Ellenburger) and the shallower oil producing sandstones (Bell and Cherry Canyon) in Ward, Pecos, Reeves and Sutton Counties of West Texas and in Eddy County, New Mexico. At December 31, 2008, we owned interests in 114 gross (52 net) producing wells in the Permian Basin. These wells produce oil and gas from multiple stacked formations at depths ranging from 5,000 to 16,000 feet. Our net proved reserves as of December 31, 2008 in the Permian Basin region were 31.0 Bcf of gas and 0.5 MBbl of oil, or 33.8 Bcfe. During the year ended December 31, 2008, our net production from the Permian Basin region was 2,528 MMcfe, or 6.9 MMcfe per day. We believe that development drilling on our Permian Basin properties is relatively low to moderate risk.

Our Permian Basin areas of operations are as follows:

ROC Complex. Our ROC Complex consists of wells located in Pecos, Reeves and Ward County, Texas that produce oil and gas from multiple stacked formations from the Bell Canyon at 5,000 feet down to the Ellenburger at 16,000 feet. Abraxas Petroleum operates all but eight of our wells in this complex, seven of which are operated by EOG Resources, Inc.

The deep gas producing fields in the ROC Complex that principally produce from the Devonian (12,000’) and Ellenburger (16,000’) formations were discovered by Roden Oil Company and Exxon Corporation in the 1960s and 1970s, while the formation sandwiched between them was virtually ignored until Mobil Oil Corporation began exploiting the Montoya formation at 14,000 feet with horizontal drilling technology in 1999. Abraxas Petroleum acquired its interest in the ROC Complex in 1994 and subsequently entered into a farmout agreement with EOG Resources in 2000 to develop the Montoya formation on Abraxas’ leasehold. In 2001, Abraxas Petroleum participated with EOG Resources in a 3-D seismic survey over its R.O.C. fields located in Ward County. Overlying these deep gas producing formations are the Bell and Cherry Canyon sands that produce oil and associated gas at depths of 5,000 to 7,000 feet. Abraxas Petroleum discovered the Cherry Canyon field in 1995 and has since drilled over 50 wells on 40-acre spacing. Our primary fields in the ROC Complex are R.O.C. (Devonian), R.O.C. (Ellenburger), Block 16 (Devonian), Howe (Devonian), and the Abraxas (Cherry Canyon).

As of December 31, 2008, we had identified 49 drilling locations in the ROC Complex, including three proved undeveloped locations. Eight drilling locations are located in the Howe field, which currently produces gas from the Devonian and Montoya formations. We believe that a significant amount of gas reserves remain trapped in the underlying structure based on the behavior of a well that Abraxas Petroleum re-entered and drilled horizontally in 2000 that continues to incline in production. Forty potential drilling locations are located in the shallow Bell and Cherry Canyon sands. Abraxas Petroleum has applied for and received approval from the Texas Railroad Commission for optional down-spacing from 40-acre to 20-acre spacing in the Cherry Canyon field, which we believe will allow us to drain these reservoirs more efficiently. In addition to down-spacing opportunities, we believe we have opportunities to utilize secondary and tertiary recovery techniques that have been successfully utilized by other operators in the area.

Oates SW. Our Oates SW area consists of wells located in Pecos County, Texas that produce gas from the Devonian formation at 13,500 feet. Abraxas Petroleum operates all of our wells in this area.

The Devonian formation was discovered in the Oates SW area by HNG Oil Company and Getty Oil Company in the late 1970s. Abraxas Petroleum acquired its leasehold interest in this area in 2000 and began redeveloping this field with horizontal drilling technology in 2001. In 2005, Abraxas Petroleum acquired a significant portion of the minerals, in addition to the surface and executive rights, on the majority of the 15,000 acre block. Abraxas Petroleum also owns 38 square miles of proprietary 3-D seismic data over the area and has entered into 3-D seismic data swap agreements on an additional 40 square miles with operators on adjacent properties. Our primary fields in the Oates SW area are Oates SW (Devonian) and the Elsinore, West Farm (Devonian).

As of December 31, 2008, we had five proved undeveloped locations in the Oates SW area, comprised of three Devonian locations and two deepenings to the Montoya formation at a depth of approximately 14,500 feet. In connection with the Formation Transactions, we received a leasehold assignment from Abraxas Petroleum for four producing wells and the proved undeveloped locations, which assignment is limited to the specific formations and the proration unit acreage assigned to each such well by the Texas Railroad Commission for so long as each well produces gas in sufficient quantities to remain economic. Abraxas Petroleum retained ownership of the Woodford/Barnett Shale formations in the Oates SW area for future development, as well as certain rights to other formations. Abraxas Petroleum also retained ownership of two producing wells, one of which produces from the Devonian formation, as well as several other well bores.

Permian Basin—Other. Our other Permian Basin properties consist of wells located in Sutton County, Texas and Eddy County, New Mexico.

Gulf Coast

Our Gulf Coast operations are concentrated along the Edwards trend in DeWitt and Lavaca Counties and the Frio and Vicksburg formations in the Portilla field in San Patricio County. At December 31, 2008, we owned interests in 64 gross (47 net) wells in the Gulf Coast region. These wells produce oil and gas from formations at depths ranging from 7,000 to 13,500 feet. Our estimated net proved reserves as of December 31, 2008 in the Gulf Coast region were 31.2 Bcf of gas and 0.4 MBbl of oil, or 33.9 Bcfe. During the year ended December 31, 2008, our net production from the Gulf Coast region was 2,156 MMcfe, or 5.9 MMcfe per day. We believe that development drilling on our Gulf Coast properties is relatively low to moderate risk.

Our Gulf Coast areas of operations are as follows:

Edwards. Our Edwards trend consists of wells located in DeWitt and Lavaca Counties, Texas that produce gas from the Edwards formation at a depth of approximately 13,500 feet.

Abraxas Petroleum began redeveloping several fields in the Edwards area in 1997 by applying horizontal drilling technology to previously abandoned fields that were originally developed with vertical wells. At December 31, 2008, our seven producing wells in the Yoakum (Edwards) field, which is our primary field in the Edwards area, had produced a cumulative total of 18.5 Bcf and had estimated proved reserves remaining of 14.4 Bcf, for a total of 32.9 Bcf, or an average of 4.7 Bcf per well.

At December 31, 2008, we had eight proved undeveloped drilling locations in the Edwards area with estimated average proved reserves of 3.3 Bcf per well. We have identified seven potential in-fill drilling locations based on the success in neighboring fields of wells drilled on denser spacing by other operators. In addition, we have a number of existing wells in which we believe we can fracture stimulate using advanced completion technology that has proven successful in the Edwards trend. We drilled one Edwards well in 2008. The Henson 3H came on-line on June 8, 2008 and has produced an average of 2.9 MMcfpd (1.6 net) during the seven months ended December 31, 2008. We own a 75% working interest in this well.

Portilla. Our Portilla field consists of wells located in San Patricio County, Texas that produce oil and gas from over 70 different intervals in the Frio and Vicksburg sands at depths ranging from 7,000 to 9,000 feet.

The Portilla field was discovered by The Superior Oil Company, predecessor to Mobil Oil Corporation, in 1950 and has produced a cumulative total of 514 Bcfe as of December 31, 2008. Abraxas Petroleum acquired this field from Mobil in 1993. During the past decade, Abraxas Petroleum has maintained production at relatively constant levels over the past decade by spending relatively modest amounts of capital annually as part of a continuous workover/recompletion program which predominately involves the completion of additional Frio sands, usually uphole from the existing completion. Abraxas Petroleum participated in a 3-D seismic survey over the entire field in 1994, which has aided in the interpretation of the complex faulting of the deeper Vicksburg sands.

At December 31, 2008, we had three proved undeveloped drilling locations in the Portilla field. In addition, we have identified seven additional drilling locations based on the success of other operators in nearby fields with similar geological characteristics.

Gulf Coast—Other. Our other Gulf Coast properties consist of wells located in Alabama, Mississippi, Louisiana, and Texas.

Business Strategy

Our primary business objective is to provide stability and growth in our cash distributions per unit over time. We intend to accomplish this objective by executing the following business strategies:

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Maintaining an inventory of drilling locations, which are sufficient, when drilled and completed, to allow us to maintain our current production levels for at least three years. We have identified 226 drilling locations, which provide us with a multi-year inventory of drilling opportunities.

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Making accretive acquisitions of relatively long-lived reserves with relatively low-risk exploitation and development opportunities. We plan to utilize a disciplined acquisition strategy which focuses on producing properties and related assets that possess the following characteristics:

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high quality, long-lived reserves;

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relatively predictable production profiles;

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low operating cost structure;

•

low-risk exploitation and development potential;

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operational control with high working interest; and

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geographic concentration.

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Using our technical expertise to exploit and develop our existing assets and to maximize reserve recovery. We plan to balance our acquisition efforts with exploitation projects on our existing assets. We seek to maximize the value of our existing assets by developing and exploiting properties with the lowest risk and the highest production and reserve growth potential. We routinely perform field studies of our existing properties to evaluate potential exploitation and development opportunities using advanced technologies, such as modern log analysis, reservoir modeling, 3-D seismic and horizontal drilling. Where appropriate, we also utilize down-spacing or in-fill drilling strategies to maximize recoveries from our properties.

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Reducing cash flow volatility through commodity price hedging. As of December 31, 2008, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated oil and gas production from our net proved developed producing reserves through December 2011 at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas. We expect to continue to enter into derivative contracts in the future to reduce our exposure to commodity price fluctuations and achieve more predictable cash flows. While these derivative contracts will protect us when market prices are below our contract prices, they also prevent us from realizing an increase in cash flow when market prices are higher than our contract prices.

Competitive Strengths

We believe that the following strengths position us well to execute our strategies:

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Our properties are characterized by relatively predictable, long-lived production. Our properties are located in large, mature fields with a high percentage of proved developed producing reserves and relatively low decline rates. These properties have a reserve to production index of 13.4 years (8.2 years for our proved developed properties) based on our estimated reserves as of December 31, 2008 and our production for the year ended December 31, 2008, and have relatively predictable production profiles that make them well-suited to our objective of making stable cash distributions to our unitholders.

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We have a substantial inventory of relatively low to moderate risk, proved undeveloped and other identified drilling locations. We believe that development drilling on our properties is relatively low to moderate risk based on Abraxas Petroleum’s drilling success on the properties contributed to us. For the five years ended December 31, 2007, Abraxas Petroleum drilled 13 gross (10.2 net) wells on the properties contributed to us, of which 100% resulted in commercially productive wells. For the year ended December 31, 2008, Abraxas Petroleum and other operators drilled 40 gross (1.6 net) wells on our properties, of which 100% resulted in commercially productive wells. For the two-year period ended December 31, 2008, Abraxas Petroleum, Abraxas Energy and St. Mary spent approximately $27.5 million on the drilling, workover or recompletion of wells on our properties.

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Our management has a proven acquisition, exploitation and development track record. Our CEO, Robert L.G. Watson, founded Abraxas Petroleum in 1977 and has assembled an experienced operating and technical team. The executive officers and key employees of Abraxas Petroleum average over 20 years of experience in the oil and gas industry and have demonstrated a successful track record of acquiring, developing and exploiting assets in areas where our properties are located.

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Over 75% of our estimated proved reserves at December 31, 2008 are operated by Abraxas Petroleum, which is an efficient, low-cost operator. Abraxas Petroleum operates a high percentage of our properties and will have substantial control over the timing of drilling activities. In addition, we believe that Abraxas Petroleum will be able to continue to operate these properties in an efficient, cost-effective manner.

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Abraxas Petroleum has an aligned and vested interest in our success due to its substantial ownership in us. Abraxas Petroleum will own a 2% general partner interest in us and a 40.1% limited partner interest in us after the consummation of this offering, and our quarterly cash distributions will represent a significant source of cash flow for Abraxas Petroleum.

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Relationship with Abraxas Petroleum. Our relationship with Abraxas Petroleum will provide us with additional operational, technical and other expertise. Abraxas Petroleum has a proven track record of oil and gas acquisitions in North America and we may have the opportunity to participate with Abraxas Petroleum in pursuing acquisitions that we may not be able to pursue on our own.

Acreage

The following table sets forth our acreage position as of December 31, 2008:


	Developed Acreage		Undeveloped Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres
Rocky Mountain	56,411	27,502	60,340	35,778
Mid-Continent	85,133	21,933	1,957	988
Permian Basin	13,425	8,388	1,766	1,127
Gulf Coast	6,730	3,917	829	185

Total	161,699	61,740	64,892	38,078

Productive Wells

The following table sets forth our producing wells as of December 31, 2008:


	Oil		Gas
	Gross	Net	Gross	Net
Rocky Mountain	363.0	74.6	498.0	16.2
Mid-Continent	125.0	15.2	475.0	87.8
Permian Basin	67.0	32.5	47.0	19.2
Gulf Coast	31.5	26.2	32.5	20.9

Total	586.5	148.5	1,052.5	144.1

Reserves Information

Our oil and gas reserves have been estimated as of December 31, 2006 and December 31, 2007 by DeGolyer and MacNaughton, an independent engineering firm. As of December 31, 2008, DeGolyer and MacNaughton estimated reserves for approximately 93% of the standardized measure of our properties. Reserve estimates for our remaining properties were prepared by Abraxas Petroleum personnel. The properties acquired from St. Mary included in the reserve report prepared by DeGolyer and MacNaughton were selected by us initially according to the value we allocated to each property during our review of the acquisition. Reserve estimates for the higher valued properties were prepared by DeGolyer and MacNaughton and reserve estimates for the lower valued properties were prepared by Abraxas Petroleum personnel because we determined that it was not practical for DeGolyer and MacNaughton to prepare reserve estimates for all of the properties acquired from St. Mary due to the large number of properties with relatively low values. A total of 300 properties were included in the reserve report prepared by DeGolyer and MacNaughton, which comprised approximately 93% of the standardized measure of our properties and a total of 854 properties were included in the reserve estimates prepared by Abraxas Petroleum personnel, which comprised approximately 7% of the standardized measure of our properties. Some of the properties include multiple wells. Please read—“Appendix D” for information regarding DeGolyer and MacNaughton’s preparation of their reserve report. Oil and gas reserves, and the estimates of the present value of future net revenues therefrom, were determined based on then-current prices and costs. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. The following table sets forth certain information regarding estimates of the pro forma oil and gas reserves on the properties contributed to us by Abraxas Petroleum as of December 31, 2006 and our historical oil and gas reserves as of December 31, 2007 and December 31, 2008.


	Estimated Proved Reserves
	Proved Developed	Proved Undeveloped	Total Proved
Pro forma as of December 31, 2006
Oil (MBbls)	897.6	60.3	957.9
Gas (MMcf)	32,595.4	20,050.5	52,645.9
Gas Equivalents (MMcfe)	37,981.3	20,412.3	58,393.6
As of December 31, 2007
Oil (MBbls)	1,166.8	38.9	1,205.7
Gas (MMcf)	29,333.8	36,126.2	65,460.0
Gas Equivalents (MMcfe)	36,334.4	36,359.8	72,694.2
As of December 31, 2008
Oil (MBbls)	4,416.0	62.5	4,478.5
Gas (MMcf)	41,029.6	42,376.9	83,406.5
Gas Equivalents (MMcfe)	67,525.7	42,752.2	110,277.9

The estimates of our net proved reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves and future net revenue from proved reserves are based on the assumption that future oil and gas prices remain constant. Any significant variance in actual results from these assumptions could materially affect the estimated quantity and value of reserves set forth herein. Please read “Risk Factors—Risk Related to Our Business—The estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

We file reports of our estimated oil and gas reserves with the Department of Energy. The reserves reported to this agency are required to be reported on a gross operated basis and therefore are not comparable to the reserve data reported herein.

Oil and Gas Production and Sales Prices

The following table presents our pro forma net oil and gas sales, the realized price per Bbl of oil and per Mcf of gas produced and the operating cost per Mcfe of production sold, for the two years ended December 31, 2007 and relating to the properties contributed to us by Abraxas Petroleum, our historical results for the year ended December 31, 2008, and pro forma for the St. Mary Acquisition for the year ended December 31, 2008:


										Pro Forma St. Mary Acquisition
	Year Ended December 31,									Year Ended December 31,
	2006			2007			2008			2008
Oil sales (MBbls)		128			128			452			484
Gas sales (MMcf)		5,953			4,860			5,505			5,678
Gas equivalents (MMcfe)		6,719			5,627			8,218			8,581
Realized oil price ($/Bbl)	$	63.73		$	65.09		$	79.14		$	79.25
Realized gas price ($/Mcf)	$	5.71		$	6.55		$	6.97		$	6.94
Realized gas equivalent price ($/Mcfe)	$	6.27		$	7.13		$	9.02		$	9.06
Gas differential to NYMEX, excluding realized gain (loss) on derivative contracts ($/Mcf)	$	(1.10	)	$	(0.99	)	$	(1.36	)	$	(1.40	)
Operating cost per Mcfe	$	1.29		$	1.60		$	2.75		$	2.75

Drilling Activities

The following table sets forth our pro forma gross and net working interests in exploratory and development wells drilled during the two years ended December 31, 2007 on the properties contributed to us by Abraxas. For the year ended December 31, 2008, the table sets forth our gross and net working interests in exploratory and development wells drilled on our properties. In addition to drilling new wells during the periods below, we recompleted a number of additional wells.


	2006		2007		2008
	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive
Oil	—	—	—	—	—	—
Gas	1.0	1.0	—	—	—	—
Dry holes	—	—	—	—	—	—

Total	1.0	1.0	—	—	—	—

Development
Productive
Oil	—	—	3.0	2.5	7.0	0.3
Gas	1.0	1.0	—	—	33.0	1.3
Dry holes	—	—	—	—	—	—

Total	1.0	1.0	3.0	2.5	40.0	1.6

During 2008, we drilled and completed a well in the Edwards trend located in the Gulf Coast region, the Henson 3H, which came on-line on June 8, 2008 and has produced an average of 2.9 MMcfpd (1.6 net) during the seven months ended December 31, 2008. We own a 75% working interest in this well.

A number of non-operated wells were drilled during 2008 on properties acquired from St. Mary across all of our regions. On average, we own a relatively small working interest in these wells.

Hedging Activity

We have entered into NYMEX-based fixed price commodity swaps with Société Générale with respect to a significant portion of our estimated oil and gas production from our currently producing wells to achieve more predictable cash flow and to reduce our exposure to fluctuations in commodity prices. At December 31, 2008 and continuing through December 2011, we had NYMEX-based fixed price commodity swaps covering approximately 85% of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $84.41 per barrel of oil and $8.27 per MMbtu of gas. For a more detailed discussion of our hedging activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Commodity Prices and Hedging Activities” and “—Quantitative and Qualitative Disclosures About Market Risk—Hedging Activity and Sensitivity.”

Markets and Customers

Substantially all of our oil and gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2008, three purchasers, Western Gas Resources, Inc., Crosstex Treating Services, LP/Crosstex Gulf Coast Marketing, Ltd. and Southern Union Pipeline, Ltd., together accounted for approximately 41% of the oil and gas sales relating to our properties. We believe that there are numerous other companies available to purchase our oil and gas and that the loss of one or more of these purchasers would not materially affect our ability to sell oil and gas.

Our Relationship with Abraxas Petroleum

Our general partner is a wholly-owned subsidiary of Abraxas Petroleum and has the sole responsibility for conducting our business and managing our operations. Some of the executive officers and directors of Abraxas Petroleum also serve as executive officers and directors of our general partner. The Board of Directors of our general partner currently consists of six members, with three directors meeting the independence standards established by the NASDAQ Stock Market. For more information about these individuals, please read “Management—Directors and Executive Officers of Our General Partner.”

Our general partner will not receive any management fee or other compensation in connection with the management of our business or this offering. Pursuant to our omnibus agreement, we currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and administrative expenses, subject to annual adjustments for inflation and acquisition or other expansion adjustments. We will also reimburse Abraxas Petroleum for operating expenses incurred on our behalf under our operating agreement. For more information, please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “—Operating Agreement.”

Abraxas Petroleum’s core areas of operation are in Texas, the Mid-Continent and Rocky Mountain regions of the United States. Abraxas Petroleum is more focused than we are on the exploration of oil and gas reserves, and it will continue to pursue relatively higher risk, higher return projects than we will. Abraxas Petroleum had 40.4 Bcfe of net proved reserves as of December 31, 2008 principally in Texas, of which 65% were classified as proved undeveloped. In addition to these proved reserves, Abraxas Petroleum retained all of its acreage in the West Texas Woodford/Barnett Shale Play (approximately 12,000 gross acres) and in the Mowry Shale/Turner Sand Play (approximately 33,000 gross acres) located in the southern Powder River Basin of Wyoming. Abraxas Petroleum also retained all of its 3-D exploration projects targeting the Wilcox formation in the Gulf Coast Basin of South Texas.

While our relationship with Abraxas Petroleum may benefit us, it is also a source of potential conflicts of interest. For example, Abraxas Petroleum is not restricted from competing with us. It may acquire, develop or dispose of oil and gas properties or other assets in the future without any obligation to offer us the opportunity to purchase or participate in the development of those assets. Please read “Conflicts of Interest and Fiduciary Duties” and “Risk Factors—Risks Inherent in an Investment in Us.” Notwithstanding the foregoing, many of Abraxas Petroleum’s properties, after development and stabilization of production rates, could be suitable for us. We will evaluate potential opportunities to acquire properties from Abraxas Petroleum as we would from any other third party.

Well Operations

Our wholly-owned subsidiary, Abraxas Operating, which directly owns our assets, has entered into an operating agreement with Abraxas Petroleum, under which Abraxas Petroleum operates our oil and gas properties that are not subject to operating agreements with other parties. In addition, Abraxas Petroleum will continue as operator of our properties subject to existing operating agreements, to the extent Abraxas Petroleum is the operator of record. Under these agreements, we will reimburse Abraxas Petroleum for operating expenses. Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of these expenses. Operating expenses do not include general and administrative expenses. A majority of our operating cost components are variable and increase or decrease as the level of production increases or decreases. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed and do not fluctuate with changes in production volumes, but can fluctuate depending on activities performed during a specific period.

Pursuant to our operating agreement, Abraxas Petroleum will establish a joint account for each well in which we have an interest. We will be required to pay our working interest share of amounts charged to the joint account. The joint account will be charged with all direct expenses incurred in the operation of our wells. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells will be done in accordance with the Council of Petroleum Accountants Societies, or COPAS, model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and wells and other equipment used on our properties. In addition, direct expenses will include the allocable share of the cost of Abraxas Petroleum employees who perform services on our properties. The allocation of the operating costs of Abraxas Petroleum employees who perform services on our properties will be based on time sheets maintained by Abraxas Petroleum’s employees.

Regulation of Oil and Gas Activities

The exploration, production and transportation of all types of hydrocarbons is subject to significant governmental regulations. The operations of our properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, and by changes in such laws and by constantly changing administrative regulations.

Federal, state and local laws and regulations govern oil and gas activities. Operators of oil and gas properties are required to have a number of permits in order to operate such properties, including operator permits and permits to dispose of salt water. We do not operate any of our properties and are not required, as a non-operator, to maintain any such permits. Abraxas Petroleum, which is the operator of properties comprising over 75% of our estimated proved reserves at December 31, 2008, possesses all material requisite permits required by the states and other local authorities in which it operates properties on our behalf. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits in order to operate such properties such as hazardous materials certificates, which Abraxas Petroleum has obtained.

Development and Production

The operations of our properties are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring the operator of oil and gas properties to possess permits for the drilling and development of wells, post bonds in connection with various types of activities, and file reports concerning operations. Most states, and some counties and municipalities in which Abraxas Petroleum operates, regulate one or more of the following:

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the location of wells;

•

the method of developing and casing wells;

•

the surface use and restoration of properties upon which wells are drilled;

•

the plugging and abandoning of wells; and

•

notice to surface owners and other third parties.

Some states regulate the size and shape of development and spacing units or proration units for oil and gas properties. Some states allow forced pooling or unitization of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum allowable rates of production from gas and oil wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of gas and oil we can produce from our wells or limit the number of wells or the locations at which these wells can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Operations on Federal or Indian oil and gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies, including the Bureau of Land Management, which we refer to as BLM, and the Minerals Management Service, which we refer to as MMS. MMS establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas lessees. Accordingly, we believe that the impact of royalty regulation on the operations of our properties should generally be the same as the impact on our competitors. We believe that the operations of our properties are in material compliance with all applicable regulations as they pertain to Federal or Indian oil and gas leases.

The failure to comply with these rules and regulations can result in substantial penalties, including lease suspension or termination in the case of federal leases. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect us.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended, which we refer to as NGA, the Natural Gas Policy Act of 1978, as amended, which we refer to as NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, which we refer to as FERC and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended, which we refer to as the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders, which we refer to, collectively, as Order No. 636, to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. FERC continues to regulate the rates that interstate pipelines may charge for such transportation and storage services. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which we refer to, collectively, as Order No. 637, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which

makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, or omit a material fact or engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

Generally, intrastate natural gas transportation is subject to regulation by state regulatory agencies, although FERC does regulate the rates, terms, and conditions of service provided by intrastate pipelines who transport gas subject to FERC’s NGA jurisdiction pursuant to Section 311 of the NGPA. The basis for state regulation of intrastate natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.

Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

Natural Gas Gathering

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which facilities constitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt for FERC’s NGA jurisdiction. From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. For example, there is currently pending at FERC a proposed rulemaking to reformulate its test for non-jurisdictional gathering in the shallow waters of the Outer Continental Shelf. In recent years, FERC has also permitted jurisdictional pipelines to “spin down” exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in which such a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been “spun down.” We cannot predict the effect that FERC’s activities in this regard may have on the operations of our properties, but we do not expect these activities to affect the operations in any way that is materially different from the effect thereof on our competitors.

State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or service requirements, but does not generally entail rate regulation. In the United States, gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under FERC Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated with the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by FERC in 2000 was

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successfully challenged on appeal by an association of oil pipelines. On remand, FERC, in February 2003, increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Environmental Matters

Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may:

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require the acquisition of a permit or other authorization before construction or drilling commences;

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restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities;

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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas;

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require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;

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restrict injection of liquids into subsurface strata that may contaminate groundwater; and

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impose substantial liabilities for pollution resulting from the operations of our properties.

Environmental permits that the operators of our properties including Abraxas Petroleum are required to possess may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on our properties as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

We are not currently involved in any administrative, judicial or legal proceedings arising under federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our financial position or results of operations. Moreover, we maintain insurance against the costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

Under the terms of our omnibus agreement with Abraxas Petroleum, we have agreed to be responsible for all environmental liabilities relating to the properties contributed to us in the Formation Transactions except to the extent we are indemnified by Abraxas Petroleum. Abraxas Petroleum has agreed to indemnify us through May 24, 2010 against certain potential environmental claims. Abraxas Petroleum’s maximum liability for these indemnification obligations will not exceed $5 million and Abraxas Petroleum will not have any obligation under this indemnification until our aggregate losses exceed $500,000. Abraxas Petroleum will have no indemnification

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obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 25, 2007. We have agreed to indemnify Abraxas Petroleum against environmental liabilities related to our assets to the extent Abraxas Petroleum is not required to indemnify us. In connection with the properties acquired from St. Mary, we agreed to be responsible for all plugging and abandonment costs relating to the wells we acquired and all environmental liabilities related to these properties.

The following is a discussion of the current relevant environmental laws and regulations that relate to our operations.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, and which we refer to as CERCLA, and comparable state statutes impose strict, joint, and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment.

In the course of the ordinary operations of our properties, certain wastes may be generated that may fall within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA currently contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including oil cleanups.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although Abraxas Petroleum has utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA (as defined below), and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

Oil Pollution Act of 1990. United States federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control plans and spill response plans relating to the possible discharge of oil into surface waters. The Federal Oil Pollution Act, which we refer to as OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our financial position or results of operations.

Resource Conservation Recovery Act. The Resource Conservation and Recovery Act, which we refer to as RCRA, is the principal federal statute governing the treatment, storage and disposal of hazardous waste.

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RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and gas exploration and production waste to be classified as non-hazardous wastes. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimum quantities of hazardous waste. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

Naturally Occurring Radioactive Materials, which we refer to as NORM, are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that the operations of our properties are in material compliance with all applicable NORM standards established by the various states in which Abraxas Petroleum operates wells on our behalf.

Clean Water Act. The Clean Water Act, which we refer to as the CWA, and analogous state laws, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that the operations of our properties comply in all material respects with the requirements of the CWA and state statutes enacted to control water pollution.

Safe Drinking Water Act. Oil and gas operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act, which we refer to as the SDWA, and analogous state and local laws. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production. The main goal of the SDWA is the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In most states, no underground injection may take place except as authorized by permit or rule. We currently own and Abraxas Petroleum operates on our behalf various underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we and Abraxas Petroleum are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

Clean Air Act. The Clean Air Act, which we refer to as the CAA, and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. The operations of our properties utilize equipment that emits air pollutants which may be subject to federal and state air pollution

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control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require oil and natural gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe that we and Abraxas Petroleum are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, or the Protocol, became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as “greenhouse gases,” that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol; however, Congress has recently considered proposed legislation directed at reducing “greenhouse gas emissions,” and certain states have adopted legislation, regulations and/or initiatives addressing greenhouse gas emissions from various sources, primarily power plants. Additionally, on April 2, 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that the EPA has authority under the CAA to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks). The Court also held that greenhouse gases fall within the CAA’s definition of “air pollutant,” which could result in future regulation of greenhouse gas emissions from stationary sources, including those used in gas and oil exploration and production operations. The gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. It is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Nonetheless, domestic leaders in Congress have signaled their intention to release a bill during the 111th Congress that would comprehensively regulate greenhouse gas emissions through a “cap and trade” regime. Additionally, the Obama Administration has indicated that it is considering regulating greenhouse gas emissions through the Clean Air Act. Either of these initiatives would impact our operations.

National Environmental Policy Act. Gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of gas and oil projects.

Endangered Species Act. The Endangered Species Act, which we refer to as the ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that may be designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the discovery of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Abandonment Costs. All of our oil and gas wells will require proper plugging and abandonment when they are no longer producing. Abraxas Petroleum has posted bonds with most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation

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of the surface production site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing. In connection with the Formation Transactions, we agreed to be responsible for all plugging and abandonment costs relating to the wells that Abraxas Petroleum contributed to us and in connection with the St. Mary Acquisition, we agreed to be responsible for all plugging and abandonment costs relating to the properties we acquired. As of December 31, 2008, we have estimated these costs to be approximately $9.0 million.

Title to Properties

As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and gas leases at the time we acquire them. However, before drilling commences, we require a thorough title search to be conducted, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties.

Competition

We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future, we cannot assure you that such materials and resources will be available to us.

Employees

We do not have any employees or dedicated senior management. Our general partner will manage our operations and activities on our behalf. As of December 31, 2008, our general partner had three executive officers who spend a portion of their time on our operations. Pursuant to our omnibus agreement, Abraxas Petroleum performs general and administrative services for us and for our subsidiary, Abraxas Operating. Abraxas Petroleum and Abraxas Operating have also entered into an operating agreement, under which Abraxas Petroleum operates our properties that are not subject to operating agreements with other parties. Abraxas Petroleum will continue as operator of our properties that are subject to operating agreements to the extent Abraxas Petroleum is the operator of record. For more information on the omnibus agreement and operating agreements and the fees paid thereunder, please read “Certain Relationships and Related Party Transactions.” As of December 31, 2008, Abraxas Petroleum had 65 full time employees. None of these employees is represented by labor unions or covered by any collective bargaining agreement. We believe that labor relations with these employees are satisfactory at this time.

Office Facilities

We share our executive and administrative offices with Abraxas Petroleum. These offices are located at 18803 Meisner Drive, San Antonio, Texas 78258. The office space consists of approximately 21,000 square feet, which is owned by Abraxas Petroleum, subject to a real estate lien note. We currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this

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offering for general and administrative expenses, subject to annual adjustments for inflation and acquisition or other expansion adjustments.

Legal Proceedings

At December 31, 2008, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

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MANAGEMENT

Management of Abraxas Energy

We have no employees or dedicated senior management. Our general partner will manage our operations and activities on our behalf. Our general partner is wholly-owned by Abraxas Petroleum. All of the executive officers of our general partner are employees of Abraxas Petroleum and will devote their time as needed to conduct our business and affairs. Pursuant to our omnibus agreement with Abraxas Petroleum, Abraxas Petroleum will perform administrative services for us and for Abraxas Operating, such as accounting, finance, land and engineering.

Abraxas Petroleum and Abraxas Operating have also entered into an operating agreement, under which Abraxas Petroleum will operate our properties that are not subject to operating agreements with other parties. Abraxas Petroleum will continue as operator of our properties that are subject to operating agreements to the extent Abraxas Petroleum is the operator of record. For a description of the fees and expenses that we will pay pursuant to these agreements, please read “Certain Relationships and Related Party Transactions.”

Our general partner has a Board of Directors that oversees its management, operations and activities. Three of the six-member Board of Directors of our general partner meet the independence standards required of directors who serve on an audit committee of a board of directors established by Rule 10A-3 of the Exchange Act and the NASDAQ Stock Market. The current members of the audit and conflicts committee are Messrs. Aldridge, Melton and Patton. Audit and conflicts committee members may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence standards to serve on an audit committee of a board of directors established by the NASDAQ Stock Market, as well as certain other requirements.

The audit and conflicts committee will review our external financial reporting, recommend engagement of our independent registered public accountants, review procedures for internal auditing and the adequacy of our internal accounting controls, and review specific matters that the board believes may involve conflicts of interest. If such a matter is referred to the audit and conflicts committee of our general partner, it will determine if the resolution of the conflict of interest is fair and reasonable to us. Any matters approved by our audit and conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Except as described in “The Partnership Agreement—Voting Rights” and subject to its fiduciary duty to act in good faith, our general partner will have exclusive management power over our business and affairs.

Pursuant to the terms of an investors’ rights agreement among us, our general partner, Abraxas Petroleum and certain of the Private Investors, which we refer to as the investors’ rights agreement, the Private Investors have the right to designate one person to serve as a member of the Board of Directors of our general partner until such time as this registration statement becomes effective. The Private Investors selected Edward P. Russell to serve on the Board of Directors of our general partner as their director-designee. Mr. Russell has informed us that he intends to tender his resignation as a member of our Board of Directors upon the closing of this offering.

All of the executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of Abraxas Petroleum; however, they may face a conflict regarding the allocation of their time between our business and the other business interests of Abraxas Petroleum. The executive officers of our general partner will devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs although it is currently anticipated that they will devote between 30% and 60% of their time to our business for the foreseeable future. We have entered into an omnibus agreement with Abraxas Petroleum and our general partner pursuant to which Abraxas Petroleum will perform administrative services for us. For a description of the fees and expenses that we will pay pursuant to this agreement, please read “Certain Relationships and Related Party Transactions.”

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Directors and Executive Officers of Our General Partner

The following table sets forth certain information with respect to the members of the Board of Directors and the executive officers of our general partner. Executive officers and directors will serve until their successors are duly appointed or elected.


Name	Age	Position with Our General Partner
Robert L.G. Watson	58	Chief Executive Officer and Chairman of the Board
Barbara M. Stuckey	40	President and Secretary
Chris E. Williford	57	Chief Financial Officer and Treasurer
Ralph F. Cox	76	Director
Bryant H. Patton	50	Director
Randolph C. Aldridge	64	Director
Brian L. Melton	39	Director
Edward P. Russell	45	Director

Robert L.G. Watson has been the Chief Executive Officer of our general partner since May 2007 and was appointed to be the Chairman of the Board of Directors of our general partner in June 2007. Since May 2007, Mr. Watson has also served as Chief Executive Officer of Abraxas Operating, and Abraxas Energy Investments, LLC. Mr. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas Petroleum since 1977. Since January 2003, Mr. Watson has served as Chairman of the Board, Chief Executive Officer and Director of Grey Wolf Exploration, Inc., an oil and gas exploration and production company whose shares are listed on the Toronto Stock Exchange and which was, until February 2005, a wholly-owned subsidiary of Abraxas Petroleum. Prior to forming Abraxas Petroleum, Mr. Watson held petroleum engineering positions with Tesoro Petroleum Corporation and DeGolyer and MacNaughton. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974. Mr. Watson currently devotes approximately one-third of his business time to his obligations for Grey Wolf. While there is no formal policy in place regarding potential conflicts of interest between Abraxas Petroleum and Grey Wolf, in February of 2005, in connection with Grey Wolf’s initial public offering in Canada, Abraxas Petroleum and Grey Wolf entered into a non-competition agreement pursuant to which Abraxas Petroleum agreed that it will not own or operate, directly or indirectly, any oil and gas properties outside the United States, and Grey Wolf agreed that it would not own or operate oil and gas properties located in the United States.

Barbara M. Stuckey has been the President of our general partner since May 2007 and Secretary of our general partner since July 2008. Ms. Stuckey was elected Vice President—Corporate Development of Abraxas Petroleum Corporation in June 2007 after serving as Director of Corporate Development since January 2005. In May 2007, Ms. Stuckey was also elected as Assistant Secretary of Abraxas Petroleum. Ms. Stuckey joined Abraxas Petroleum in 1997 and has held positions in investor relations, corporate finance, land and marketing. Since May 2007, Ms. Stuckey has also served as President and Secretary of Abraxas Operating and Abraxas Investments. Ms. Stuckey received a Bachelor of Arts degree from the University of Texas at San Antonio in 1991 and a Master of Business Administration degree from the Bordeaux Business School in 2004.

Chris E. Williford has been the Chief Financial Officer and Treasurer of our general partner since July 2008. Mr. Williford has served as Chief Financial Officer, Executive Vice President and Treasurer of Abraxas Petroleum since 1993. Prior to 1993, Mr. Williford was the Chief Financial Officer of American Natural Energy Corporation and the President of Clark Resources Corp. Mr. Williford received a Bachelor of Science degree in Business Administration from Pittsburg State University in 1973.

Ralph F. Cox was appointed to be a member of the Board of Directors of our general partner in June 2007. Mr. Cox is currently a member of the Board of Directors of Abraxas Petroleum, a position that he has held since December 1999, and has over 50 years of oil and gas industry experience, over 30 of which was with Atlantic Richfield Company (ARCO). Mr. Cox retired from ARCO in 1985 after serving as Vice Chairman. Mr. Cox then

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joined Union Pacific Resources prior to its acquisition by Anadarko Petroleum in July 2000, retiring in 1989 as President and Chief Operating Officer. Mr. Cox then joined Greenhill Petroleum Corporation as President until leaving in 1994 to pursue a consulting business. Mr. Cox currently serves on the board of CH2M Hill Companies, an engineering and construction firm, and as a trustee for Fidelity Mutual Funds. Mr. Cox also serves as a director of Validus International, a company specializing in oil field drilling tools, as a director of World GTL Inc., a gas-to-liquids production facility, and as a director of E-T Energy Ltd., a Canadian oil sands extraction company. Mr. Cox received Bachelor of Science degrees in Petroleum Engineering and Mechanical Engineering from Texas A&M University in 1954 and completed advanced studies at Emory University.

Bryant H. Patton was appointed to be a member of the Board of Directors of our general partner in June 2007. Mr. Patton founded BRYCAP Investments, Inc., a merchant banking firm specializing in management support, corporate finance and business development for energy related companies in 1999 and currently serves as President. Mr. Patton also co-founded Camden Resources, Inc., a private oil and gas exploration and production company in 2000 and served as Executive Vice President until the company was sold to Cinco Natural Resources Corporation in December 2007. Prior to founding Camden and BRYCAP, Mr. Patton served as Senior Vice President of Associated Energy Managers, an investment fund manager of institutional investments that specialized in mezzanine finance to independent oil and gas companies. Mr. Patton also serves on the board of Energy Partners, Ltd. Mr. Patton started his career in the energy industry with his family oil and gas company, TTE, Inc. Mr. Patton currently serves on the board of the Dallas Petroleum Club. Mr. Patton majored in Accounting at Texas Christian University and University of Texas at Dallas from 1976 to 1981.

Randolph C. Aldridge was appointed to be a member of the Board of Directors of our general partner in June 2007. Mr. Aldridge has over 35 years of diversified engineering, military and petroleum business experience, over 20 of which was with the Koch family of companies. Mr. Aldridge retired from Koch Pipelines, L.P. in 2002 after serving as Chairman of the Board. From 1980 to 2002, Mr. Aldridge served in various capacities from Manager of Supply and Transportation Projects of Koch Industries to President of Koch Oil Co. US, Koch Oil International, and Koch Petroleum Canada. From 1968 to 1974, Mr. Aldridge proudly served as an officer and carrier pilot in the United States Navy. Mr. Aldridge currently serves on the board of the Free Trade Alliance and on the Texas A&M Chemical Engineering Advisory Council. Mr. Aldridge also serves on the board of the Salvation Army. Mr. Aldridge obtained a Bachelor of Science degree in Chemical Engineering from Texas A&M University in 1966 and a Master of Science degree in International Business from the University of Texas at Dallas in 1975.

Brian L. Melton was appointed to be a member of the Board of Directors of our general partner in September 2008. Mr. Melton has served as Vice President of Corporate Strategy of Inergy, L.P. (Nasdaq: NRGY), a publicly traded limited partnership that specializes in retail propane distribution and midstream processing and storage facilities, since September 2008. Prior to joining Inergy, Mr. Melton was a Director in the Energy Corporate Investment Banking groups of Wachovia Securities and A.G. Edwards, prior to its merger with Wachovia in October of 2007. Mr. Melton joined A.G. Edwards in July 2000 and was a senior member of the energy corporate finance team, which was consistently ranked as one of the top three underwriters / advisors of MLP’s in the energy industry. From November 1995 until July 2000, Mr. Melton served as Director of Finance & Corporate Planning with TransMontaigne Inc., a downstream refined products supply, transportation and logistics company. Mr. Melton received a Bachelor of Science degree in Management and a Master of Business Administration degree from Arkansas State University.

Edward P. Russell was appointed to be a member of the Board of Directors of our general partner in January 2009. Mr. Russell currently serves as the President of Tortoise Capital Resources Corp. and Tortoise Gas and Oil Corp. Prior to joining Tortoise Capital Advisors, Mr. Russell was a Managing Director at Stifel, Nicolaus & Company, Inc. where he headed the Energy and Power group. Prior to Stifel, Mr. Russell served more than 15 years as an investment banker at Pauli & Company, Inc. and Arch Capital, LLC and as a commercial banker with Magna Bank and Southside National Bank. Mr. Russell attended Maryville University in St. Louis, Missouri. Mr. Russell has informed us that he intends to tender his resignation as a member of our Board of Directors upon the closing of this offering.

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Payment of Fees and Reimbursement of Expenses

Our general partner will not receive any management fee or other compensation for its management of our partnership but it will be entitled to reimbursements of all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business.

Pursuant to our omnibus agreement, Abraxas Petroleum will perform general and administrative services for us and for Abraxas Operating, such as accounting, finance, land and engineering. We currently pay Abraxas Petroleum $2.6 million per year, which includes an adjustment of $1.1 million annually as a result of the St. Mary Acquisition, for performing these general and administrative services. This fee will remain in effect until the second anniversary of the closing of this offering. We expect this amount to be similar after the first two years, subject to annual adjustments for inflation and acquisition or other expansion adjustments. This amount was determined by reference to Abraxas Petroleum’s historical general and administrative expenses and Abraxas Petroleum’s analysis and determination that our properties are predominantly developed and require relatively less management time than undeveloped properties and drilling prospects. In addition, we have estimated that we will incur $0.8 million per year of incremental expenses as a result of being a publicly traded partnership. We expect our incremental expenses will include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and director, accounting, reservoir engineering and legal fees.

Pursuant to our operating agreements, we are required to reimburse Abraxas Petroleum for all direct and indirect expenses associated with operating our wells. Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Operating expenses do not include general and administrative expenses. Our omnibus agreement and our operating agreements require us to reimburse Abraxas Petroleum for its expenses incurred on our behalf and on behalf of Abraxas Operating. Please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Operating Agreement.”

Executive Compensation

We and our general partner were formed in May 2007. We have no employees or dedicated senior management; therefore, we have not entered into any employment agreements nor will we offer any employee benefit plans or other retirement benefits. The officers of our general partner manage us. Compensation for such officers will be determined by the compensation committee of Abraxas Petroleum. Aside from incentive compensation awards to be granted under our long-term incentive plan, the executive officers of our general partner are not compensated by our general partner for their services in such capacity. Accordingly, we are not presenting any compensation for historical periods for our executive officers.

On January 31, 2008, in connection with the closing of the St. Mary Acquisition, the Board of Directors of our general partner awarded 63,008 phantom units with distribution equivalency rights under our long-term incentive plan to certain key employees of Abraxas Petroleum. On January 2, 2009, the Board of Directors of our general partner awarded 52,000 restricted units to the employees of Abraxas Petroleum and directors of our general partner. In conjunction with the consummation of this offering, the Board of Directors of our general partner has approved the grant of 248,950 option units to the executive officers of our general partner and certain key employees of Abraxas Petroleum. We will bear the cost of the grant with respect to any awards issued under this plan.

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The awards to the directors and executive officers of our general partner and the executive officers of Abraxas Petroleum are as follows:


Name	Phantom Units	Unit Options	Restricted Units
Robert L.G. Watson	9,991	63,000	6,000
Barbara M. Stuckey	8,776	42,000	4,000
Chris E. Williford	5,693	15,750	2,500
Lee T. Billingsley	5,693	15,750	2,500
William H. Wallace	5,693	15,750	2,500
Stephen T. Wendel	5,693	15,750	2,500
Ralph F. Cox	—	—	4,000
Bryant H. Patton	—	—	4,000
Randolph C. Aldridge	—	—	4,000
Brian L. Melton	—	—	4,000
Edward Russell	—	—	—

All directors and executive officers	41,539	168,000	36,000

The remaining 21,469 phantom units were awarded to certain key employees of Abraxas Petroleum in connection with the closing of the St. Mary Acquisition. The remaining 80,950 unit options and 16,000 restricted unit awards either have been or will be granted to certain key employees of Abraxas Petroleum in connection with this offering. The unit options will vest over four years and will have an exercise price equal to the initial public offering price. The restricted units vest over four years.

The phantom units and associated distribution equivalency rights will vest over four years and their value is based on the price of our common units, our quarterly cash distributions and the percentage increase in our cash distributions over time. For each quarter that unvested phantom units are outstanding, distribution equivalency rights entitle the holder of phantom units to receive additional phantom units equal to the cash distribution per unit made by us to the common unitholders divided by the market price of our common units on the date of the distribution multiplied by the holder’s cumulative number of unvested phantom units. On each vesting date, a holder of phantom units is entitled to receive a cash payment equal to the product of: (1) the number of vested phantom units awarded to such participant (including phantom units awarded pursuant to distribution equivalency rights), (2) the market price of our common units on the vesting date and (3) a performance milestone multiplier that is based on the percentage increase in our cash distribution per unit as of the most recent quarterly distribution on the first vesting date compared to the most recent quarterly distribution on the phantom unit grant date. After the first vesting date, the percentage increase in our cash distribution per unit is based on the most recent quarterly distribution on a particular vesting date compared to the most recent quarterly distribution on the prior vesting date. The performance milestone multiplier is determined as follows:


Percentage Increase in Cash Distribution		Performance Milestone Multiplier
0 to 4.99%		0
5.00%		1.0
5.01%-14.99%		1.0 plus 0.1 for each whole percentage point over 5%
15.00% and above		2.0

In making the awards of phantom units, the Board of Directors of our general partner established a basket of phantom unit awards for acquisitions. After the closing of a significant acquisition (or a group of smaller acquisitions), the Board will determine what amount of phantom units, if any, to award to our executive officers and the executive officers and key employees of Abraxas Petroleum based on their subjective determination of the contributions by each such officer or key employee to the acquisition.

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In making the awards of unit options and restricted units, the Board of Directors of our general partner reviewed similar awards made by a group of exploration and production master limited partnerships and further reviewed the components of those awards with respect to the percentage of restricted units compared to the percentage of unit options awarded. The group of master limited partnerships reviewed consisted of Breitburn Energy Partners L.P., EV Energy Partners, L.P., Atlas Energy Resources, LLC, Constellation Energy Partners LLC, Legacy Reserves LP, Linn Energy, LLC, and Vanguard Natural Resources, LLC.

As a result of this review, the Board determined that of the comparable partnerships that granted awards at the time of their initial public offerings, an average of 25% of the awards available under their respective long-term incentive plans were granted and that approximately 16% of those awards were in the form of restricted units with the remainder granted as unit options. Several of the comparable partnerships did not grant awards at the time of their initial public offerings. In connection with this offering and on January 2, 2009 with respect to the restricted unit awards, we have granted 300,950 units to officers and directors of our general partner and certain key employees of Abraxas Petroleum, which equate to 26% of our available awards under our long-term incentive plan, with 17% being in the form of restricted units and the remainder, unit options. With regard to the restricted units awards to the directors of our general partner, Mr. Watson subjectively determined that in lieu of annual cash compensation, the directors of our general partner would be paid in restricted units and that the amount of distributions on these restricted units would initially equate to annual cash compensation of approximately $6,000 based upon our current annual distribution rate of $1.50 per unit. In addition, Mr. Watson determined that the directors of our general partner should have equity-based incentives to help align their interests with those of our unitholders. The Board of Directors approved a grant of 4,000 restricted units to each director (other than Mr. Watson), entitling each of them to receive cash distributions of approximately $6,000 per year at our expected initial annual distribution rate of $1.50 per unit.

Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business, and we do not have a compensation committee. Our general partner will manage our operations and activities, and its Board of Directors and executive officers will make decisions on our behalf. Mr. Watson, Ms. Stuckey and Mr. Williford also serve as executive officers of Abraxas Petroleum. The compensation of Abraxas Petroleum’s employees that perform services on our behalf (other than the long-term incentive plan benefits described below) will be set by the compensation committee of and be paid for by Abraxas Petroleum. We do not expect to pay any salaries or bonuses to our executive officers. Our payment for the compensation of our general partners’ executive officers is governed by the omnibus agreement.

The compensation committee of Abraxas Petroleum will approve the compensation of the executive officers of our general partner based on the committee’s compensation philosophy of aligning the interests of its executive officers with those of its stockholders. Key elements of this philosophy are:

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Establishing compensation plans that deliver base salaries which are competitive with companies in Abraxas Petroleum’s peer group, within its budgetary constraints and commensurate with its salary structure;

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Rewarding outstanding performance particularly where such performance is reflected by an increase in Abraxas Petroleum’s net asset value; and

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Providing equity-based incentives to ensure motivation over the long-term to respond to Abraxas Petroleum’s business challenges and opportunities as owners rather than just as employees.

The compensation currently paid to Abraxas Petroleum’s executive officers consists of three core elements: base salary, annual bonuses under a performance-based, non-equity incentive plan and long-term equity based awards under our long-term incentive plan and under Abraxas Petroleum’s long-term equity incentive plan. Abraxas Petroleum believes these elements support its underlying philosophy of aligning the interests of its executive officers with those of its stockholders by providing the executive officers a competitive salary, an opportunity for annual bonuses and equity-based incentives to ensure motivation over the long-term. Abraxas Petroleum views the three core elements of compensation as related but distinct. Although it reviews total

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compensation, it does not believe that significant compensation derived from one component of compensation should increase or reduce compensation from another component. Abraxas Petroleum determines the appropriate level for each component of compensation separately. Abraxas Petroleum has not adopted any formal or informal policies or guidelines for allocating compensation among long-term incentives and annual base salary and bonuses, between cash and non-cash compensation, or among different forms of non-cash compensation; however, the age, tenure and seniority of each named executive officer is considered in making compensation decisions.

Base salaries for the executive officers of Abraxas Petroleum are set at a level that Abraxas Petroleum believes enables it to hire and retain individuals in a competitive environment and to reward individual performance and contribution to its overall business goals. Abraxas Petroleum reviews the salary structure of Abraxas Petroleum as compared to a peer group of exploration and production companies included in a survey that includes over 200 companies within the energy industry. Abraxas Petroleum’s salary range is set by reference to the salaries paid by its peer group companies in the survey while remaining within its budgetary constraints. Abraxas Petroleum uses the companies in its peer group to compare its salary structure to that of other companies that compete with it for executives but without targeting salaries to be higher, lower, or approximately the same as those of the companies in the peer group. Increases in base salary levels from time to time are designed to reflect competitive practices in the industry, individual performance and the officer’s contribution to overall business goals. Individual performance and contribution to the overall business goals of Abraxas Petroleum are subjective measures and evaluated by Mr. Watson and the Abraxas Petroleum compensation committee.

The Abraxas Petroleum bonus plan is intended to create financial incentives for its executive officers that are tied directly to increases in net asset value, or NAV, per share of Abraxas Petroleum common stock. Abraxas Petroleum chose NAV as the foundation of the bonus plan because it believes that NAV equates to the value of Abraxas Petroleum’s reserve base, giving risked credit for non-proven reserves, and adjusted for other assets and liabilities, including long-term debt. Under the bonus plan, NAV is calculated at each year-end after receipt of the reserve report from its independent petroleum engineering firm and the audited financials, subject to certain adjustments. The annual bonuses are calculated by the percentage increase in the current year-end NAV per share over the previous year-end NAV per share up to the first 10%; after 10% has been achieved, all excess percentage increases are doubled, with a maximum award for any one-year of 70% of the executive officer’s base annual salary.

Our general partner has adopted a long-term incentive plan for executive officers and directors of our general partner and certain key employees, including executive officers, of Abraxas Petroleum. The long-term incentive plan provides for the grant of options, restricted units, phantom units, unit appreciation rights and other unit-based awards. The Board of Directors of our general partner has approved the grant of awards for a total of 248,950 units pursuant to the long-term incentive plan described below in conjunction with this offering. Additionally, on January 31, 2008, in connection with the closing of the St. Mary Acquisition, the Board of Directors of our general partner granted 63,008 phantom unit awards to certain key employees of Abraxas Petroleum and on January 2, 2009, the Board of Directors of our general partner granted 52,000 restricted unit awards to employees of Abraxas Petroleum and directors of our general partner. For a more detailed description of the long-term incentive plan, please read “—Long-Term Incentive Plan” below.

During the first quarter of each year, Mr. Watson will submit his recommendations to the Board of Directors for long-term incentive awards based upon his subjective evaluation of the individual performance of each officer of the general partner and certain key employees of Abraxas Petroleum, except himself. Mr. Watson also factors in the quantity and value of the long-term incentives that each officer and key employee has been previously granted. The Board of Directors will review and discuss Mr. Watson’s recommendations and will make the final determination as to such awards. For awards to be made to Mr. Watson, the Board of Directors will subjectively evaluate Mr. Watson’s performance and, in their sole authority, determine how many, if any, long-term incentive awards to grant to Mr. Watson. It is anticipated that the Board of Directors will consider the quantity and value of the long-term incentives previously granted to Mr. Watson when considering making awards to him. In determining whether to grant long-term incentive awards, such awards will be substantially

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contingent upon the conclusion of Mr. Watson and the Board of Directors (and only the Board of Directors with respect to awards to be made to Mr. Watson) as to whether individual and management’s collective efforts have produced attractive long-term returns to our unitholders by increasing cash distributions and the market price of our common units over time as well as whether we have been able to make accretive acquisitions. In determining whether to grant long-term incentive awards, we anticipate that neither Mr. Watson nor the Board of Directors will have specific numerical targets, but rather will make a subjective determination based upon the state of the oil and gas exploration and production industry and other general economic factors at the time of their evaluation. There is no limitation on the amount of awards that may be granted to any participant. We do not intend to grant long-term incentives every year and we may award long-term incentives at other times during the year, principally in the event of a significant partnership event, such as an accretive acquisition. We believe that certain partnership events, such as the St. Mary Acquisition, may warrant the granting of awards outside the normal course of business if, in the Board’s discretion, the events are significant to the future success of Abraxas Energy. We do not time award grants in coordination with the release of material non-public information. The exercise price of all unit option awards will be no less than 100% of the fair market value on the date of the award, and as a general rule, all long-term incentive awards will contain a four-year vesting schedule to ensure motivation over the long-term to respond to Abraxas Energy’s business challenges and opportunities as owners rather than just employees.

Together with our general partner, we have entered into indemnification agreements with each of our general partner’s directors and executive officers and certain key employees of Abraxas Petroleum. Pursuant to the indemnification agreements, we and our general partner are required to indemnify each indemnitee, among other things, against expenses (including attorneys’ fees), judgments, penalties and fines (including excise taxes) and amounts paid in settlement that are actually and reasonably incurred if and whenever an indemnitee was or is, or is threatened to be made, a party to any proceeding by reason of the fact that the person serves or served as a director, officer, employee, agent, representative or other functionary of our general partner or us, or is or was serving at the request of our general partner or us, in any such capacity for an affiliate of the general partner or us, provided that the indemnitee engaged in the service or conduct in question in good faith and in a manner the indemnitee reasonably believed to be in or not opposed to the best interests of our general partner or us and, in the event the proceeding is a criminal action or involves the indemnitee’s conduct, the indemnitee had no reasonable cause to believe that such conduct was unlawful. Also as permitted under Delaware law, the indemnification agreements require our general partner and us to advance expenses in defending such an action, provided that the director or executive officer undertakes to repay the expenses advanced if he or she is ultimately determined not to be entitled to indemnification from our general partner or us. We and our general partner are also required to make the indemnitees whole for taxes imposed on the indemnification payments made pursuant to the indemnification agreements.

Compensation of Directors

Officers of our general partner who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that, following the closing of this offering, each director who is not an officer or employee of our general partner will receive compensation for attending meetings of the board of directors, as well as committee meetings. The initial compensation for directors of our general partner who are not officers of our general partner was a one-time award of 4,000 restricted units which were granted on January 2, 2009 and which will vest over a four year period. In addition, each non-employee director is expected to receive a fee of $1,500 per meeting of the board if attended in person, or $750 per meeting of the board if attended via telephonic conference, and a fee of $1,000 per meeting for each meeting of a committee of the board attended in person, or $500 per meeting for each meeting of a committee of the board attended via telephonic conference. The chairman of each committee is expected to receive an additional annual fee of $3,000. The directors will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. The compensation payable to our directors is not included in the $2.6 million payment to Abraxas Petroleum for general and administrative expenses pursuant to our omnibus agreement.

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Long-Term Incentive Plan

Our general partner has adopted the Abraxas Energy Partners, L.P. Long-Term Incentive Plan, which we refer to as our long-term incentive plan or our plan, to provide incentive compensation awards for employees, consultants and directors who perform services for our general partner and affiliates, including Abraxas Petroleum. The following awards are expected to be available under our long-term incentive plan: options, restricted units, phantom units, unit appreciation rights and other unit-based awards. Awards may provide for the issuance of common units of the partnership, payments of cash, or a combination of both. Our long-term incentive plan limits the number of units that may be delivered pursuant to awards to 1,136,160 units, of which awards for 248,950 units will be granted in conjunction with this offering. In addition, 63,008 phantom units were awarded to certain key employees of Abraxas Petroleum in connection with the closing of the St. Mary Acquisition on January 31, 2008 and on January 2, 2009, 52,000 restricted units were awarded to employees of Abraxas Petroleum and directors of our general partner. Units withheld to satisfy exercise prices or tax withholding obligations or that are otherwise forfeited by award recipients are available for issuance pursuant to other awards. Our long-term incentive plan will be administered by the Board of Directors of our general partner, the compensation committee of the board, or such other committee as may be appointed by the board, which we refer to as the plan administrator, as applicable.

The plan administrator may terminate or amend our long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend our long-term incentive plan or any part of our plan from time to time, including by increasing the number of units that may be granted, subject to the requirements of the NASDAQ Stock Market. However, no amendment or termination of our long-term incentive plan will be permitted, that may materially reduce the rights or benefits provided under any outstanding award without the consent of the holder of such award. Our long-term incentive plan provides for its expiration upon the earlier of: (1) its termination by the plan administrator, (2) the tenth anniversary of the date our plan is approved by our general partner or (3) the date that all awards have been paid out under the terms of our plan. No awards will be granted following the tenth anniversary of the approval of our plan.

Our plan provides that common units to be delivered under unit awards, as restricted units, upon the vesting of phantom units, through unit appreciation rights, upon the exercise of an option, or through any other award under our plan, may be common units acquired by us in the open market, common units acquired by us from any other person, a new issuance of common units, or any combination of the foregoing, in the plan administrator’s discretion. Our plan provides further, that if we issue new common units upon the delivery of units of any award under our plan, the total number of common units outstanding will increase, but such increase will not impact the total number of units available under our

Abraxas Energy Partners LP S-1/A