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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
TABLE OF CONTENTS

As filed with the Securities and Exchange Commission on September 20, 2007

Registration No. 333-144537

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

AMENDMENT NO. 2
to
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
(State or other jurisdiction of
incorporation or organization)

1311
(Primary Standard Industrial
Classification Code Number)

26-0144848
(I.R.S. Employer
Identification Number)

500 North Loop 1604 East, Suite 100
San Antonio, Texas 78232
(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 Chief Operating Officer
500 North Loop 1604 East, Suite 100 San Antonio, Texas 78232 (210) 490-4788 (Name, address, including zip code, and telephone number, including area code, of agent for service)



*Copies to:*
Steven R. Jacobs Marcello E. Tamez Lauren S. Ciminello Jackson Walker L.L.P. 112 E. Pecan Street, Suite 2400 San Antonio, Texas 78205 (210) 978-7727		Kelly B. Rose Joshua Davidson Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

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. o

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. o

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. o

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. o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee(3)


Common Units representing limited partner interests	$56,764,113	$1,743

(1): Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
(3): The registrant has previously paid the registration fee.

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 SEPTEMBER 20, 2007

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

2,350,481 Common Units

Representing Limited Partner Interests

Abraxas Energy Partners, L.P. is a limited partnership formed in May 2007 by Abraxas Petroleum Corporation. We are offering 2,000,000 common units representing limited partner interests and the selling unitholder is offering 350,481 common units. This is the initial public offering of our common units. We expect the initial public offering price to be between $ and $ per common unit. We have applied for the quotation of our common units on the American Stock Exchange under the symbol "ABE." We will not receive any proceeds from the sale of common units by the selling unitholder.

Investing in our common units involves risks. Please see "Risk Factors" beginning on page 18.

These risks include the following:

•: 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.
•: We intend to pay holders of our units quarterly distributions of $0.375 per unit (or $1.50 per unit annually). We would not have generated sufficient available cash on a pro forma basis to have paid the initial quarterly distributions on all of our units for the year ended December 31, 2006.
•: Oil and gas prices are volatile and are currently at high levels. If oil or gas prices decline, we may lower our distributions or not pay distributions at all.
•: Our oil and gas reserves naturally decline, and we are unlikely to be able to sustain distributions at current levels 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.
•: Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
•: Even if holders of our common units are dissatisfied, they currently cannot remove our general partner without its consent.
•: You will experience immediate and substantial dilution of $12.91 in tangible net book value per common unit.
•: If we were to become subject to entity-level taxation for federal or state tax purposes, then our cash available for distribution to you would be substantially reduced.
•: You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

PRICE $ PER COMMON UNIT

	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to us (before expenses)	$	$
Proceeds to the selling unitholder(1)(2)	$	$

(1): Excludes a financial advisory fee of 0.5% of the gross proceeds of this offering, or $[ • ] million, payable by us to the underwriters for evaluation, analysis and structuring of our partnership and this offering. Please see "Underwriting" beginning on page 163 for more information.
(2): Expenses associated with this offering, other than the underwriting discounts and financial advisory fees associated with the common units being sold by the selling unitholder, will be paid by us.

We have granted the underwriters a 30-day option to purchase up to an additional 352,572 common units from us on the same terms and conditions set forth above to cover over-allotments. A.G. Edwards & Sons, Inc., on behalf of the underwriters, expects to deliver the common units on or about , 2007.

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.

A.G. EDWARDS	RBC CAPITAL MARKETS
C.K. COOPER & COMPANY

The date of this prospectus is , 2007

TABLE OF CONTENTS

PROSPECTUS SUMMARY
ABRAXAS ENERGY PARTNERS, L.P.
	Overview
	Our Properties
	Hedging
	Formation Transactions
	Business Strategy
	Competitive Strengths
	Summary of Risk Factors
	Our Relationship with Abraxas Petroleum
	Summary of Conflicts of Interest and Fiduciary Duties
	Principal Executive Offices and Internet Address
	Partnership Structure
	The Offering
	Summary Historical and Pro Forma Financial and Operating Data
	Non-GAAP Financial Measures
RISK FACTORS
	Risks Related to Our Business
	Risks Inherent in an Investment in Us
	Tax Risks to Common Unitholders
USE OF PROCEEDS
CAPITALIZATION
DILUTION
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
	Our Cash Distribution Policy
	Our Initial Distribution Rate
	Pro Forma Financial Information and Estimated Cash Available for Distributions
	Assumptions and Considerations
	How We Make Cash Distributions
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview
	Basis of Presentation
	How We Evaluate Our Operations
	Outlook
	Results of Operations—Abraxas Energy
	Results of Operations—Abraxas Petroleum
	Liquidity and Capital Resources
	Critical Accounting Policies
	Recent Accounting Pronouncements
	Quantitative and Qualitative Disclosures about Market Risk
BUSINESS
	General
	Our Properties
	Business Strategy
	Competitive Strengths
	Acreage

	Productive Wells
	Reserves Information
	Oil and Gas Production and Sales Prices
	Drilling Activities
	Hedging Activity
	Markets and Customers
	Our Relationship with Abraxas Petroleum
	Well Operations
	Regulation of Oil and Gas Activities
	Environmental Matters
	Title to Properties
	Competition
	Employees
	Office Facilities
	Legal Proceedings
MANAGEMENT
	Management of Abraxas Energy
	Directors and Executive Officers of Our General Partner
	Payment of Fees and Reimbursement of Expenses
	Executive Compensation
	Compensation Discussion and Analysis
	Compensation of Directors
	Long-Term Incentive Plan
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
PRIVATE INVESTORS
SELLING UNITHOLDER
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	Distributions and Payments to Our General Partner and Its Affiliates
	Summary of Formation Transaction Documents
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
	Conflicts of Interest
	Fiduciary Duties
DESCRIPTION OF THE COMMON UNITS
	The Units
	Transfer Agent and Registrar
	Transfer of Common Units
THE PARTNERSHIP AGREEMENT
	Organization and Duration
	Purpose
	Power of Attorney
	Capital Contributions
	Limited Liability
	Voting Rights
	Issuance of Additional Securities
	Amendments to Our Partnership Agreement
	Prohibited Amendments
	No Unitholder Approval
	Opinion of Counsel and Unitholder Approval
	Merger, Consolidation, Conversion, Sale or Other Disposition of Assets
	Termination or Dissolution

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

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 , 2007 (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 (AMEX: "ABP") and its subsidiaries, other than Abraxas Energy Partners, L.P. References to "our general partner" or "Abraxas General Partner" refer to Abraxas General Partner, LLC, our general partner and references to "Abraxas Investments" refer to Abraxas Energy Investments, LLC. References to "our assets" or "our properties" refer to the oil and gas properties contributed to us by Abraxas Petroleum. The terms "pro forma" or "on a pro forma basis" refer to what our business might have looked like if the transactions described under "Formation Transactions" had occurred at the times indicated, and where specifically indicated, also gives effect to this offering and the application of the net proceeds we expect to receive as described under "Use of Proceeds" beginning on page 38.

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 $ per common unit and that the underwriters' over-allotment option to purchase additional common units is not exercised. You should read "Risk Factors" beginning on page 18 for information about important factors that you should consider carefully before buying our common units. Our reserve information is derived from reserve reports prepared by DeGolyer & MacNaughton, an independent engineering firm. 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 Delaware Basin of West Texas and the Gulf Coast Basin of South Texas.

At June 30, 2007, our oil and gas properties had estimated net proved reserves of 65.3 Bcfe, of which 91% were gas, with a standardized measure of $120.2 million. Our net proved reserves as of June 30, 2007 were 56% proved developed and 44% proved undeveloped. At June 30, 2007, we owned an average working interest of 81% in 104 producing wells that produced 6.7 Bcfe on a pro forma basis during 2006 and 3.0 Bcfe on a pro forma basis during the six months ended June 30, 2007. Our properties are located in mature fields that exhibit relatively long-lived production, with a reserve to production index of 10.9 years (6.2 years for our proved developed properties) based on our reserves as of June 30, 2007 and our pro forma annualized production for the six months ended June 30, 2007. Abraxas Petroleum operates over 90% of our properties. We currently have 80 identified drilling locations, of which 16 were classified as proved undeveloped as of June 30, 2007, which we believe provides us with a multi-year inventory of drilling opportunities.

The following table sets forth summary historical and pro forma information about our properties. The historical reserve and producing well information is as of June 30, 2007, and the pro forma production information is for the year ended December 31, 2006.

	Estimated Net Proved Reserves (Bcfe) As of June 30, 2007(1)					Pro Forma Production for the Year Ended December 31, 2006			Producing Wells As of June 30, 2007
	Estimated Net Proved Reserves (Bcfe) As of June 30, 2007(1)			Standardized Measure (1) (in millions)		Pro Forma Production for the Year Ended December 31, 2006			Producing Wells As of June 30, 2007
	Developed	Undeveloped	Total	Standardized Measure (1) (in millions)		MMcfe	%		Gross	Net
West Texas	21.2	18.7	39.9	$	72.0	4,529	67	%	67	48
South Texas	15.6	9.8	25.4		48.2	2,190	33	%	37	36

Total	36.8	28.5	65.3	$	120.2	6,719	100	%	104	84

(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 June 30, 2007 were determined using NYMEX prices of $70.68 per barrel for oil and $6.77 per MMbtu of gas and do not include adjustments for hedging.

Our Properties

All of our properties are located in the Delaware Basin of West Texas and the Gulf Coast Basin of South Texas. These properties are located in mature fields that exhibit relatively long-lived production with relatively predictable decline rates. The majority of our 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.

Our West Texas properties consist of the following:

•: ROC Complex—Our properties in the ROC Complex are located in Pecos, Reeves and Ward Counties and consist of 63 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 four 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.

Our South Texas properties consist of the following:

•: Edwards—Our fields in the Edwards area were redeveloped by Abraxas Petroleum in 1997 through the use of horizontal drilling technology. We have eight wells producing gas from the Edwards formation at a depth of approximately 13,500 feet. We also have two wells that produce from the overlying Wilcox formation at 9,000 feet in these fields.
•: Portilla—The Portilla field was discovered in 1950 by The Superior Oil Company, predecessor to Mobil Oil Corporation, and produces oil and gas from 27 wells in the Frio and Vicksburg sands from depths of approximately 7,000 to 9,000 feet. Abraxas Petroleum acquired this field in 1993.

Hedging

We are currently a party to 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. For the remainder of 2007 and continuing through December 2010, we have NYMEX-based fixed price commodity swaps covering approximately 75% of our estimated oil and gas production from our existing net proved developed producing reserves. 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. For more information on our hedging arrangements, please read "Management's Discussion & Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk—Hedge Activity and Sensitivity." Please read also "Risk Factors—Risks Related to Our Business" beginning on page 18 for a discussion of certain risk factors relating to our hedging activities.

Formation Transactions

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

•: Abraxas Petroleum contributed our 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" and "Private Investors" on pages 111 and 113.

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 approximately 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 though commodity price hedging.

Competitive Strengths

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

•: Abraxas Petroleum has operated over 90% of our properties for over ten years and is an efficient, low-cost operator;
•: Our properties are characterized by relatively predictable, long-lived production;
•: 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;
•: Abraxas Petroleum has an aligned and vested interest in our success due to its substantial ownership in us;
•: We will have no long-term debt outstanding following the closing of this offering, which will provide us financial flexibility to operate our business and finance our exploitation, development and acquisition activities; and
•: Our relationship with Abraxas Petroleum will provide us with additional operational, technical and other expertise.

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 18.

Risks Related to Our Business

•: 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.
•: On a pro forma basis, we would not have had sufficient cash available for distribution to pay the initial quarterly distributions on all units for the year ended December 31, 2006.
•: The assumptions underlying our estimated cash available for distribution 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 high levels. If oil or gas prices 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 substantial portion of our production is currently concentrated in one well. If production from this well declines more than we anticipate, we may not be able to pay distributions to you.
•: 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.
•: 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.
•: 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.
•: Our hedging activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions.

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 distribution.
•: 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 common 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 $12.91 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.
•: 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.
•: 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 IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among 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 the income we generate even if you do not receive any cash distributions from us.
•: Although gain or loss on disposition of common units is generally capital in nature, it is possible that all or a portion may be recognized as ordinary income, subject to your marginal rate.
•: Tax-exempt entities and foreign persons may 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.

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 five members, with two directors meeting the independence standards established by the American Stock Exchange. For more information about these individuals, please read "Management—Directors and Executive Officers of Our General Partner" beginning on page 102.

Upon the completion of this offering, Abraxas Petroleum will beneficially own a 2% general partner interest and a 38.2% limited partner interest in us, assuming the underwriters do not exercise their over-allotment option to purchase additional common units. We have entered into an omnibus agreement with Abraxas Petroleum and our general partner regarding certain payment and indemnification matters 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" beginning on page 118. 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" beginning on page 121.

Abraxas Petroleum is a publicly traded independent energy company engaged primarily in the acquisition, development, exploration and production of oil and gas in Texas and Wyoming. 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.

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" beginning on page 121. Please read also "The Partnership Agreement" beginning on page 128.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232 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 (assuming the underwriters do not exercise their over-allotment option to purchase additional common units), our organizational structure will be as follows:

		Percentage
Public common units		17.5	%
Private Investors' common units		42.0	%
Abraxas Petroleum and affiliates:
	Common units	38.2	%
	General partner units	2.0	%
	Restricted common units	0.3	%

Total:		100.0	%

(1): Represents restricted units that we intend to grant in conjunction with this offering to our General Partner's executive officers and outside directors and to certain executive officers and key employees of Abraxas Petroleum.

THE OFFERING

Common units offered to the public	We are offering 2,000,000 common units, or 2,352,572 common units if the underwriters exercise their over-allotment option to purchase additional common units in full. The selling unitholder is offering 350,481 common units.
Units outstanding after this offering	13,180,167 common units, representing a 98% limited partner interest in us. Our general partner will own 268,983 general partner units, representing a 2% general partner interest in us. Our total units outstanding after this offering will be 13,449,150 units.
	If the underwriters exercise their over-allotment option to purchase additional units in full, there will be 13,532,739 common units and 276,178 general partner units, or a total of 13,808,918 units outstanding.
Use of proceeds	We intend to use the net proceeds of approximately $36.4 million from this offering, after deducting approximately $3.6 million for financial advisory fees, underwriting discounts and offering expenses, together with our general partner's proportionate capital contribution and any proceeds from the exercise of the underwriters' over-allotment option:
	•	to repay in full the indebtedness outstanding under our credit facility; and
	•	for general partnership purposes, including capital expenditures and working capital.
	At June 30, 2007, the principal balance outstanding under our credit facility was $35.0 million.
	We will not receive any of the proceeds from the sale of the common units being sold by the selling unitholder.
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 to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. 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" beginning on page 43.

		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 December 31, 2007. We expect to pay this cash distribution on or before February 14, 2008. All unitholders, including our general partner, will receive the same cash distribution per unit; none of our unitholders has 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 December 31, 2007, 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, 2006 would not have been sufficient to allow us to pay the full initial quarterly distribution for four quarters on all of our units, and would have allowed us to pay only 85% of the initial quarterly distribution on all of our units for such periods. The amount of pro forma available cash generated during the twelve months ended June 30, 2007 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 2006 as well as the twelve months ended June 30, 2007, please read "Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Consolidated Available Cash for the Year Ended December 31, 2006 and the Twelve Months Ended June 30, 2007."
		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 September 30, 2008" and "—Assumptions and Considerations," we will have sufficient cash available for distribution to pay the initial quarterly distribution for the four quarters ending September 30, 2008 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" beginning on page 140 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 39.3% of our common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units. 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, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be [ ]% 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 $[ ] 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" beginning on page 141.

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		We have applied for the quotation of our common units on the American Stock Exchange under the symbol "ABE."
Private investors' resale shelf registration statement		In addition to this offering, we intend to file a shelf registration statement for the resale of the 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. 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" beginning on page 140.
Eligible Holders and redemption		We currently do not own interests in any federal leases. If in the future we acquire interests in a federal lease, we 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 as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 are derived from the audited financial statements of Abraxas Petroleum included elsewhere in this prospectus. The summary historical financial data of Abraxas Petroleum for the six months ended June 30, 2006 and 2007 are derived from the unaudited financial statements of Abraxas Petroleum included elsewhere in this prospectus. The summary historical financial data of Abraxas Energy as of June 30, 2007 are derived from our unaudited financial statements included elsewhere in this prospectus. The summary pro forma financial data of Abraxas Energy for the six months ended June 30, 2007 are derived from our unaudited pro forma financial statements included elsewhere in this prospectus and give effect to:

•

The following Formation Transactions, which occurred in May 2007:

•: Abraxas Petroleum contributed our 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 the Private Investors in consideration for gross proceeds of approximately $100.0 million.

•

The completion of this offering and the use of proceeds from this offering are described in "Use of Proceeds" beginning on page 38.

For a summary of the use of the proceeds of the Formation Transactions, please see "—Formation Transactions."

The unaudited pro forma statement of operations data for the year ended December 31, 2006 and for the six months ended June 30, 2007 assume that the Formation Transactions and this offering occurred on January 1, 2006. This pro forma financial data does not reflect expenses we expect to incur as a publicly traded partnership of $0.5 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 historical consolidated financial statements of Abraxas Petroleum and notes thereto and the unaudited pro forma and historical consolidated financial statements of Abraxas Energy and notes thereto 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

			Abraxas Petroleum—Historical															Abraxas Energy—Pro Forma
																		Formation Transactions		After Offering		Formation Transactions		After Offering
			Years Ended December 31,									Six Months Ended June 30,						Year Ended December 31,				Six Months Ended June 30,
			2004			2005			2006			2006			2007			2006				2007
			(In thousands, except per share/unit data)
	Total operating revenue		$	33,854		$	48,625		$	51,723		$	26,609		$	26,524		$	42,203	$	42,203	$	21,896	$	21,896
	Lease operating and production taxes			8,567			11,094			11,776			5,538			6,025			8,692		8,692		4,666		4,666
	Depreciation, depletion and amortization expense			7,213			8,914			14,393			7,136			6,756			12,496		12,496		5,738		5,738
	General and administrative expense			5,126			5,510			4,162			2,052			2,039			1,500		1,500		750		750
	Stock-based compensation			112			247			998			370			544			—		983		—		492
	Net interest expense			17,857			13,970			16,738			8,085			6,868			2,569		73		1,270		31
	Amortization of deferred financing fees			1,848			1,589			1,591			795			547			199		199		100		100
	Gain on sale of assets			—			—			—			—			58,498			—		—		—		—

	Income from continuing operations		$	9,037		$	6,271		$	1,246		$	2,203		$	56,160		$	16,747	$	18,260	$	2,917	$	3,664
	Income from continuing operations per common share/unit:
		Basic	$	0.25		$	0.16		$	0.03		$	0.05		$	1.28		$	1.47	$	1.36	$	0.26	$	0.27
		Diluted	$	0.23		$	0.15		$	0.03		$	0.05		$	1.26		$	1.47	$	1.36	$	0.26	$	0.27
Other Financial Data:
	Adjusted EBITDA(1)		$	35,448		$	31,196		$	33,887		$	17,856		$	17,187		$	31,940	$	30,957	$	14,694	$	14,202
	Capital expenditures		$	9,269		$	35,350		$	26,346		$	18,549		$	8,775		$	14,365	$	14,365	$	3,324	$	3,324
Net cash provided by (used in) continuing operations:
	Operating activities		$	27,000		$	21,099		$	15,561		$	10,887		$	325
	Investing activities		$	(9,269	)	$	(35,350	)	$	(14,102	)	$	(18,549	)	$	(8,775	)
	Financing activities		$	(65,684	)	$	14,877		$	(1,458	)	$	7,672		$	19,895

(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."

	Abraxas Petroleum—Historical						Abraxas Energy—Historical
	At December 31,						At June 30,
	2005			2006			2007
	(In thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	(4,880	)	$	(3,719	)	$	4,517
Total assets		121,866			117,486			95,872
Long-term debt		129,527			127,614			35,000
Stockholders'/partners' equity (deficit)		(23,701	)		(21,619	)		58,186

Summary Historical and Pro Forma Operating and Reserve Data

The following tables show summary historical operating and reserve data of Abraxas Petroleum, and our pro forma operating and historical and pro forma reserve data for the periods and as of the dates indicated, giving effect to and reflecting the Formation Transactions as if such transactions occurred on January 1, 2006 or as of the date indicated. The information in these tables should be read in conjunction with "Unaudited Pro Forma Financial Statements," "Risk Factors" beginning on page 18, "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 59 and Appendix D.

		Abraxas Petroleum—Historical										Abraxas Energy—Pro Forma
		Year Ended December 31,						Six Months Ended June 30,				Year Ended December 31,		Six Months Ended June 30,
		2004		2005		2006		2006		2007		2006		2007
Production:
	Oil (MBbls)		220		194		200		98		99		128		63
	Gas (MMcf)		4,403		4,942		6,515		3,201		2,925		5,953		2,611
	Total (MMcfe)(1)		5,779		6,109		7,718		3,786		3,521		6,719		2,988
Average daily production (Mcfepd)			15,789		16,736		21,144		20,917		19,454		18,407		16,509
Average Sales Price:
	Oil ($/Bbl)	$	40.12	$	53.27	$	62.10	$	62.97	$	57.70	$	63.73	$	59.02
	Gas ($/Mcf)	$	5.45	$	7.48	$	5.78	$	6.03	$	6.27	$	5.72	$	6.29
	Gas equivalents ($/Mcfe)	$	5.72	$	7.75	$	6.49	$	6.72	$	6.84	$	6.28	$	6.73
Operating Expenses ($/Mcfe)		$	1.48	$	1.82	$	1.52	$	1.46	$	1.71	$	1.29	$	1.56

(1): Includes 53 MMcfe of NGLs in 2004.

		Abraxas Petroleum—Historical									Abraxas Energy—Pro Forma			Abraxas Energy—Historical
		As of December 31,												As of June 30,
		2004			2005			2006			2006			2007
Reserve Data:
	Oil (MBbls)		3,101			3,084			2,820			976			1,001
	Gas (MMcf)		75,118			86,203			81,832			59,523			59,309
	Total (MMcfe)		93,724			104,707			98,752			65,381			65,317
Proved developed reserves as a % of total			51	%		48	%		48	%		58	%		56	%
Standardized measure (in thousands)(1)		$	149,035		$	311,908		$	160,886		$	116,327		$	120,247
Proved developed reserves as a % of total			66	%		65	%		74	%		84	%		80	%

(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 June 30, 2007 were determined using NYMEX prices of $70.68 per barrel for oil and $6.77 per MMbtu of gas and do not include adjustments for hedging.

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 plus:

•: Net interest expense;
•: Depreciation, depletion and amortization;
•: Amortization of deferred financing fees;
•: Unrealized loss (gain) on hedging;
•: 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 and net cash provided by operations to Adjusted EBITDA.

			Abraxas Petroleum—Historical															Abraxas Energy—Pro Forma
																		Formation Transactions			After Offering			Formation Transactions			After Offering
			Year Ended December 31,									Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30,
			2004			2005			2006			2006			2007			2006						2007
			(In thousands)
Reconciliation of net income to Adjusted EBITDA:
Net income			$	9,037		$	6,271		$	1,246		$	2,203		$	56,160		$	16,747		$	18,260		$	2,917		$	3,664
Add:
	Net interest expense			17,857			13,970			16,738			8,085			6,868			2,569			73			1,270			31
	Depreciation, depletion and amortization			7,213			8,914			14,393			7,136			6,756			12,496			12,496			5,738			5,738
	Amortization of deferred financing fees			1,848			1,589			1,591			795			547			199			199			100			100
	Unrealized loss (gain) on hedging			(507	)		452			(81	)		(363	)		(1,816	)		(71	)		(71	)		(1,786	)		(1,786	)
	Income tax provision			—			—			—			—			715			—			—			—			—
	(Gain) on sale of assets			—			—			—			—			(58,498	)		—			—			—			—
	Loss on debt extinguishment			—			—			—			—			6,455			—			—			6,455			6,455

Adjusted EBITDA			$	35,448		$	31,196		$	33,887		$	17,856		$	17,187		$	31,940		$	30,957		$	14,694		$	14,202

Reconciliation of net cash provided by operations to Adjusted EBITDA:			$	27,000		$	21,099		$	15,561		$	10,887		$	325
		Add (deduct):
	Cash interest expense and other financing costs, net			17,749			13,951			16,605			8,036			15,294
	Stock-based compensation			(112	)		(247	)		(998	)		(370	)		(544	)
	Changes in working capital			(8,775	)		(4,059	)		2,892			(334	)		3,928
	Deferred tax benefit			6,060			—			—			—			—
	Unrealized loss (gain) on hedging			(507	)		452			(81	)		(363	)		(1,816	)
	Other			(5,967	)		—			(92	)		—			—

Adjusted EBITDA			$	35,448		$	31,196		$	33,887		$	17,856		$	17,187

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

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.

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:

•: the amount of oil and gas we produce;
•: the prices at which we sell our oil and gas production;
•: the effectiveness of our commodity pricing hedging strategy;
•: our ability to continue to exploit and develop our existing oil and gas properties in a timely and cost efficient manner;
•: the level of our operating and general and administrative expenses;
•: the level of our interest expenses and restrictions on distributions in our credit facility;
•: fluctuations in our working capital needs;
•: timing and collectibility of receivables;
•: 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
•: 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" beginning on page 41.

On a pro forma basis, we would not have had sufficient cash available for distribution to pay the initial quarterly distribution on all units for the year ended December 31, 2006.

The amount of available cash we need to pay the initial quarterly distributions for four quarters on all of our units to be outstanding immediately after this offering is approximately $20.2 million (approximately $20.7 million if the underwriters exercise their over-allotment option to purchase additional common units in full). The amount of our available cash generated during the year ended December 31, 2006 would have been sufficient to pay only 85% of the initial quarterly distributions on our common units. Further, we may not generate sufficient cash flow to make actual cash distributions.

For a calculation of an estimate of our ability to make distributions to unitholders based on our pro forma results for 2006 and the twelve months ended June 30, 2007, please read "Cash Distribution Policy and Restrictions on Distributions" beginning on page 41.

The assumptions underlying our estimated cash available for distribution 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.

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.

Oil and gas prices are volatile and currently at high levels. If oil or gas prices 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 revenue, profitability and cash flow from operations depend upon the prices and demand for oil and gas, and a decline in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

•: 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;
•: reduce the amount of cash flow available for capital expenditures;
•: limit our ability to borrow money or raise additional capital; and
•: 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:

•: 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 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
•: 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 Activites."

A substantial portion of our production is currently concentrated in one well. If production from this well declines more than we anticipate, we may not be able to pay cash distributions to you.

Approximately 27% of our production during the six months ended June 30, 2007 was from the La Escalera 1AH well in our Oates SW area of West Texas. This well represented approximately 4% of our proved developed reserves as of June 30, 2007 and according to our reserve report is expected to be depleted in 2011. Like all gas wells, the rate of production from this well will decline over time and the estimated future reserves associated with this well will also decrease. If production from this well declines more rapidly than we anticipate, it would have a material adverse effect on our ability to make distributions.

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.

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on the reserve information set forth in our reserve report at June 30, 2007, our average annual estimated decline rate for our net proved developed producing reserves is 12% during the first five years, 9% in the next five years and approximately 7% 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.

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.

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 June 30, 2007. The NYMEX prices as of such date for oil and gas were $70.68 per barrel and $6.77 per MMbtu of gas, respectively, which resulted in realized prices of $67.87 per Bbl of oil and $5.75 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 44% of our total estimated proved reserves at June 30, 2007 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 our reserve report.

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:

•: supply of and demand for oil and gas;
•: actual prices we receive for oil and gas;
•: our actual operating costs;
•: the amount and timing of our capital expenditures;
•: the amount and timing of actual production; and
•: 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.

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.

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:

•: the amount of oil and gas we produce from existing wells;
•: the prices at which we sell our production;
•: the costs to produce oil and gas from our existing wells;
•: the estimated quantities of our oil and gas reserves;
•: our ability to develop and produce new wells on our existing properties; and
•: 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. 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 future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Following this offering, we estimate we will have the ability to incur debt, including under our credit facility, subject to borrowing base limitations. Our future indebtedness could have important consequences to us, including:

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

Our credit facility contains 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:

•: make distributions to unitholders or repurchase units;
•: incur indebtedness;
•: grant liens;
•: make acquisitions, investments and dispositions; and
•: 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. 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 agreement or exceed our borrowing base, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited 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 agreement, 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. Although Abraxas Petroleum has had some success in development drilling in the past, we cannot assure you that we will continue to replace reserves through development drilling. In 2006, Abraxas Petroleum replaced only 48% of the reserves it produced. Our drilling involves 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.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

•: unexpected drilling conditions;
•: facility or equipment failure or accidents;
•: shortages or delays in the availability of drilling rigs, equipment and crews;
•: adverse weather conditions;
•: compliance with environmental and governmental rules and regulations;
•: title problems;
•: unusual or unexpected geological formations;
•: pipeline ruptures;

•: fires, blowouts, craterings and explosions; and
•: uncontrollable flows of oil or gas or well fluids.

We intend to make acquisitions of oil and gas properties to grow our asset base. Properties that 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. Any future acquisition will require an assessment of recoverable reserves, title, future oil and gas prices, operating costs, potential environmental hazards, 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:

•: incorrect assumptions regarding the future prices of oil and gas or the future operating or development costs of properties acquired;
•: incorrect estimates of the oil and gas reserves attributable to a property we acquire;
•: unpredictable production profiles and decline rates of properties acquired;
•: an inability to integrate successfully the properties we acquire;
•: the assumption of liabilities;
•: limitations on our rights to be indemnified by the seller;
•: the diversion of management's attention from other business concerns; and
•: losses of key operational employees at the acquired properties.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

All of our properties and related assets are located in the Delaware Basin of West Texas and the Gulf Coast Basin of South Texas. Due to our lack of diversification in asset type and location, an adverse development in the oil and gas industry in these geographic areas would have a significant impact on our results of operations and cash available for distribution to our unitholders.

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 adverse fluctuations in the prices of oil and gas and to comply with the requirements under our credit facility, we have and expect to continue to enter into hedging arrangements for a significant portion of our oil and gas production that could result in both realized and unrealized hedging losses. Our credit facility required us to enter

into hedging arrangements for not less than 75% (nor more than 90%) of our projected oil and gas production. On May 25, 2007, we entered into NYMEX-based fixed price commodity swaps at then current market prices on approximately 75% of our then projected net proved developed producing reserves for the period from June 1, 2007 to December 31, 2010.

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 instruments are NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas. NYMEX-based derivative instruments are priced based on delivery at the Henry Hub in Louisiana and do not protect against basis differentials if our gas is priced on delivery to another location, such as Waha in West Texas or Houston Ship Channel. Basis differentials between the Henry Hub and other delivery locations can vary depending on seasonality, pipeline capacity and many other factors outside of our control. Our current marketing agreements are priced based on delivery locations other than the Henry Hub; therefore, our cash flow could be affected if the basis differentials widen more than we anticipate. 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.

Our ability to use hedging transactions 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 transactions 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. As our hedges expire, more of our future production will be sold at market prices unless we enter into further hedging transactions. Our commodity price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under any 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 transactions, 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 may limit our ability to realize 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 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. 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:

•: damages to equipment caused by adverse weather conditions, including hurricanes, lightning strikes and flooding;
•: facility or equipment malfunctions;
•: pipeline ruptures or spills;
•: fires, blowouts, craterings and explosions; and
•: 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:

•: the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;
•: the federal Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;
•: 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
•: 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 "Business—Environmental Matters" for more information on the laws and regulations that affect us and the operation of our properties.

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 conduct our operations in compliance with these laws and regulations, Abraxas Petroleum (which operates over 90% of our properties) 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 our oil and gas operations. While the cost of compliance with these laws has not been material to our operations 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.

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 owns and controls our general partner. Some of our general partner's directors, and some of its executive officers, are directors or officers of Abraxas Petroleum. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, 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:

•: 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;
•: 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;
•: Abraxas Petroleum is not limited in its ability to compete with us, which could limit our ability to acquire additional assets;
•: 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;
•: 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;
•: Abraxas Petroleum operates over 90% of our wells, 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;
•: our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus;
•: our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
•: in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions;
•: our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;

•: 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
•: 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" beginning on page 121.

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 or 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 accordingly cash available for distribution. Please read "Conflicts of Interest and Fiduciary Duties" beginning on page 121.

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 will pay Abraxas Petroleum $1.5 million per year for general and administrative expenses for the first two years following this offering, subject to annual adjustments for inflation and acquisitions or other expansion adjustments. 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 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.

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:

•: 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;
•: 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;
•: 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;
•: 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; and
•: provides that in resolving conflicts of interest, it will be presumed that in making its decision 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."

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.

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 39.3% of our common units and approximately 38.3% 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 the voting rights of unitholders owning 20% or more of our common 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.

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 $12.91 in tangible net book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $5.12 per unit before this offering. Based on the assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $12.91 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" beginning on page 40.

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 5,651,927 common units, representing approximately 42% of our outstanding units. Subject to the terms and conditions of our registration rights agreement, and pursuant to the shelf registration statement to be filed by us as required by the 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, except for the selling unitholder, who will generally be eligible to sell its common units into the market

beginning 90 days after the date of this prospectus. Please read "Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Registration Rights Agreement" beginning on page 117 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, 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 180 days from the date of this prospectus. Please read "Units Eligible for Future Sale" beginning on page 140 and "Underwriting—Lock-Up Agreement" 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:

•: our unitholders' proportionate ownership interest in us will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: the ratio of taxable income to distributions may increase;
•: the common units may be subordinated in rights of distribution, liquidation or voting;
•: the relative voting strength of each previously outstanding unit may be diminished; and
•: 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, our general partner and its affiliates will own an aggregate of 40.5% of our outstanding units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units. 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 the State of Texas. In the future we may operate in a number of other 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 other 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:

•: we were conducting business in a state but had not complied with that particular state's partnership statute; or
•: 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.

Following this offering, we may acquire 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 both, 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 8,002,408 publicly traded common units, or 8,354,980 publicly traded common units if the underwriters exercise their over-allotment option to purchase additional common units in full. 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" beginning on page 141 for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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.

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. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. 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 will 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 will 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. If in the future we operate in other states and if any of those states 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."

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.

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.

Although gain or loss on disposition of common units is generally capital in nature, it is possible that all or a portion may be recognized as ordinary income, subject to your marginal rate.

If our unitholders sell any of their units, they will recognize 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. Although generally capital in nature, 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. A constructive termination of our partnership will not, however, cause any unitholder to recognize gain or loss upon termination.

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 will initially conduct business and own assets in Texas. As we make acquisitions or expand our business, we may conduct business or own assets in other 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.

USE OF PROCEEDS

We expect the estimated net proceeds from this offering to be $36.4 million, after deducting the financial advisory fee of $0.2 million, the underwriting discount of $2.6 million and offering expenses of approximately $0.8 million, based on an assumed offering price of $20.00 per unit. We intend to use the net proceeds of this offering to repay in full the indebtedness outstanding under our credit facility, and for other general partnership purposes, including capital expenditures and working capital. We will not receive any of the proceeds from the sale of the common units by the selling unitholder. Please read "Selling Unitholder," beginning on page 114.

In connection with the Formation Transactions, we borrowed $35.0 million under our credit facility, which remained outstanding at June 30, 2007. 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 and (2) the Federal Funds Rate plus 0.5%, plus in each case, (b) 0.25% to 1.25% depending on utilization of the borrowing base, or, if we elect, at the London Interbank Offered Rate plus 1.25% to 2.25%, depending on the utilization of the borrowing base. At June 30, 2007, the interest rate on the facility was 7.13%. The maturity date of our credit facility is May 25, 2011. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting the financial advisory fee, the underwriting discount and estimated offering expenses payable by us, to increase or decrease by approximately $1.9 million.

CAPITALIZATION

The following table shows:

•: our historical cash and capitalization as of June 30, 2007; and
•: our cash and capitalization as of June 30, 2007, as adjusted to reflect the sale of 2,000,000 units in this offering at an assumed offering price of $20.00 per unit less the financial advisory fee and underwriting discount and estimated offering expenses, our general partner's proportionate capital contribution and the application of the net proceeds we expect to receive as described under "Use of Proceeds" on page 38.

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 June 30, 2007
		Historical		As adjusted(1)
		(In thousands)
Cash and cash equivalents		$	2	$	2,014

Long-term debt			35,000		—
Total partners' capital			58,186	$	95,421

	Total capitalization	$	93,186	$	95,421

(1): A $1.00 increase or decrease in the assumed public offering price per common unit would increase or decrease our total partners' capital by $1.9 million, assuming 2,000,000 common units offered by us and after deducting the financial advisory fee and underwriting discount and 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 $20.00 per common unit, as of June 30, 2007, 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 $95.4 million, or $7.09 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				$	20.00
	Net tangible book value per common unit before this offering(1)	$	5.12
	Increase in net tangible book value per common unit attributable to purchasers in this offering		1.97

Less: net tangible book value per common unit after this offering(2)					7.09

Immediate dilution in net tangible book value per common unit to new investors(3)				$	12.91

(1): Determined by dividing the net tangible book value of our assets by the number of units (11,134,367 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 (13,180,167 common units and 268,983 general partner units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units), 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 $12.76. 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 $13.05.

The following table sets forth the number of units that have been issued and the total consideration contributed to us by our general partner and its affiliates in respect of 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)	11,449	85.1	%	$	60,952	60.4	%
New investors	2,000	14.9	%		40,000	39.6	%

Total	13,449	100.0	%	$	100,952	100.0	%

(1): The Private Investors currently own 6,002,408 common units and will own 5,651,027 common units, representing a 42.0% interest in us after this offering. Our general partner will own 268,983 general partner units representing a 2% interest in us, and its affiliate, Abraxas Investments owns 5,131,959 common units, representing a 38.2% interest in us and restricted unitholders will own 45,800 common units, representing a 0.3% 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 affiliates of our general partner is equal to the net tangible book value of such assets as of June 30, 2007.

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" beginning on page 168 and "Risk Factors" beginning on page 18 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 audited historical consolidated financial statements and the notes thereto of Abraxas Petroleum for the years ended December 31, 2004, 2005 and 2006, the unaudited historical consolidated financial statements and the notes thereto of Abraxas Petroleum for the six months ended June 30, 2006 and June 30, 2007 and the unaudited pro forma consolidated financial statements and the notes thereto of Abraxas Energy for the year ended December 31, 2006 and the six months ended June 30, 2007 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 the credit facility, there is no borrowing base deficiency and the amount of 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 $65.0 million) or the total commitment amount of our credit facility (which is $150.0 million) at such time. 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 with the approval of our general partner and holders of a majority of our outstanding common units.

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 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.
•: 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" beginning on page 76.
•: 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, tax expenses, 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 from our credit facility and sales of equity or debt 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" beginning on page 74.

Our Initial Distribution Rate

The board of directors of our general partner has adopted a cash distribution policy pursuant to which 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 $5.0 million per quarter, or approximately $20.2 million per year, based on the common units outstanding immediately after completion of this offering. If the underwriters' fully exercise their over-allotment option to purchase 352,572 additional common units, then the aggregate cash distribution would increase to approximately $5.2 million per quarter, or approximately $20.7 million per year. 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 the credit facility, there is no borrowing base deficiency and the amount of 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 $65.0 million) or the total commitment amount of our credit facility (which is $150.0 million) at such time.

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	2,350,481	$	881,430	$	3,525,722	2,703,053	$	1,013,645	$	4,054,580
Private Investor common units	5,651,927		2,119,473		8,477,891	5,651,927		2,119,473		8,477,891
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	268,983		100,869		403,475	276,178		103,567		414,268
Restricted units	45,800		17,175		68,700	45,800		17,175		68,700

Total	13,449,150	$	5,043,431	$	20,173,725	13,808,918	$	5,178,344	$	20,713,376

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. On August 14, 2007 we paid a prorated distribution of $0.152 per unit to the Private Investors for the period beginning on May 25, 2007 and ending on June 30, 2007. Assuming that we complete this offering before December 31, 2007, we will pay unitholders a prorated distribution for the period from the first day our common units are publicly traded to and including December 31, 2007.

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 September 30, 2008. In those sections we present two tables, including:

•: Our "Estimated Cash Available For Distributions" 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 September 30, 2008.
•: 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, 2006 and the twelve months ended June 30, 2007 derived from our unaudited pro forma financial statements that are included in this prospectus. The unaudited pro forma financial statements are based on the audited and unaudited historical financial statements of Abraxas Petroleum, as adjusted to reflect the Formation Transactions and 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 September 30, 2008

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 September 30, 2008. 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 September 30, 2008.

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 September 30, 2008. 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). 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 September 30, 2008.

Abraxas Energy
Statement of Estimated Cash Available for Distribution

			Twelve Months Ending September 30, 2008
			Assuming no exercise of underwriters' over-allotment option			Assuming exercise of underwriters' over-allotment option
			(In thousands, except per unit amounts)
Operating revenues			$	44,485		$	44,485
Realized hedging gain				1,925			1,925

Total operating revenues				46,410			46,410
Operating expenses
	Lease operating expenses			5,879			5,879
	Production taxes			4,004			4,004
	General and administrative expenses			2,000			2,000

Total operating expenses				11,883			11,883
Depreciation, depletion and amortization expense				11,881			11,881
Amortization of deferred financing fees				200			200
Stock-based compensation				983			983
Net interest expense (income)(a)				48			(350	)(b)

Net income				21,415			21,813
Adjustments to reconcile net income to Adjusted EBITDA:
Plus:
	Depreciation, depletion and amortization expense			11,881			11,881
	Amortization of deferred financing fees			200			200
	Net interest expense (income)(a)			48			(350	)(b)

Estimated Adjusted EBITDA(c)				33,544			33,544
Adjustments to reconcile Estimated Adjusted EBITDA to Estimated Cash Available for Distribution:
Less:
	Cash interest expense (income)			(13	)		(368	)(b)
	Stock-based compensation (expense)			(983	)		(983	)
	Maintenance capital expenditures(d)			11,533			11,533
	Growth capital expenditures			0			0

Estimated Cash Available for Distribution			$	23,007		$	23,362

Distributions:
Distribution per unit			$	1.50		$	1.50
Distributions to:
	General partner		$	403		$	414
	Public common unitholders			3,526			4,054
	Private Investors			8,478			8,478
	Restricted unitholders			69			69
	Abraxas Petroleum and its affiliates			7,698			7,698

		Total cash distributions	$	20,174		$	20,713

Excess of Estimated Cash Available for Distribution over Total cash distributions			$	2,833		$	2,649

(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 to purchase additional common units would generate interest income of $0.4 million, assuming a 5.0% annual interest rate.
(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—Non-GAAP Financial Measures" beginning on page 16.
(d): For purposes of this table, we have assumed that we will fund all of our maintenance capital expenditures for the twelve months ending September 30, 2008 with cash flow from operations.

Unaudited Pro Forma Consolidated Available Cash for the Year Ended December 31, 2006 and the Twelve Months Ended June 30, 2007

If we had completed the Formation Transactions and this offering on January 1, 2006, our pro forma available cash for the year ended December 31, 2006 would have been approximately $17.1 million—this amount would have been insufficient by approximately $3.1 million to pay the full initial distribution amount on all of our units and would have been sufficient to pay only 85% of the initial quarterly distributions on our units for the twelve months ended December 31, 2006.

If we had completed the Formation Transactions and this offering on July 1, 2006, our pro forma available cash for the twelve months ended June 30, 2007 would have been approximately $22.6 million, which would have been sufficient to pay the full initial distribution amount on all of our units. 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 September 30, 2008. See "—Assumptions and Considerations" below for the specific assumptions underlying this belief.

Unaudited pro forma consolidated available cash includes $0.5 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 will pay Abraxas Petroleum $1.5 million per year for general and administrative expenses for the first two years following this offering, 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 net income for the year ended December 31, 2006 or for the twelve months ended June 30, 2007.

The pro forma financial statements upon which pro forma available cash is based do not purport to present our results of operations had the Formation Transactions and 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, 2006, and for the twelve months ended June 30, 2007, the amount of cash we would have had available for distributions to our unitholders, assuming in each case that the Formation Transactions and this offering had been consummated at the beginning of the period presented.

Abraxas Energy
Unaudited Pro Forma Consolidated Available Cash

		Year Ended December 31, 2006						Twelve Months Ended June 30, 2007
		Assuming no exercise of underwriters' over-allotment option			Assuming exercise of the underwriters' over-allotment option			Assuming no exercise of underwriters' over-allotment option			Assuming exercise of the underwriters' over-allotment option
		(In thousands, except per unit data)
Pro Forma Net Income(a)		$	18,260		$	18,658		$	12,198		$	12,596
Plus:
	Depreciation, depletion and amortization expense		12,496			12,496			12,121			12,121
	Amortization of deferred financing fees		199			199			199			199
	Net interest expense (income)(b)		73			(325	)(c)		77			(321	)(c)
	Loss on debt extinguishment		—			—			6,455			6,455
	Unrealized loss (gain) on hedging		(71	)		(71	)		(1,539	)		(1,539	)

Adjusted EBITDA(d)		$	30,957		$	30,957		$	29,511		$	29,511
Less:
	Cash interest expense (income)		—			(398	)(c)		—			(398	)(c)
	Stock-based compensation (expense)		(983	)		(983	)		(983	)		(983	)
	Capital expenditures(e)		14,365			14,365			7,229			7,229
	Incremental expenses(f)		500			500			500			500

Pro Forma Available Cash		$	17,075		$	17,473		$	22,765		$	23,163

Distributions per unit		$	1.50		$	1.50		$	1.50		$	1.50

Pro Forma Cash Distributions:
	Distributions to our general partner	$	403		$	414		$	403		$	414
	Distributions to public common unitholders		3,526			4,054			3,526			4,054
	Distributions to Private Investors		8,478			8,478			8,478			8,478
	Distributions to restricted unitholders		69			69			69			69
	Distributions to Abraxas Petroleum and its affiliates		7,698			7,698			7,698			7,698

Total distributions		$	20,174		$	20,713		$	20,174		$	20,713

(Shortfall) / Excess		$	(3,099	)	$	(3,240	)	$	2,591		$	2,450

(a): Reflects net income of Abraxas Petroleum derived from its historical financial statements for the period indicated, giving pro forma effect to the Formation Transactions and 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 of the underwriters' over-allotment option would generate interest income of $0.4 million assuming a 5% interest rate.
(d): 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" beginning on page 16.
(e): These capital expenditures reflect the actual capital that Abraxas Petroleum spent on our properties for the periods indicated. If Abraxas Petroleum had spent our estimated maintenance capital expenditures for the twelve months ending September 30, 2008 of $11.5 million, we would not have had sufficient cash available to pay our full initial quarterly distributions for four quarters on all of our units for the year ended December 31, 2006 and the twelve months ended June 30, 2007.
(f): Represents the incremental expenses that we expect to incur as a result of being a publicly traded partnership. 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.

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 September 30, 2008.

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), 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 on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007, and on an estimated basis for the twelve months ending September 30, 2008:

	Pro Forma for Year Ended December 31, 2006	Pro Forma for Twelve Months Ended June 30, 2007	Estimated Twelve Months Ending September 30, 2008
Production:
Oil (MBbl)	128	127	151
Gas (MMcf)	5,953	5,684	5,033
Gas equivalents (MMcfe)	6,719	6,443	5,941
Daily Production:
Oil (Bopd)	349	347	413
Gas (Mcfpd)	16,311	15,572	13,750
Gas equivalents (Mcfepd)	18,407	17,652	16,231

We estimate that our production for the twelve months ending September 30, 2008 will be 5,941 MMcfe, which represents a decline of 11.8% as compared to the year ended December 31, 2006, and a decline of 8.0%, as compared to the twelve months ended June 30, 2007. The decline is due in part to limited capital expenditures over the twelve months ended June 30, 2007, during which Abraxas Petroleum spent a total of $7.2 million in capital expenditures on our properties. Our estimated production for the twelve months ending September 30, 2008 reflects natural field declines offset by production that we believe will be generated by our estimated 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 80% of our production for the twelve months ending September 30, 2008 will be produced from wells producing on June 30, 2007 and that the remaining 20% will be produced from new wells and recompletion / workover projects, including production from wells that are currently classified as proved undeveloped. Historically, on our properties, we have added 1.0 Mcfepd of production for every $3,300 of capital expended. During the twelve months ending September 30, 2008, we estimate that we will spend $11.5 million on maintenance capital expenditures, which includes new wells and recompletion / workover projects on our existing 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 producing oil and gas in commercial quantities based on our past drilling performance. Over the past five years, Abraxas Petroleum drilled 11 gross (7.8 net) wells on our properties, of which 100% have resulted in commercially productive wells.

Prices. The table below illustrates the relationship between realized prices and NYMEX prices on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007, as compared to our estimate for the twelve months ending September 30, 2008:

	Pro Forma for Year Ended December 31, 2006		Pro Forma for Twelve Months Ended June 30, 2007		Estimated Twelve Months Ending September 30, 2008
Oil:
Average NYMEX oil price ($/Bbl)	$	66.20	$	63.46	$	67.00
Realized price ($/Bbl)		63.73		60.93		64.50

Differential to NYMEX	$	2.47	$	2.53	$	2.50
Gas:
Average NYMEX gas price ($/Mcf)	$	6.73	$	6.88	$	8.00
Realized price ($/Mcf)		5.63		5.81		6.90

Differential to NYMEX	$	1.10	$	1.07	$	1.10
Gas Equivalents:
Realized price ($/Mcfe)	$	6.20	$	6.32	$	7.49

We have estimated average NYMEX oil and gas prices of $67.00 per barrel and $8.00 per Mcf, respectively, for the twelve months ending September 30, 2008 based on NYMEX futures prices as of August 13, 2007 that averaged $70.23 per barrel for oil and $8.19 per Mcf for gas for the twelve months ending September 30, 2008. For the year ended December 31, 2006, average NYMEX oil and gas prices were $66.20 per barrel and $6.73 per Mcf, respectively, and for the twelve months ended June 30, 2007, average NYMEX oil and gas prices were $63.46 per barrel and $6.88 per Mcf, respectively. We have applied a differential to the NYMEX prices which reflects our historical averages and results in estimated realized prices for the twelve months ending September 30, 2008. For pro forma periods, 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 $2.50 for the twelve months ending September 30, 2008 as compared to $2.47 and $2.53, respectively, on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007. Our gas price differential to the average NYMEX price is expected to average $1.10 for the twelve months ending

September 30, 2008 as compared to $1.10 and $1.07, respectively, on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007.

Hedging. The following table summarizes our realized oil and gas prices on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007, and on an estimated basis for the twelve months ending September 30, 2008:

	Pro Forma for Year Ended December 31, 2006		Pro Forma for Twelve Months Ended June 30, 2007		Estimated Twelve Months Ending September 30, 2008
Oil:
Realized price ($/Bbl)	$	63.73	$	60.93	$	64.50
Realized hedging gain ($/Bbl)		—		—		1.31

Combined realized oil price ($/Bbl)	$	63.73	$	60.93	$	65.81
Gas:
Realized price ($/Mcf)	$	5.63	$	5.81	$	6.90
Realized hedging gain ($/Mcf)		0.09		0.03		0.34

Combined realized gas price ($/Mcf)	$	5.72	$	5.84	$	7.24
Gas Equivalents:
Combined realized price ($/Mcfe)	$	6.28	$	6.35	$	7.81

We estimate realized hedging gain for the twelve months ending September 30, 2008 based upon the hedging arrangements, or derivative contracts, that we have entered into, as detailed below. For the twelve months ending September 30, 2008, we have hedging arrangements covering an average 238 barrels of oil per day at a weighted average price of $69.28 per barrel and 7,728 Mcf of gas per day at a weighted average price of $8.61 per MMbtu, or 57% of our total estimated daily production. These hedging arrangements result in a realized hedging gain of $2.28 per barrel and $0.61 per Mcf for the hedged volumes and $1.31 per barrel and $0.34 per Mcf when applied to all estimated production for the twelve months ending September 30, 2008. 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, 2006 and for the twelve months ended June 30, 2007, we realized a $0.09 per Mcf gain and $0.03 per Mcf gain on our hedging arrangements, respectively.

The following table summarizes our oil derivative contracts:

	NYMEX-based Fixed Price Swaps
	Barrels per day	Price ($/Bbl)
July 2007—December 2007	260	$	67.35
January 2008—December 2008	230	$	70.01
January 2009—December 2009	200	$	70.01
January 2010—December 2010	175	$	69.06

The following table summarizes our gas derivative contracts:

	NYMEX-based Fixed Price Swaps
	MMbtu per day	($/MMbtu)
July 2007—December 2007	9,300	$	8.22
January 2008—December 2008	7,200	$	8.78
January 2009—December 2009	5,800	$	8.55
January 2010—December 2010	4,900	$	8.19

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 operating revenue on a pro forma basis (including realized gain from hedges) for the year ended December 31, 2006 and the twelve months ended June 30, 2007, and on an estimated basis for the twelve months ending September 30, 2008:

			Pro Forma for Year Ended December 31, 2006		Pro Forma for Twelve Months Ended June 30, 2007		Estimated Twelve Months Ending September 30, 2008
			(In thousands)
Oil:
	Oil revenues		$	8,127	$	7,712	$	9,760
	Oil hedges			—		—		198

		Total oil revenues		8,127		7,712		9,958
Gas:
	Gas revenues			33,514		33,022		34,725
	Gas hedges			562		176		1,727

		Total gas revenues		34,076		33,198		36,452

Total oil and gas revenues			$	42,203	$	40,910	$	46,410

We estimate oil and gas revenues for the twelve months ending September 30, 2008 based upon our estimated production multiplied by the estimated average NYMEX price less the estimated differential. Realized hedging revenue is based upon our hedging arrangements and reflect the difference between the estimated NYMEX price and the weighted average hedge price for the hedged production for the twelve months ending September 30, 2008. For the year ended December 31, 2006 and the twelve months ended June 30, 2007, our oil and gas revenues were $42.2 million and $40.9 million, respectively.

Gas comprises 85% of our total estimated production for the twelve months ending September 30, 2008. As a consequence, our revenues are more sensitive to changes in gas prices than to changes in oil prices. The following table shows estimated Adjusted EBITDA sensitivities under various assumed NYMEX gas prices for the twelve months ending September 30, 2008. 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 $1.10. We have assumed no changes in our production based on changes in prices and that our hedging counter-parties will perform as expected.

	Estimated Twelve Months Ending September 30, 2008
	(In thousands, except per unit data and percentages)
NYMEX gas price ($/Mcf)	$	6.00		$	7.00		$	8.00		$	9.00
NYMEX oil price ($/Bbl)	$	67.00		$	67.00		$	67.00		$	67.00
Combined daily production (Mcfepd)		16,231			16,231			16,231			16,231
Percentage gas		85	%		85	%		85	%		85	%
Total revenues	$	41,842		$	44,114		$	46,410		$	48,731
Lease operating expenses		5,879			5,879			5,879			5,879
Production taxes		3,083			3,542			4,004			4,467
General and administrative expenses		2,000			2,000			2,000			2,000

Adjusted EBITDA	$	30,880		$	32,693		$	34,527		$	36,385

As NYMEX gas prices decline, our Adjusted EBITDA does not decline proportionately due to the effects of our hedging arrangements. However, the change in production taxes, which are calculated as a percentage of our oil and gas revenues, excluding the effects of hedging, are correlated with commodity prices. Furthermore, we have assumed no changes in production or lease operating expenses during the twelve months ended September 30, 2008. However, 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 September 30, 2008.

Capital Expenditures and Expenses

Capital Expenditures. We estimate that our capital expenditures for the twelve months ending September 30, 2008 will be approximately $11.5 million as compared to $4.5 million, $20.7 million, $14.4 million and $7.2 million, respectively, on a pro forma basis for the years ended December 31, 2004, 2005 and 2006 and the twelve months ended June 30, 2007. The historical amounts reflect the actual capital expenditures on our properties by Abraxas Petroleum. The $11.5 million of capital expenditures for the twelve months ending September 30, 2008, 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 our properties, 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 September 30, 2008. We expect to finance these maintenance capital expenditures with cash flow from operations. We intend to fund growth capital with a combination of cash flow from operations, borrowings from our credit facility and sales of equity or debt 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 pro forma lease operating expenses on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2006 and the twelve

months ended June 30, 2007 and our estimate of our lease operating expenses on an aggregate basis and on a per Mcfe basis for the twelve months ending September 30, 2008:

	Pro Forma for Year Ended December 31, 2006		Pro Forma for Twelve Months Ended June 30, 2007		Estimated Twelve Months Ending September 30, 2008
	(In thousands, except per unit data)
Lease operating expenses	$	4,997	$	5,344	$	5,879
Lease operating expenses ($/Mcfe)	$	0.74	$	0.83	$	1.00

We estimate that our lease operating expenses for the twelve months ending September 30, 2008 will be approximately $5.9 million as compared to $5.3 million on a pro forma basis for the twelve months ended June 30, 2007. The $0.5 million increase in estimated lease operating expenses is primarily attributable to expected increases in oilfield service costs and additional water disposal fees that we expect to incur.

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, 2006 and the twelve months ended June 30, 2007, and on an estimated basis for the twelve months ending September 30, 2008:

	Pro Forma for Year Ended December 31, 2006			Pro Forma for Twelve Months Ended June 30, 2007			Estimated Twelve Months Ending September 30, 2008
	(In thousands, except percentages)
Oil and gas revenues(a)	$	41,641		$	40,734		$	44,485
Production taxes	$	3,695		$	3,769		$	4,004
Production taxes as a percentage		8.9	%		9.3	%		9.0	%

(a): Excludes effect of hedges.

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 September 30, 2008 will be approximately $2.0 million, which includes $0.5 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 will pay Abraxas Petroleum $1.5 million per year for general and administrative expenses for the first two years following this offering, 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." We have not included any non-cash unit based compensation expense in our forecast of general and administrative expenses.

Interest Expense. We intend to use the net proceeds of this offering to repay in full the indebtedness outstanding under our credit facility. As a result, we have estimated that we will have no cash interest expense for the twelve months ending September 30, 2008. We have also estimated that we will fund our maintenance capital expenditures for the twelve months ending September 30, 2008 of $11.5 million from cash flow from operations.

Regulatory, Industry and Economic Factors. Our estimate for the twelve months ending September 30, 2008 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 September 30, 2008 are expected to be $20.2 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 December 31, 2007 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 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, 2002, 2003, 2004, 2005 and 2006 are derived from the audited financial statements of Abraxas Petroleum. The selected historical consolidated financial data of Abraxas Petroleum as of and for the six months ended June 30, 2006 and 2007 are derived from the unaudited financial statements of Abraxas Petroleum. Our selected historical consolidated financial data as of June 30, 2007 is derived from our unaudited financial statements. The selected pro forma consolidated financial data for the year ended December 31, 2006 and for the six months ended June 30, 2007 are derived from our unaudited pro forma consolidated financial statements included in this prospectus beginning on page F-2 and give effect to the Formation Transactions and the completion of this offering and the use of proceeds from this offering as described in "Use of Proceeds."

			Abraxas Petroleum—Historical
			Year Ended December 31,													Six Months Ended June 30, (unaudited)
			2002			2003			2004			2005		2006		2006		2007
			(In thousands, except per share data)
Consolidated Statements of Operations Data:
Operating revenue:
	Oil and gas production revenues		$	20,835		$	29,710		$	33,073		$	47,314	$	50,094	$	25,149	$	24,192
	Other revenue			706			670			781			1,311		1,629		1,460		2,332

		Total operating revenue		21,541			30,380			33,854			48,625		51,723		26,609		26,524
Operating costs and expenses:
	Lease operating and production taxes			7,639			8,342			8,567			11,094		11,776		5,538		6,025
	Depreciation, depletion and amortization expense			9,194			7,608			7,213			8,914		14,393		7,136		6,756
	General and administrative expense			4,715			4,223			5,238			5,757		5,160		2,422		2,583
	Other			567			609			671			756		819		430		373
	Proved property impairment			28,178			—			—			—		—		—		—

		Total operating expenses		50,293			20,782			21,689			26,521		32,148		15,526		15,737

Operating income (loss)				(28,752	)		9,598			12,165			22,104		19,575		11,083		10,787
Net interest expense				24,597			16,293			17,857			13,970		16,738		8,085		6,868
Amortization of deferred financing fees				1,325			1,630			1,848			1,589		1,591		795		547
Financing costs				967			4,406			1,657			—		—		—		—
(Gain) on debt redemption				—			—			(12,561	)		—		—		—		—
Loss on debt extinguishment				—			—			—			—		—		—		6,455
Other (income) expense				201			100			387			274		—		—		—
(Gain) on sale of assets				—			—			—			—		—		—		(58,498	)

Income (loss) from continuing operations before cumulative effect of accounting change, income tax and minority interest				(55,842	)		(12,831	)		2,977			6,271		1,246		2,203		55,415
Cumulative effect of accounting change				—			395			—			—		—		—		—
Income tax expense (benefit)				—			—			(6,060	)		—		—		—		715

Minority interest				—			—			—			—		—		—		1,460

Net income (loss) from continuing operations			$	(55,842	)	$	(13,226	)	$	9,037		$	6,271	$	1,246	$	2,203	$	56,160

Diluted earnings per share:
	Income (loss) from continuing operations		$	(1.87	)	$	(0.36	)	$	0.23		$	0.15	$	0.03	$	0.05	$	1.28
	Cumulative effect of accounting change			—			(0.01	)		—			—		—		—		—

Net income (loss) per common share from continuing operations—diluted			$	(1.87	)	$	(0.37	)	$	0.23		$	0.15	$	0.03	$	0.05	$	1.26

Weighted average common shares outstanding—diluted(1)				29,979			35,364			38,895			41,164		43,862		44,119		44,588

(1): For the years ended December 31, 2002 and 2003 none of the shares issuable in connection with stock options or warrants are included in diluted shares. Inclusion of these shares would be antidilutive due to losses incurred in those periods.

		Abraxas Energy—Pro Forma
		Formation Transactions		After Offering		Formation Transactions		After Offering
		Year Ended December 31, (unaudited)				Six Months Ended June 30, (unaudited)
		2006				2007
		(In thousands, except per unit data)
Consolidated Statements of Operations Data:
	Total operating revenue	$	42,203	$	42,203	$	21,896	$	21,896
	Lease operating and production taxes		8,692		8,692		4,666		4,666
	Depreciation, depletion and amortization expense		12,496		12,496		5,738		5,738
	General and administrative expense		1,500		1,500		750		750
	Stock-based compensation		—		983		—		492
	Net interest, net of interest income		2,569		73		1,270		31
	Amortization of deferred financing fees		199		199		100		100
	Loss on debt extinguishment		—		—		6,455		6,455

	Net income	$	16,747	$	18,260	$	2,917	$	3,664

	Net income per unit (basic)	$	1.47	$	1.36	$	0.26	$	0.27

	Units outstanding (basic)		11,362		13,449		11,362		13,449

																Abraxas Energy— Historical
	Abraxas Petroleum—Historical															Abraxas Energy— Historical
	Abraxas Petroleum—Historical															At June 30, (unaudited)
	At December 31,															At June 30, (unaudited)
	2002			2003			2004			2005			2006			2007
	(In thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	(65,609	)	$	(2,444	)	$	(4,592	)	$	(4,880	)	$	(3,719	)	$	4,517
Total assets		181,425			126,437			152,685			121,866			117,486			95,872
Long-term debt		236,943			184,649			126,425			129,527			127,614			35,000
Stockholders'/partners' equity (deficit)		(142,254	)		(72,203	)		(53,464	)		(23,701	)		(21,619	)		58,186
Other Data:
Capital expenditures for the period	$	5,070		$	9,194		$	9,269		$	35,350		$	26,346		$	3,324

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 related notes included elsewhere in this prospectus. 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 interest in us, and will beneficially own a 38.2% limited partner interest in us, assuming the underwriters do not exercise their over-allotment option to purchase additional common units.

Basis of Presentation

Because we were not formed until May 2007, we have included the historical financial statements of Abraxas Petroleum in this prospectus as well as the discussion of the results of operations and period-to-period comparisons covering the historical results of Abraxas Petroleum. As the historical results of Abraxas Petroleum include combined information for our oil and gas properties, as well as the properties retained by Abraxas Petroleum following the Formation Transactions, Abraxas Petroleum's historical results of operations and period-to-period comparisons of its results may not be indicative of our future results. To provide additional information relating specifically to our properties, we have also included historical revenue, direct expenses and other information specific to our properties. 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 our 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, 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.

Retained Properties

Abraxas Petroleum's core areas of operation are in South and West Texas and east central Wyoming. After contributing properties with 65.4 Bcfe of proved reserves at December 31, 2006 to us in May 2007, Abraxas Petroleum retained 33.4 Bcfe of proved reserves, located primarily in the Permian Basin of West Texas, of which over 70% were categorized 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 15,000 gross acres) and in the Mowry Shale Play (approximately 50,000 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.

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 prices 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. 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 Petroleum had capital expenditures for 2006 of $14.4 million on our properties and $3.3 million for the six months ended June 30, 2007 and we have a capital budget for the remainder of 2007 of $8 to $10 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 Abraxas Petroleum for the years ended December 31, 2004, 2005 and 2006 and for the six months ended June 30, 2006 and 2007 and our net production volumes on a pro forma basis for the year ended December 31, 2006 and for the six months ended June 30, 2007:

	Abraxas Petroleum—Historical
	Abraxas Petroleum—Historical					Abraxas Energy— Pro Forma
	Year Ended December 31,			Six Months Ended June 30,		Abraxas Energy— Pro Forma
	Year Ended December 31,			Six Months Ended June 30,		Year Ended December 31, 2006	Six Months Ended June 30, 2007
	2004	2005	2006	2006	2007	Year Ended December 31, 2006	Six Months Ended June 30, 2007
Total production (MMcfe)	5,779	6,109	7,718	3,786	3,521	6,719	2,988
Average daily production (Mcfepd)	15,789	16,736	21,144	20,917	19,454	18,407	16,509

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 price differential 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. During the first half of 2006, prices for oil and gas were at record or near-record levels. Supply and geopolitical uncertainties resulted in significant price volatility during the second half of 2006 with both oil and gas prices weakening. NYMEX futures prices for West Texas Intermediate (WTI) oil averaged $66.18 per barrel for the year, with a low price of $55.81 per barrel occurring in the fourth quarter of 2006. NYMEX futures price for Henry Hub gas declined from an average of $9.13 per MMbtu during 2005 to an average of $6.98 per MMbtu during 2006, with a low price of $4.20 occuring in September 2006. The gas market continues to be driven by high storage inventories and mild weather conditions for much of the country. At June 29, 2007, the NYMEX futures price for oil and gas were $70.68 per barrel and $6.77 per MMbtu, respectively.

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 Btu content; and
•: gathering, processing and transportation costs.

During 2006, differentials averaged $2.47 per Bbl of oil and $1.10 per Mcf of gas.

Our credit facility required us to enter into hedging arrangements for not less than 75% (nor more than 90%) of our projected oil and gas production. For the remainder of 2007 and continuing through December 2010, we have NYMEX-based fixed price commodity swaps covering approximately 75% of

our projected net proved developed producing reserves. We intend to enter into 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. 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" and "—Quantitative and Qualitative Disclosure about Market Risk."

We currently have the following derivative contracts in place:

Period Covered	Hedged Product	Hedged Volume (Production per Day)	Fixed Price
July–December 2007	Natural Gas	9,300 MMbtu	$	8.22
July–December 2007	Crude Oil	260 Bbl	$	67.35
Year 2008	Natural Gas	7,200 MMbtu	$	8.78
Year 2008	Crude Oil	230 Bbl	$	70.01
Year 2009	Natural Gas	5,800 MMbtu	$	8.55
Year 2009	Crude Oil	200 Bbl	$	70.01
Year 2010	Natural Gas	4,900 MMbtu	$	8.19
Year 2010	Crude Oil	175 Bbl	$	69.06

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 were not subject to operating agreements prior to the Formation Transactions. Abraxas Petroleum will continue to operate our properties that were subject to operating agreements prior to the Formation Transactions, to the extent Abraxas Petroleum was the operator prior to the contribution of our assets to us. We will reimburse Abraxas Petroleum for its costs in performing the services on our behalf under the operating agreements, plus related expenses.

States regulate the development, production, gathering and sale of oil and gas, including imposing production and other taxes and requirements for obtaining drilling permits. Texas currently imposes a production tax on all oil and gas production. In addition to production taxes, Texas also imposes 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. Pursuant to our omnibus agreement, we will pay Abraxas Petroleum $1.5 million per year for general and administrative expenses for the first two years following this offering, 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 $0.5 million 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 sales of debt or equity securities. At June 30, 2007, we had $30.0 million of availability under our credit facility and after giving effect to the application of the proceeds of this offering, we will have availability of $65.0 million which reflects the current amount of our borrowing base. For a description of our credit facility, please see "—Liquidity and Capital Resources—Credit Facility."

Borrowings and Interest. We currently have outstanding indebtedness of $35.0 million under our credit facility. Our cash interest expense for a full year would have been $2.5 million based on current interest rates and our outstanding indebtedness at June 30, 2007. 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.

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 over 90% of our properties, allowing for substantial control over the timing and incurrence of capital expenditures. We have identified 80 additional drilling locations (of which 16 were classified as proved undeveloped at June 30, 2007) on our existing leasehold, the successful development of which we believe could significantly increase our production and proved reserves. Over the past five years, Abraxas Petroleum has drilled 11 gross (7.8 net) wells on our properties, of which 100% have 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 44% of our total estimated proved reserves at June 30, 2007 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 are volatile and have increased significantly since the beginning of 2004. 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 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
•: the price and availability of alternative fuels.

A substantial portion of our estimated production is currently hedged through December 2010, and we intend to continue to enter into hedging arrangements in the future, to help mitigate the impact of price volatility on our cash flow.

The increase in commodity prices since 2004 has resulted in increased drilling activity and demand for drilling rigs, equipment and crews. Due to the expected continued favorable commodity price environment and related demand pressures, we anticipate drilling service and labor costs, as well as costs of equipment and raw materials, to exceed current levels.

We expect to fund our capital expenditures with cash flow from operations, borrowings under our credit facility and sales 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 distributions to unitholders for each quarter for the twelve months ending September 30, 2008. Please read "—Liquidity and Capital Resources" beginning on page 74 and "Cash Distribution Policy and Restrictions on Distributions" beginning on page 41 for more information.

We expect 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.

Results of Operations—Abraxas Energy

Comparison of Six Months Ended June 30, 2006 to Six Months Ended June 30, 2007

Operating Revenue—Abraxas Energy

The following table illustrates the primary components of pro forma revenue for the six months ended June 30, 2006 and 2007 for our properties:

			Six Months Ended June 30,
			2006		2007
			(Dollars in thousands, except per unit data)
Operating revenue:
	Oil sales		$	4,121	$	3,706
	Gas sales			16,967		16,475
	Realized hedge gain (loss)			511		(71	)
	Unrealized hedge gain			46		1,786

		Total operating revenue	$	21,645	$	21,896

Operating income			$	10,645	$	10,742
Volumes:
Oil (MBbl)				63.7		62.8
Gas (MMcf)				2,881.2		2,611.5
Gas equivalents (MMcfe)				3,263.6		2,988.2
Realized oil price ($/Bbl)			$	64.66	$	59.02
Realized gas price ($/Mcf)			$	6.07	$	6.29

During the six months ended June 30, 2007, operating revenue from oil and gas sales decreased to $20.2 million from $21.1 million for the first six months of 2006. The decrease in revenue was primarily due to a decline in oil and gas volumes and lower realized oil prices, partially offset by an increase in realized gas prices during the first six months of 2007 as compared to the same period of 2006. A decline in oil and gas volumes had a negative impact of $1.6 million for the first six months of 2007, while the net result of realized prices had a positive impact of $0.7 million for the first six months of 2007.

Oil volumes decreased from 63.7 MBbls during the six months ended June 30, 2006 to 62.8 MBbls for the same period of 2007. Gas volumes decreased from 2,881.2 MMcf for the six months ended June 30, 2006 to 2,611.5 MMcf for the same period of 2007. The decrease in oil and gas volumes were primarily due to natural field declines.

Operating Expenses—Abraxas Energy

The following table summarizes pro forma operating expenses for the six months ended June 30, 2006 and 2007 for our properties:

			Six Months Ended June 30,
			2006		2007
			(Dollars in thousands)
Direct operating expenses:
	Lease operating expenses		$	2,476	$	2,824
	Production and other taxes			1,619		1,842

		Total direct operating expenses	$	4,095	$	4,666

Operating expenses, which we refer to as LOE, for the six months ended June 30, 2007 increased to $4.7 million compared to $4.1 million in the same period of 2006. The increase in LOE was due to a general increase in the cost of field services. LOE on a per Mcfe basis for the six months ended June 30, 2007 was $1.56 per Mcfe compared to $1.25 for the same period of 2006. The increase in per Mcfe cost was attributable to the decrease in production volumes during the first six months of 2007 as compared to 2006 as well as the overall increase in costs.

Comparison of Three Years Ended December 31, 2004, 2005 and 2006—Abraxas Energy

The following table illustrates the primary components of pro forma revenue for the three years ended December 31, 2004, 2005 and 2006 for our properties:

		Years Ended December 31,
		2004		2005		2006
		(Dollars in thousands, except per unit data)
Operating revenue:
	Oil sales	$	5,894	$	6,811	$	8,127
	Gas sales		18,723		31,834		34,076
	Gas liquids sales		2		—		—

	Total operating revenue	$	24,619	$	38,645	$	42,203

	Operating income	$	11,733	$	21,717	$	19,515
Volumes:
	Oil (MBbls)		144.0		124.8		127.5
	Gas (MMcf)		3,475.4		4,224.4		5,953.4
	Gas liquids (MBbls)		0.1		—		—
	Gas equivalents (MMcfe)		4,340.0		4,973.2		6,718.4
	Realized oil price ($/Bbl)	$	40.92	$	54.59	$	63.73
	Realized gas price ($/Mcf)	$	5.39	$	7.54	$	5.72
	Realized gas liquids price ($/Bbl)	$	22.70	$	—	$	—

The following table summarizes pro forma operating expenses for the three years ended December 31, 2004, 2005 and 2006 for our properties.

			Years Ended December 31,
			2004		2005		2006
			(Dollars in thousands)
Direct operating expenses:
	Lease operating expenses		$	3,717	$	4,824	$	4,996
	Production and other taxes			2,245		3,343		3,695

		Total direct operating expenses	$	5,962	$	8,167	$	8,692

Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2006

Operating Revenue—Abraxas Energy

During the year ended December 31, 2006, operating revenue from oil and gas increased by $3.6 million from $38.6 million in 2005 to $42.2 million in 2006. The increase in revenue was primarily due to increased volumes in 2006 as compared to 2005, offset by lower realized gas prices in 2006 as compared to 2005. Higher volumes contributed $10.1 million to oil and gas revenue, and increased realized oil prices contributed $1.1 million. Lower realized gas prices had a negative impact of $7.6 million on operating revenue during 2006.

Oil volumes increased from 124.8 MBbls in 2005 to 127.5 MBbls during 2006. The increase in oil production was primarily from wells in South Texas that were brought onto production during 2006. Gas volumes increased from 4.2 Bcf in 2005 to 6.0 Bcf in 2006. This increase was primarily due to production from the La Escalera 1AH well in our Oates SW area of West Texas that was drilled and brought on-line in August 2005. This well produced 2.2 Bcf in 2006 as compared to 0.6 Bcf in 2005. The increase in production was partially offset by natural field declines.

Operating Expenses—Abraxas Energy

Operating expenses, or LOE, increased from $8.2 million in 2005 to $8.7 million in 2006. The increase in LOE was primarily due to a general increase in the cost of field services. Lower production taxes, due to the lower realized price for gas, were offset by increased ad valorem taxes related to new wells. Our LOE on a per Mcfe basis for the year ended December 31, 2006 was $1.29 per Mcfe compared to $1.64 per Mcfe in 2005. The decrease on a per Mcfe basis was primarily due to increased volumes in 2006 as compared to 2005.

Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2005

Operating Revenue—Abraxas Energy

During the year ended December 31, 2005, operating revenue increased by $14.0 million from $24.6 million in 2004 to $38.6 million in 2005. The increase in revenue was primarily due to increased gas volumes in 2005 as compared to 2004, partially offset by a decrease in oil volumes and higher realized commodity prices in 2005 as compared to 2004. Higher gas volumes contributed $5.6 million to operating revenue while decreased oil volumes had a negative impact of $1.1 million. Higher realized commodity prices contributed $9.5 million to oil and gas revenue during 2005.

Oil volumes decreased from 144.0 MBbls in 2004 to 124.8 MBbls during 2005. The decrease in oil production was primarily due to natural field declines. Gas volumes increased from 3.5 Bcf in 2004 to 4.2 Bcf in 2005. This increase was primarily due to new production during 2005 offset by natural field declines.

Operating Expenses—Abraxas Energy

Operating expenses, or LOE, increased from $6.0 million in 2004 to $8.2 million in 2005. The increase in LOE was primarily due to a general increase in the cost of field services. The increase in LOE was primarily due to higher production taxes associated with higher commodity prices in 2005 as compared to 2004, as well as a general increase in the cost of field services. Our LOE on a per Mcfe basis for the year ended December 31, 2005 was $1.64 per Mcfe compared to $1.37 per Mcfe in 2004. The increase on a per Mcfe basis was due to increased overall operating expenses in 2005 as compared to 2004.

Results of Operations—Abraxas Petroleum

The following table illustrates the primary components of revenue for the six months ended June 30, 2006 and 2007, as well as the respective oil and gas production volumes and average sale prices for such periods. All data is for continuing operations.

		Abraxas Petroleum—Historical Six Months Ended June 30,
		2006		2007
		(Dollars in thousands, except per unit data)
Operating revenue:
Oil sales		$	6,142	$	5,733
Gas sales			19,007		18,459
Realized hedge gain (loss)			283		(126	)
Unrealized hedge gain			363		1,816
Rig operations			805		639
Other			9		3

	Total operating revenue	$	26,609	$	26,524

Operating income		$	11,083	$	10,787
Volumes:
Oil (MBbl)			97.5		99.3
Gas (MMcf)			3,200.8		2,925.0
Gas equivalents (MMcfe)			3,786.1		3,521.1
Realized oil price ($/Bbl)		$	62.97	$	57.70
Realized gas price ($/Mcf)		$	6.03	$	6.27

Comparison of Six Months Ended June 30, 2006 to Six Months Ended June 30, 2007

Operating Revenue—Abraxas Petroleum

During the six months ended June 30, 2007, operating revenue from oil and gas sales decreased to $24.2 million from $25.1 million for the first six months of 2006. The decrease in revenue was primarily due to lower oil and gas volumes and lower realized oil prices, partially offset by higher realized gas prices. Lower volumes had a negative impact on revenue of $1.6 million for the six months ended June 30, 2007. Higher realized gas prices contributed $499,000 to revenue, offset by $523,000 due to lower realized oil prices.

Oil volumes increased from 97.5 MBbls during the six months ended June 30, 2006 to 99.3 MBbls for the same period of 2007. The increase in oil volumes was primarily due to new production brought

online during the second half of 2006. Gas volumes decreased from 3,201 MMcf for the six months ended June 30, 2006 to 2,925 MMcf for the same period of 2007. The decrease in gas volumes was primarily due to property sales and field declines partially offset by a well brought onto production in May 2007 that contributed 97.5 MMcf for the period.

Operating Expenses—Abraxas Petroleum

The following table summarizes Abraxas Petroleum's operating expenses for the six months ended June 30, 2006 and 2007.

			Abraxas Petroleum—Historical Six Months Ended June 30,
			2006		2007
			(Dollars in thousands)
Direct operating expenses:
	Lease operating expenses		$	3,488	$	3,821
	Production and other taxes			2,050		2,204

		Total direct operating expenses	$	5,538	$	6,025

LOE for the six months ended June 30, 2007 increased to $6.0 million compared to $5.5 million for the same period in 2006. The increase in LOE was due to a general increase in the cost of field services. LOE on a per Mcfe basis for the six months ended June 30, 2007 was $1.71 per Mcfe compared to $1.46 for the same period of 2006. The increase in per Mcfe cost was attributable to the decrease in volumes during the first six months of 2007 as compared to 2006 as well as the overall increase in cost.

General and Administrative Expenses—Abraxas Petroleum

G&A expenses, excluding stock-based compensation, decreased slightly from $2.1 million for the six months ended June 30, 2006 to $2.0 million for the same period of 2007. G&A expense on a per Mcfe basis was $0.58 for the first six months of 2007 compared to $0.54 for the same period of 2006. The increase in G&A expense on a per Mcfe basis was primarily due to a decline in volumes during the first six months of 2007 compared to the same period in 2006.

Stock-Based Compensation—Abraxas Petroleum

Abraxas Petroleum currently utilizes the Black-Scholes option pricing model to measure the fair value of stock options granted to employees. Options granted to its employees are valued at the date of grant and expense is recognized over the options vesting period. For the six months ended June 30, 2007 and 2006, stock-based compensation for Abraxas Petroleum was approximately $544,000 and $370,000, respectively. For more information relating to Abraxas Petroleum's accounting for stock-based compensation please see "—Critical Accounting Policies" beginning on page 77.

Depreciation, Depletion and Amortization Expenses—Abraxas Petroleum

Depreciation, depletion and amortization, which we refer to as DD&A expense, decreased to $6.8 million for the six months ended June 30, 2007 from $7.1 million for the same period of 2006. Abraxas Petroleum's DD&A on a per Mcfe basis for the six months ended June 30, 2007 was $1.92 per Mcfe compared to $1.90 per Mcfe in 2006.

Interest Expense—Abraxas Petroleum

Net interest expense decreased to $6.9 million for the first six months of 2007 from $8.1 million for the same period of 2006. The decrease in interest expense was due to the refinancing and repayment on May 25, 2007 of Abraxas Petroleum's previously outstanding senior notes and Abraxas Petroleum's previously outstanding senior secured revolving credit facility.

Comparison of Years Ended December 31, 2004, 2005 and 2006

The following table illustrates the primary components of revenue for the three years ended December 31, 2004, 2005 and 2006, as well as oil and gas production volumes and average sale prices for such periods. All data has been restated to reflect continuing operations.

		Abraxas Petroleum—Historical Years Ended December 31,
		2004		2005		2006
		(Dollars in thousands, except per unit data)
Operating revenue:
	Oil sales	$	8,843	$	10,354	$	12,446
	Gas sales		23,996		36,960		37,648
	Gas liquid sales		234		—		—
	Rig and other		781		1,311		1,629

	Total operating revenue	$	33,854	$	48,625	$	51,723

	Operating income	$	12,165	$	22,104	$	19,575
Volumes:
	Oil (MBbls)		220.4		194.4		200.4
	Gas (MMcf)		4,403.0		4,942.4		6,515.0
	Gas liquids (MBbls)		8.9		—		—
	Gas equivalents (MMcfe)		5,778.8		6,108.8		7,717.4
	Realized oil price ($/Bbl)	$	40.12	$	53.27	$	62.10
	Realized gas price ($/Mcf)	$	5.45	$	7.48	$	5.78
	Realized gas liquids price ($/Bbl)	$	26.32	$	—	$	—

The following table summarizes Abraxas Petroleum's expenses for the three years ended December 31, 2004, 2005 and 2006.

			Abraxas Petroleum—Historical Years Ended December 31,
			2004		2005		2006
			(Dollars in thousands)
Direct operating expenses:
	Lease operating expenses		$	6,442	$	6,870	$	7,291
	Production and other taxes			2,125		4,224		4,485

		Total direct operating expenses	$	8,567	$	11,094	$	11,776

Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2006

Operating Revenue—Abraxas Petroleum

During the year ended December 31, 2006, operating revenue from oil and gas sales increased by $2.8 million from $47.3 million in 2005 to $50.1 million in 2006. The increase in revenue was primarily due to increased production volumes in 2006 as compared to 2005 offset by lower gas prices realized in 2006 as compared to 2005. Higher production volumes contributed $12.1 million to oil and gas revenue, and increased oil realized prices contributed $1.8 million. Lower gas prices had a negative impact of $11.1 million on oil and gas revenue during 2006.

Oil sales volumes increased from 194.4 MBbls in 2005 to 200.4 MBbls during 2006. The increase in oil production was primarily due to production from wells in Wyoming and South Texas that were brought onto production during 2006. Gas sales volumes increased from 4.9 Bcf in 2005 to 6.5 Bcf in 2006. This increase was primarily due to production from the La Escalera 1AH well in West Texas that was drilled and brought onto production in August 2005. This well produced 2.2 Bcf in 2006 as compared to 0.6 Bcf in 2005. The increase in production was partially offset by natural field declines and the sale of properties in Live Oak County, Texas effective August 1, 2006. These properties produced 286.8 MMcf in 2005 compared to 182.3 MMcf in 2006 through the date of sale.

Operating Expenses—Abraxas Petroleum

Operating expenses, or LOE, increased from $11.1 million in 2005 to $11.8 million in 2006. The increase in LOE was primarily due to a general increase in the cost of field services. Lower production taxes, due to the lower realized price for gas, were offset by increased ad valorem taxes related to new wells. Abraxas Petroleum's LOE on a per Mcfe basis for the year ended December 31, 2006 was $1.52 per Mcfe compared to $1.82 per Mcfe in 2005. The decrease on a per Mcfe basis was primarily due to increased production volumes in 2006 as compared to 2005.

General and Administrative Expenses—Abraxas Petroleum

G&A expense, excluding stock-based compensation, decreased from $5.5 million in 2005 to $4.2 million in 2006. The decrease in G&A expense in 2006 was primarily due to higher performance bonuses paid in 2005 as compared to 2006. Performance bonuses amounted to $162,000 in 2006, as compared to $960,000 in 2005. Abraxas Petroleum's G&A expense on a per Mcfe basis decreased from $0.90 in 2005 to $0.54 in 2006. The decrease in the per Mcfe cost was due to decreased G&A expense in 2006 as compared to 2005 as well as increased production volumes in 2006 as compared to 2005.

Stock-Based Compensation—Abraxas Petroleum

Abraxas Petroleum currently utilizes the Black-Scholes option pricing model to measure the fair value of stock options granted to its 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 Abraxas Petroleum on the alternative models available to value option grants, and in conjunction with the type and number of stock options expected to be issued in the future, Abraxas Petroleum has determined that it will continue to use the Black-Scholes model for option valuation as of the current time. For more information relating to Abraxas Petroleum's accounting for stock-based compensation please see "—Critical Accounting Policies" beginning on page 77.

As a result of the retrospective adoption of SFAS 123R, the expenses previously recognized under the rules of variable accounting were reversed and a compensation expense measured according to SFAS 123R was recorded. As a result of the adoption of this accounting change, Abraxas Petroleum recognized stock-based compensation of $998,000 during 2006 compared to $247,000 in 2005, as restated. The increase in stock-based compensation in 2006 as compared to 2005 was due to new

options granted during the latter part of 2005 and the first half of 2006, and the increase in the calculated fair value of these grants due to higher option prices as a result of the increase in the price of Abraxas Petroleum's common stock over previous option grants. Also contributing to the increase were director options grants that vest upon issuance resulting in all of the fair value of the options being recognized as stock-based compensation in the current period.

Depreciation, Depletion and Amortization Expenses—Abraxas Petroleum

DD&A expense increased from $8.9 million in 2005 to $14.4 million in 2006. The increase in DD&A was primarily due to increased production volumes in 2006 as well as a general increase in drilling and development cost in 2006 as compared to 2005. The increase in development cost was a result of an increase in estimated future development cost which causes an increase in the depletion base on which depletion is calculated. Abraxas Petroleum's DD&A expense on a per Mcfe basis for 2006 was $1.86 per Mcfe as compared to $1.46 per Mcfe in 2005. The increase in the per Mcfe basis was due to the increased depletion base as a result of higher estimated future development cost in 2006 as compared to 2005 which was partially offset by higher production volumes in 2006.

Interest Expense—Abraxas Petroleum

Interest expense increased from $14.0 million to $16.7 million for 2006 compared to 2005. The increase in interest expense was primarily due to increased interest rates during 2006.

Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2005

Operating Revenue—Abraxas Petroleum

During the year ended December 31, 2005, operating revenue from oil and gas sales increased by $14.2 million from $33.1 million in 2004 to $47.3 million in 2005. The increase in revenue was primarily due to increased commodity prices realized in 2005 as compared to 2004, as well as an increase in gas production volumes. Higher commodity prices contributed $12.6 million to oil and gas revenue while increased production volumes contributed $1.6 million to revenue.

Prior to 2005, Abraxas Petroleum was being paid on certain wells for the liquid content of its gas as a separate component, as well as the value of the residue gas after processing. In 2005, Abraxas Petroleum elected to be paid for this gas at the wellhead. Accordingly, Abraxas Petroleum did not recognize any gas liquids revenue in 2005. Oil sales volumes decreased slightly from 220.4 MBbls in 2004 to 194.4 MBbls during 2005. The decrease was primarily due to natural field declines. Gas sales volumes increased from 4.4 Bcf in 2004 to 4.9 Bcf in 2005. This increase was primarily due to new production during 2005 offset by natural field declines. New production brought on line at various times during 2005 contributed 1.1 Bcf to gas production and was partially offset by natural field declines.

Operating Expenses—Abraxas Petroleum

LOE increased from $8.6 million in 2004 to $11.1 million in 2005. The increase in LOE was primarily due to higher production taxes associated with higher commodity prices in 2005 as compared to 2004 as well as a general increase in the cost of field services and the amount of services required by Abraxas Petroleum as it increased its drilling activity during 2005 as compared to 2004. Abraxas Petroleum's LOE on a per Mcfe basis for the year ended December 31, 2005 was $1.82 per Mcfe compared to $1.48 per Mcfe in 2004. The increase on a per Mcfe basis was due to increased cost in 2005 as compared to 2004.

General and Administrative Expenses—Abraxas Petroleum

G&A expense, excluding stock-based compensation, increased from $5.1 million in 2004 to $5.5 million in 2005. The increase in G&A expense in 2005 was primarily due to higher performance bonuses in 2005 as compared to 2004. Our G&A expense on a per Mcfe basis increased from $0.89 in 2004 to $0.90 in 2005. The increase in per Mcfe cost was due to increased expense in 2005 as compared to 2004.

Stock-Based Compensation—Abraxas Petroleum

Abraxas Petroleum currently utilizes the Black-Scholes option pricing model to measure the fair value of stock 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 Abraxas Petroleum on the alternative models available to value option grants, and in conjunction with the type and number of stock options expected to be issued in the future, Abraxas Petroleum has determined that it will continue to use the Black-Scholes model for option valuation as of the current time. For more information relating to Abraxas Petroleum's accounting for stock-based compensation please see "Critical Accounting Policies" beginning on page 77.

As a result of the retrospective adoption of SFAS 123R, the expenses previously recognized under the rules of variable accounting were reversed and a compensation expense measured according to SFAS 123R was recorded. As a result, Abraxas Petroleum recognized stock-based compensation of $247,000 during 2005 as a result of the adoption of this accounting change compared to $112,000 in 2004, as restated.

Depreciation, Depletion and Amortization Expenses—Abraxas Petroleum

DD&A expense increased from $7.2 million in 2004 to $8.9 million in 2005. The increase in DD&A was primarily due to increased production volumes in 2005 and increased capital expenditures in 2005 as compared to 2004. Abraxas Petroleum's DD&A expense on a per Mcfe basis for 2005 was $1.46 per Mcfe as compared to $1.25 per Mcfe in 2004.

Interest Expense—Abraxas Petroleum

Interest expense decreased from $17.9 million to $14.0 million for 2005 compared to 2004. The decrease in interest expense was due to decreased debt levels during 2005. While the outstanding debt of Abraxas Petroleum at December 31, 2005 was slightly higher than the balance as December 31, 2004, the level of debt during the course of 2004, prior to the financial restructuring that occurred in October 2004, was significantly higher. In addition, during most of 2004, interest on Abraxas Petroleum's then outstanding secured notes was payable by the issuance of additional notes, which caused its cash interest expense in 2004 to be $7.6 million. With the issuance of the notes in October 2004, interest became payable in cash, which led to all of the interest paid in 2005 being paid in cash.

Financing Costs—Abraxas Petroleum

Financing costs in 2004 were $1.7 million compared to zero in 2005. Financing costs represent costs related to refinancing activities, which do not qualify for amortization over the life of the debt. The 2004 costs relate to refinancing activities during 2004. Abraxas Petroleum did not undertake any activities in 2005 which would have given rise to financing costs.

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:

•: the exploitation and development of existing properties, including drilling and completion costs of wells; and
•: 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 Abraxas Petroleum's operations, are summarized in the following table and discussed in further detail below:

	Abraxas Petroleum—Historical Year Ended December 31,
	2004			2005			2006
	(Dollars in thousands)
Net cash provided by operating activities	$	27,000		$	21,099		$	15,561
Net cash used in investing activities		(9,269	)		(35,350	)		(14,102	)
Net cash (used in) provided by financing activities		(65,684	)		14,877			(1,458	)

Total	$	(47,953	)	$	626		$	1

Operating activities for the year ended December 31, 2004 provided Abraxas Petroleum with $27.0 million of cash. Investing activities used $9.3 million during 2004 primarily for the development of oil and gas properties. Financing activities used $65.7 million during 2004 primarily for payments on long-term debt and deferred financing fees.

Operating activities for the year ended December 31, 2005 provided Abraxas Petroleum with $21.1 million of cash. Expenditures in 2005 of approximately $35.4 were primarily for the development of oil and gas properties. Financing activities provided $14.9 million during 2005, of which $11.3 million was provided by a private placement of common stock, $28.4 million was provided from long-term borrowings offset by $25.3 million of payments on long-term debt.

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.

Capital Expenditures. Capital expenditures related to our properties in 2004, 2005 and 2006 were $4.5 million, $20.7 million and $14.4 million, respectively. During 2004, 2005 and 2006, capital expenditures were primarily for the development of existing properties. Abraxas Petroleum made $3.3 million of capital expenditures on our properties during the six months ended June 30, 2007 compared to $10.6 million for the six months ended June 30, 2006, and we anticipate making capital expenditures for the remainder of 2007 ranging from $8 to $10 million, which will be used primarily for

the exploitation and development of our current 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 decline and if our costs of operations continue to increase as a result of the scarcity of drilling rigs or if our production volumes decrease, our cash 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 75% of our estimated production from our net proved developed producing reserves through 2010 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 and 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 September 30, 2008, we have estimated that our maintenance capital expenditures for such twelve-month period will be approximately $11.5 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 agreement, 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 agreement. 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 will pay Abraxas Petroleum $1.5 million per year for performing these services for the first two years following this offering, 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 were not subject to operating agreements prior to the Formation Transactions. Abraxas Petroleum will continue as operator of our properties that were subject to operating agreements, prior to the Formation Transactions, to the extent Abraxas Petroleum was the operator prior to the contribution of our assets to us. 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 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 we refer to as our credit facility. Our credit facility has a maximum commitment of $150.0 million. Availability under our credit facility is subject to a borrowing base. The borrowing base under our credit facility, which is currently $65.0 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 current borrowing base of $65.0 million was determined based upon our pro forma reserves at December 31, 2006. Our borrowing base can never exceed the $150 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, and (2) the Federal Funds Rate plus 0.5%, plus in each case, (b) 0.25% to 1.25% depending on utilization of the borrowing base, or, if we elect, at the London Interbank Offered Rate plus 1.25% to 2.25%, depending on the utilization of the borrowing base. At June 30, 2007, the interest rate on the facility was 7.13%. Subject to earlier termination rights and events of default, the stated maturity date of our credit facility is May 25, 2011. 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 agreements for not less than

75% (no more than 90%) of our projected oil and gas production from our net proved developed producing reserves. On May 25, 2007, we entered into NYMEX-based fixed price commodity swaps at then current market prices on approximately 75% of our projected net proved developed producing reserves for the period from June 1, 2007 through December 31, 2010.

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 the credit facility, there is no borrowing base deficiency and the amount of 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 $65.0 million) or the total commitment amount of our credit facility (which is $150.0 million) at such time.

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:

•: incur or guarantee additional indebtedness;
•: transfer or sell assets;
•: create liens on assets;
•: engage in transactions with affiliates;
•: make any change in the principal nature of our business; and
•: 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.

Off-Balance Sheet Arrangements. At June 30, 2007, 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 is 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 June 30, 2007 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 operations for Abraxas Petroleum and our properties are based upon the consolidated financial statements of Abraxas Petroleum, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires Abraxas Petroleum and 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 and Abraxas Petroleum evaluate such estimates and assumptions on a regular basis. We and Abraxas Petroleum 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 and of the financial statements of Abraxas Petroleum. 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 and those of Abraxas Petroleum. Please read Note 1 of the Notes to the Consolidated Financial Statements of Abraxas Petroleum 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 and Abraxas Petroleum 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 and those of Abraxas Petroleum 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, and those of Abraxas Petroleum, 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:

•: the quality and quantity of available data;
•: the interpretation of that data;
•: the accuracy of various mandated economic assumptions; and

•: the judgment of the persons preparing the estimate.

Our proved reserve information included in this prospectus was based on evaluations prepared by independent petroleum engineers. 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.

Hedge Accounting. We use commodity price hedges to limit our exposure to fluctuations in oil and gas prices. Results of those hedging transactions are reflected in revenue.

Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," which we refer to as SFAS 133, is effective for Abraxas Petroleum and 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. In 2003, Abraxas Petroleum elected out of hedge accounting as prescribed by SFAS 133. Accordingly all of its 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. We intend to elect out of hedge accounting as prescribed by SFAS 133—accordingly all of our derivatives are required to be recorded at fair value on our balance sheet, while changes in fair value of contracts will be 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. Abraxas Petroleum has elected early adoption of SFAS 123R.

SFAS 123R permits companies to adopt its requirements using either a "modified prospective" method, or a "modified retrospective" method. Abraxas Petroleum has 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 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.

Abraxas Petroleum currently utilizes the Black-Scholes option pricing model to measure the fair value of stock 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 Abraxas Petroleum on the alternative models available to value option grants, and in conjunction with the type and number of stock 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 options.

As of the date of this prospectus, we have not issued any incentive compensation awards under the long-term incentive plan of Abraxas Energy.

Recent Accounting Pronouncements

Financial Accounting Standards Board—FIN 48

In June 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109." FIN 48 requires an entity to evaluate its tax positions following a two-step process. The first step requires an entity to determine whether it is more-likely-than-not that a tax position will be sustained based on the technical merits of the position. The second step requires an entity to recognize in the financial statements each tax position that meets the more-likely-than-not criterion. Each recognized tax position should be measured at the largest amount of benefit that has a greater than 50 percent likelihood of being realized. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 was adopted effective January 1, 2007 and had no impact on us.

Statement of Financial Accounting Standards No. 157

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, "Fair Value Measurements", which we refer to as SFAS 157. This standard clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or liability. Additionally, it establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. We have not yet determined the impact that the implementation of SFAS No. 157 will have on our results of operations or financial condition if any. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007.

Staff Accounting Bulletin No. 108

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements when quantifying Misstatements in Current Year Financial Statements," which we refer to as SAB 108. SAB 108 requires companies to evaluate the materiality of identified unadjusted errors on each financial statement and related financial statement disclosure using both the rollover approach and the iron curtain approach, as those terms are defined in SAB 108. The rollover approach quantifies misstatements based on the amount of the error in the current year financial statement, whereas the iron curtain approach quantifies misstatements based on the effects of correcting the misstatement existing in the balance sheet at the end of the current year, irrespective of the misstatement's year(s) of origin. Financial statements would require adjustment when either approach results in quantifying a misstatement that is material. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. If a company determines that an adjustment to prior year financial statements is required upon adoption of SAB 108, and does not elect to restate its previous financial statements, then it must recognize the cumulative effect of applying SAB 108 in fiscal 2006 beginning balances of the affected assets and liabilities with a corresponding adjustment to the fiscal 2006 opening balance in retained earnings. SAB 108 is effective for interim periods of the first fiscal year ending after November 15, 2006 and was adopted by Abraxas Petroleum effective October 1, 2006. The adoption of SAB 108 did not have a material impact on Abraxas Petroleum's consolidated financial statements.

Statement of Financial Accounting Standards No. 159

In February 2007, the FASB issued SFAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities." SFAS 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not expect the implementation of SFAS 159 to have a material impact on our results of operations or financial condition.

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, 2006, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flow by approximately $4.2 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 hedging arrangements for a significant portion of our oil and gas production. Our credit facility required us to enter into hedging arrangements for not less than 75% (nor more than 90%) of our projected oil and gas production. On May 25, 2007, we entered into NYMEX-based fixed price commodity swaps at then current market prices on approximately 75% of our projected net proved developed producing reserves for the period from June 1, 2007 to December 31, 2010.

On January 1, 2001, Abraxas Petroleum 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 expect to 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 current revenue.

We currently have the following derivative contracts in place:

Period Covered	Hedged Product	Hedged Volume (Production per Day)	Fixed Price
July — December 2007	Natural Gas	9,300 MMbtu	$	8.22
July — December 2007	Crude Oil	260 Bbl	$	67.35
Year 2008	Natural Gas	7,200 MMbtu	$	8.78
Year 2008	Crude Oil	230 Bbl	$	70.01
Year 2009	Natural Gas	5,800 MMbtu	$	8.55
Year 2009	Crude Oil	200 Bbl	$	70.01
Year 2010	Natural Gas	4,900 MMbtu	$	8.19
Year 2010	Crude Oil	175 Bbl	$	69.06

BUSINESS

General

We are a Delaware limited partnership formed by Abraxas Petroleum in May 2007 to develop, produce and acquire oil and gas properties. Our assets consist primarily of producing and non-producing properties located in the Delaware Basin of West Texas and the Gulf Coast Basin of South Texas.

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 Petroleum had $3.3 million of capital expenditures on our properties during the first six months of 2007, and we have approved a capital budget ranging from $8 to $10 million for the remainder of 2007 for the development of our current properties. The final amount of our capital expenditures in 2007 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 information relating to our properties:

		As of June 30, 2007				Six Months Ended June 30, 2007
		Producing Wells	Average Working Interest		Estimated Net Proved Reserves (Bcfe)	Pro Forma Net Production (MMcfe)	Pro Forma Net Daily Production (MMcfepd)
West Texas
	ROC Complex	63	71	%	22.1	1,001	5.5
	Oates SW	4	100	%	17.8	966	5.3
South Texas
	Edwards	10	95	%	20.0	635	3.5
	Portilla	27	100	%	5.4	386	2.1

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.

West Texas

Our West Texas operations are concentrated in the deep gas producing formations (Devonian, Montoya and Ellenburger) and the shallower oil producing sandstones (Bell and Cherry Canyon) of the Delaware Basin in Ward, Pecos and Reeves Counties. At June 30, 2007, we owned interests in 67 gross (48 net) producing wells in West Texas. These wells produce oil and gas from multiple stacked formations at depths ranging from 5,000 to 16,000 feet. We believe that development drilling on our West Texas properties is relatively low to moderate risk.

Our West Texas areas of operations are as follows:

ROC Complex. Our ROC Complex consists of 63 producing wells located in Pecos, Reeves and Ward County, Texas. We own an average 71% working interests in these wells which 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 of our wells in this complex except eight, seven of which are operated by EOG Resources, Inc. Our estimated net proved reserves as of June 30, 2007 in the ROC Complex were 18.8 Bcf of gas and 560.6 MBbl of oil, or 22.1 Bcfe. During the six months ended June 30, 2007, our pro forma net production from the ROC Complex was 1,001 MMcfe, or 5.5 MMcfe per day.

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 - 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 June 30, 2007, we had identified 50 drilling locations in the ROC Complex, including three proved undeveloped locations. Nine drilling locations, of which two are proved undeveloped, are located in the Howe field, which currently produces gas from the Devonian and Montoya formations, as 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. During the twelve months ending September 30, 2008, we plan to re-enter at least one well in the Howe field and target the Devonian formation.

Oates SW. Our Oates SW area consists of four producing wells located in Pecos County, Texas. We own 100% working interests in these wells which produce gas from the Devonian formation at 13,500 feet. Abraxas Petroleum operates all of our wells in this area. Our estimated net proved reserves

as of June 30, 2007 in the Oates SW area were 17.8 Bcf of gas. During the six months ended June 30, 2007, our pro forma net production from the Oates SW area was 966 MMcf, or 5.3 MMcf per day.

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 June 30, 2007, we had five proved undeveloped locations in the Oates SW area, comprised of three Devonian locations and two Montoya completions. 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. During the twelve months ending September 30, 2008, we plan to drill at least one horizontal well targeting the Devonian formation.

South Texas

Our South Texas operations are located in the Gulf Coast Basin and 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 June 30, 2007, we owned interests in 37 gross (36 net) wells in South Texas. These wells produce oil and gas from formations at depths ranging from 7,000 to 13,500 feet. We believe that development drilling on our South Texas properties is relatively low to moderate risk.

Our South Texas areas of operations are as follows:

Edwards. Our Edwards area consists of 10 producing wells located in DeWitt and Lavaca Counties, Texas. We own an average working interest of 95% in these wells, which are operated by Abraxas Petroleum. Eight of the producing wells produce gas from the Edwards formation at a depth of approximately 13,500 feet and two produce gas from the overlying Wilcox formation at approximately 9,000 feet. Our estimated net proved reserves as of June 30, 2007 in the Edwards area were 20.0 Bcf of gas. During the six months ended June 30, 2007, our pro forma net production from the Edwards area was 635 MMcf, or 3.5 MMcf per day.

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 June 30, 2007, our six producing wells in the Yoakum (Edwards) field, which is our primary field in the Edwards area, had produced a cumulative total of 16.0 Bcfe and had estimated proved reserves remaining of 14.3 Bcfe, for a total of 30.3 Bcfe, or an average of 5.1 Bcfe per well.

At June 30, 2007, we had five proved undeveloped drilling locations in the Edwards area. In addition, we have identified 10 potential in-fill drilling locations based on the success in neighboring fields of wells drilled on denser spacing by other operators. During the twelve months ending September 30, 2008, we plan to drill at least one horizontal well targeting the Edwards formation.

Portilla. Our Portilla field consists of 27 producing wells located in San Patricio County, Texas. We own a 100% working interest in these wells which are operated by Abraxas Petroleum. These wells

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. Our estimated net proved reserves as of June 30, 2007 in the Portilla field were 2.7 Bcf of gas and 440.7 MBbl of oil, or 5.4 Bcfe. During the six months ended June 30, 2007, our pro forma net production from the Portilla field was 386 MMcfe, of 2.1 MMcfe per day.

The Portilla field was discovered by The Superior Oil Company, predecessor to Mobil Oil Corporation, in 1950 and has produced a cumulative total of 512 Bcfe as of June 30, 2007. 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. 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 June 30, 2007, we had three 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. During the twelve months ending September 30, 2008, we plan to drill at least one Portilla well targeting the Frio sands.

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 approximately three years. We currently have 80 identified drilling locations, which provide us with a multi-year inventory of drilling opportunities.

•

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:

•: high quality, long-lived reserves;
•: relatively predictable production profiles;
•: low operating cost structure;
•: low-risk exploitation and development potential;
•: operational control with high working interest; and
•: geographic concentration.

•

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.

•

Reducing cash flow volatility through commodity price hedging. We have entered into NYMEX-based fixed price commodity swaps at then current market prices, covering approximately 75% of our estimated oil and gas production from our existing proved developed producing reserves through December 2010. We expect to continue to enter into hedging arrangements in the

future to reduce our exposure to commodity price fluctuations and achieve more predictable cash flows.

Competitive Strengths

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

•: Abraxas Petroleum has operated over 90% of our properties for over ten years and is an efficient, low-cost operator. Abraxas Petroleum will operate 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 our properties in an efficient, cost-effective manner.
•: Our properties are characterized by relatively predictable, long-lived production. Our major properties are located in large, mature fields with a high percentage of proved developed producing reserves and relatively low decline rates. These properties have relatively predictable production profiles that make them well-suited to our objective of making stable cash distributions to our unitholders.
•: 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 our properties. Over the past five years, Abraxas Petroleum has drilled 11 gross (7.8 net) wells on our properties, of which 100% resulted in commercially productive wells. For the two-year period ended December 31, 2006, Abraxas Petroleum spent approximately $35.1 million on the drilling, workover or recompletion of wells on our properties.
•: 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, as well as many other producing basins in North America.
•: 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 38.2% 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.
•: Strong financial position. We will have no long-term debt outstanding following the closing of this offering, which will provide us financial flexibility to operate our business and finance our exploitation, development and acquisition activities. After consummation of this offering, we will have $65.0 million of availability under our credit facility which will be available for our general purposes, including capital expenditures, acquisitions and distributions.
•: 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 June 30, 2007:

		Developed Acreage		Undeveloped Acreage
		Gross Acres	Net Acres	Gross Acres	Net Acres
West Texas		10,365	8,243	1,906	1,267
South Texas		3,819	3,644	55	41

	Total	14,185	11,887	1,961	1,308

Productive Wells

The following table sets forth our producing wells as of June 30, 2007:

		Oil		Gas
		Gross	Net	Gross	Net
West Texas		39.0	30.0	28.0	18.5
South Texas		18.0	18.0	19.0	17.5

	Total	57.0	48.0	47.0	36.0

Reserves Information

Our oil and gas reserves have been estimated as of December 31, 2004, December 31, 2005, December 31, 2006 and June 30, 2007, by DeGolyer and MacNaughton, an independent engineering firm. 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 oil and gas reserves on our properties as of December 31, 2004, December 31, 2005, December 31, 2006 and June 30, 2007.

		Estimated Proved Reserves
		Proved Developed	Proved Undeveloped	Total Proved
Pro forma as of December 31, 2004
	Oil (MBbls)	967.9	90.2	1,058.1
	Gas (MMcf)	28,137.9	23,937.5	52,075.4
	Gas Equivalents (MMcfe)	33,945.3	24,478.7	58,424.0
Pro forma as of December 31, 2005
	Oil (MBbls)	922.7	108.4	1,031.1
	Gas (MMcf)	31,485.3	29,856.0	61,341.3
	Gas Equivalents (MMcfe)	37,021.5	30,506.4	67,527.9
Pro forma as of December 31, 2006
	Oil (MBbls)	897.6	78.7	976.3
	Gas (MMcf)	32,595.4	26,927.1	59,522.5
	Gas Equivalents (MMcfe)	37,981.0	27,399.3	65,380.3
As of June 30, 2007
	Oil (MBbls)	970.9	30.4	1,001.3
	Gas (MMcf)	30,951.3	28,357.5	59,308.8
	Gas Equivalents (MMcfe)	36,776.9	28,540.1	65,317.0

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, NGL and gas sales, the realized price per Bbl of oil and NGLs and per Mcf of gas produced and the operating cost per Mcfe of production sold, for

the three years ended December 31, 2006 and the six months ended June 30, 2007 relating to our properties:

	2004			2005			2006			Six Months Ended June 30, 2007
Oil sales (MBbls)		144.0			124.8			127.5			62.8
Gas sales (MMcf)		3,475			4,224			5,953			2,612
Gas liquids sales (MBbls)		0.1			—			—			—
Gas equivalents (MMcfe)		4,340			4,973			6,719			2,988
Realized oil price ($/Bbl)	$	40.92		$	54.59		$	63.73		$	59.02
Realized gas price ($/Mcf)	$	5.39		$	7.54		$	5.72		$	6.29
Realized gas liquids price ($/Bbl)	$	22.70		$	—		$	—		$	—
Realized gas equivalent price ($/Mcfe)	$	5.36		$	7.65		$	6.28		$	6.73
Differentials to NYMEX ($/Mcf)	$	(0.53	)	$	(1.04	)	$	(1.10	)	$	(1.16	)
Operating cost per Mcfe	$	1.37		$	1.64		$	1.29		$	1.56

Drilling Activities

The following table sets forth our pro forma gross and net working interests in exploratory and development wells drilled during the three years ended December 31, 2006 and the six months ended June 30, 2007 on our properties. In addition to drilling new wells during the periods below, we recompleted a number of additional wells.

				2004		2005		2006		Six Months Ended June 30, 2007
				Gross	Net	Gross	Net	Gross	Net	Gross	Net
Exploratory Productive
		Oil		—	—	—	—	—	—	—	—
		Gas		—	—	—	—	1.0	1.0	—	—
	Dry holes			—	—	—	—	—	—	—	—

			Total	—	—	—	—	1.0	1.0	—	—

Development Productive
		Oil		—	—	—	—	—	—	—	—
		Gas		1.0	1.0	3.0	3.0	1.0	1.0	2.0	1.5
	Dry holes			—	—	—	—	—	—	—	—

			Total	1.0	1.0	3.0	3.0	1.0	1.0	2.0	1.5

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. 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 2006, two purchasers, Western Gas Resources, Inc. and Southern Union Pipeline, Ltd., together accounted for approximately 49% 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 five members, with two directors meeting the independence standards established by the American Stock Exchange. For more information about these individuals, please read "Management—Directors and Executive Officers of Our General Partner" beginning on page 102.

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 will pay Abraxas Petroleum $1.5 million per year for general and administrative expenses for the first two years following this offering, 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" beginning on page 118.

Abraxas Petroleum's core areas of operation are in South and West Texas and east central Wyoming. 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. After contributing 65.4 Bcfe of proved reserves to us in May 2007, Abraxas Petroleum retained 33.4 Bcfe of proved reserves, located primarily in the Permian Basin of West Texas, of which over 70% were categorized 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 15,000 gross acres) and in the Mowry Shale Play (approximately 50,000 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" beginning on page 121 and "Risk Factors—Risks Inherent in an Investment in Us" beginning on page 29. 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 were not subject to operating agreements prior to the Formation Transactions. In addition, Abraxas Petroleum will continue as operator of our assets subject to existing operating agreements, to the extent Abraxas Petroleum was the operator prior to the Formation Transactions. 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. Our operations 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.

All of our properties are located in the State of Texas. The Texas Railroad Commission is primarily responsible for the regulation of oil and gas activities in Texas. Under the rules and regulations of the Texas Railroad Commission, 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 over 90% of our properties, possesses all material requisite permits required by the State of Texas and other local authorities. 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

Our operations 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, including the State of Texas, regulate one or more of the following:

•: 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, including Texas, 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 our operations should generally be the same as the impact on our competitors. We do not currently have any Federal or Indian oil or 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 our operations 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 except 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 our operations, but we do not expect these activities to affect our 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. Recently, however, gas gathering has received greater regulatory scrutiny at the state levels. 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 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 our operations 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, among other things:

•: require the acquisition of a permit or other authorization before construction or drilling commences;
•: 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;
•: suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas;
•: require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;
•: restrict injection of liquids into subsurface strata that may contaminate groundwater; and
•: impose substantial liabilities for pollution resulting from our operations.

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.

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 our ordinary operations, we may generate waste 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. Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil, including the oil and gas exploration and production industry, to prepare and implement spill response plans relating to the potential discharge of oil into navigable 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 and non-hazardous solid wastes. 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 wastes to be classified and regulated as non-hazardous wastes. A similar exemption is contained in many of the state counterparts to RCRA. 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 wastes. 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 required to be managed and disposed and would cause us to incur increased operating expenses. Also, in the ordinary course of the operations of our properties, small amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes are generated.

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 our operations are in material compliance with all applicable NORM standards established by the State of Texas.

Clean Water Act. The Clean Water Act, which we refer to as the CWA, and analogous state laws, impose strict 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 our operations 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 Texas, 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. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution 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. Our properties are not adversely impacted by the current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

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 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.

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 June 30, 2007, 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 were not subject to operating agreements prior to the Formation Transactions. Abraxas Petroleum will continue as operator of our assets that were subject to operating agreements prior to the Formation Transactions to the extent Abraxas Petroleum was the operator prior to the contribution of our assets to us. 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 June 30, 2007, Abraxas Petroleum had 50 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 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232. The office space consists of approximately 12,650 square feet, which is leased in its entirety through January 2009 by Abraxas Petroleum. The costs attributable to us for our use of the executive and administrative offices are reimbursable to Abraxas Petroleum under the terms of our omnibus agreement, and are subject to the annual payment of $1.5 million per year, for the first two years following this offering, subject to annual adjustments for inflation and acquisition or other expansion adjustments.

Legal Proceedings

At June 30, 2007, 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 were not subject to operating agreements prior to the Formation Transactions. Abraxas Petroleum will continue as operator of our assets that were subject to operating agreements prior to the Formation Transactions, to the extent Abraxas Petroleum was the operator prior to the contribution of our assets to us. 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. Two of the five-member Board of Directors of our general partner currently 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 American Stock Exchange. The current members of the audit and conflicts committee are Messrs. Aldridge and Patton. In compliance with rules of the American Stock Exchange, a third member will be added to the committee within one year of the consummation of this offering, at which time three of the five member board of directors will meet the independence standards required by the American Stock Exchange. 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 American Stock Exchange, as well as certain other requirements.

The audit and conflicts committee will review our external financial reporting, recommend engagement of our independent auditors, 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 Jeffrey P. Wood to serve on the Board of Directors of our general partner as their director-designee. Mr. Wood 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

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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."

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	56	Chief Executive Officer and Chairman of the Board
Barbara M. Stuckey	39	President and Chief Operating Officer
Clare Eastland-Villarreal	36	Chief Financial Officer, Treasurer and Secretary
Ralph F. Cox	75	Director
Bryant H. Patton	49	Director
Randolph C. Aldridge	63	Director
Jeffrey P. Wood	36	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 and Chief Operating Officer of our general partner since May 2007. 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 Chief

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Operating Officer 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.

Clare Eastland-Villarreal has been the Chief Financial Officer and Secretary of our general partner since June 2007 and the Treasurer of our general partner since May 2007. Ms. Villarreal has served as Controller of Abraxas Petroleum since 2002. Ms. Villarreal joined the accounting department of Abraxas Petroleum in 1990 and continuously has held positions of increasing responsibility. Since June 2007, Ms. Villarreal has also served as Chief Financial Officer and Secretary of Abraxas Operating and Abraxas Investments, and since May 2007, Ms. Villarreal has served as Treasurer of Abraxas Operating and Abraxas Investments. Ms. Villarreal received a Bachelor of Business Administration degree from the University of Texas at San Antonio in 1998 and a Master of Business Administration degree from the University of Texas at San Antonio in 2002.

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 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 co-founded Camden Resources, Inc., a private oil and gas exploration and production company in 2000 and currently serves as Executive Vice President. Mr. Patton also 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. 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 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.

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Jeffrey P. Wood was appointed to be a member of the Board of Directors of our general partner in June 2007. Mr. Wood is a Vice President of Lehman Brothers and a Principal of the Lehman Brothers MLP Opportunity Fund, an equity investment fund focused on the master limited partnership sector. Mr. Wood has held that position since June 2006. Prior to that, Mr. Wood was a Vice President in Lehman Brothers' Natural Resources investment banking group in Houston and New York, where he concentrated primarily on the midstream and MLP sectors. Mr. Wood joined Lehman Brothers in 1997. Mr. Wood received a Bachelor of Arts degree from Baylor University in 1993 and a Master of Business Administration degree from the University of Chicago's Graduate School of Business in 2001. Mr. Wood has informed us that he intends to tender his resignation as a member of our Board of Directors upon the closing of this offering.

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 will pay Abraxas Petroleum $1.5 million per year for performing these general and administrative services for the first two years following 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 $0.5 million 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. As such, our general partner did not accrue any obligations with respect to compensation for its directors and executive officers for the fiscal year ended December 31, 2006, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. 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

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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.

As of the date of this prospectus, the executive officers of our general partner have not received any incentive compensation awards under our long-term incentive plan. In conjunction with the consummation of this offering, we intend to grant awards for a total of 284,750 units to the directors and 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.

The awards to the directors and executive officers of our general partner and the executive officers of Abraxas Petroleum are as follows:

Name	Unit Options	Restricted Units
Robert L.G. Watson	63,000	6,000
Barbara M. Stuckey	42,000	4,000
Clare Eastland-Villarreal	15,750	2,500
Chris E. Williford	15,750	2,500
Lee T. Billingsley	15,750	2,500
William H. Wallace	15,750	2,500
Stephen T. Wendel	15,750	2,500
Ralph F. Cox	—	4,000
Bryant H. Patton	—	4,000
Randolph C. Aldridge	—	4,000
Jeffrey P. Wood	—	—

All directors and executive officers	183,750	34,500

The remaining 66,500 awards consist of unit options and restricted units, which we intend to grant 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.

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 and Ms. Stuckey 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 reimbursement 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:

•: 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;
•: 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. 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 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 180 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 named 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 restricted units, phantom units, unit options, unit appreciation rights, other unit-based awards and unit awards. The Board of Directors of our general partner has approved the grant of awards for a total of 284,750 units pursuant to the long-term incentive plan described below in conjunction with this offering. For a more detailed description of the long-term incentive plan, please read "—Long-Term Incentive Plan" beginning on page 107 below.

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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 is expected to be a one-time award of 4,000 restricted units to be granted upon the closing of this offering, 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 $1.5 million reimbursement to Abraxas Petroleum for general and administrative expenses pursuant to our omnibus agreement.

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 284,750 units will be granted in conjunction with this offering. 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 will be able to 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 will have 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 American Stock Exchange. 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 will provide 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

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available under our plan, which will remain at 1,136,160 or 10% of the units outstanding as determined immediately prior to the effective date of this prospectus, subject to a possible amendment of our plan by the plan administrator.

Restricted Unit Awards

A restricted unit award provides a grantee with common units that are subject to certain forfeiture restrictions, until such restrictions lapse due to the vesting of the award. Generally, the units vest over a period of time contingent upon the continuous service of the grantee of the award. If a grantee's employment or consulting arrangement or membership on the Board of Directors terminates for any reason prior to the vesting of the award, the grantee's restricted units will be automatically forfeited unless, and to the extent, the plan administrator or the terms of the award agreement provide otherwise. The plan administrator may make grants of restricted unit awards to eligible individuals as it determines in its sole discretion, and such awards will be subject to the terms and conditions as the plan administrator shall determine and set forth in individual award agreements, including the period of time over or events upon which restricted units will vest and the effect of termination of service. The plan administrator, in its discretion, may base its determination of who will receive an award or the vesting of the award on the achievement of specified financial objectives. In addition, the restricted units will vest upon a "change of control" of our partnership or our general partner, as defined in our plan or an award agreement, unless provided otherwise by the plan administrator or an award agreement. Distributions from the partnership made with respect to restricted units may be subjected to the same or different vesting provisions as the restricted unit.

Under our plan, a change of control is generally deemed to include one or more of the following events:

•: a party other than an affiliate of our general partner becoming the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of the combined voting power of the equity interests in our general partner or in us;
•: our partners approve, in one or a series of transactions, a plan for our complete liquidation;
•: the sale or other disposition by either our general partner or us of all or substantially all of its or our respective assets, as the case may be, in one or more transactions to any party other than our general partner or an affiliate of our general partner; or
•: a transaction resulting in a party other than our general partner or an affiliate of our general partner becoming our general partner.

We intend for the restricted units under our plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not be required to pay any consideration for the common units they receive, and we will receive no remuneration for the units.

Phantom Unit Award

A phantom unit award entitles the grantee to receive common units upon the vesting of the phantom units or, in the discretion of the plan administrator, cash equivalent to the value of common units. Generally, the phantom unit award vests over a period of time contingent upon the continuous service of the grantee of the award. If a grantee's employment or consulting arrangement or membership on the Board of Directors terminates for any reason, the grantee's phantom units will be automatically forfeited unless, and to the extent, the plan administrator or the terms of the award agreement provide otherwise. The plan administrator may make grants of phantom unit awards under our plan to eligible individuals as it determines in its sole discretion, and such awards will be subject to the terms and conditions as the plan administrator shall determine and set forth in award agreements,

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including the period of time over or events upon which phantom units granted will vest and the effect of termination of service. The plan administrator, in its discretion, may base its determination of who will receive an award or the vesting of the award on the achievement of specified financial objectives. In addition, the plan administrator may provide that the phantom units vest upon a "change of control" of us or our general partner.

The plan administrator may, in its discretion, grant distribution equivalent rights, which we refer to as DERs, with respect to and in conjunction with phantom unit awards. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us as to common units during the period the phantom units are outstanding. Payment of a DER may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

We intend the issuance of any common units upon vesting of the phantom units under our plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.

Unit Options

Our long-term incentive plan provides for the grant to eligible individuals of options to purchase our common units at a designated exercise price at specified periods of time. The plan administrator will determine who will receive option grants, and the terms and conditions of such option grants, in its sole discretion, provided, however, unit options must have an exercise price that is not less than the fair market value of the units on the date of grant of the option. In general, unit options granted will become exercisable as the option vests over a period of time or at certain times as determined by the plan administrator and set forth in an award agreement. In addition, the plan administrator may provide that unit options will become exercisable upon a "change of control" of our partnership or our general partner. If a grantee's employment or consulting arrangement or membership on the Board of Directors terminates for any reason, the grantee's unvested unit options will be automatically forfeited, and the grantee's vested options will be exercisable for only a limited period of time following such termination, unless, and to the extent, the option agreement or the plan administrator provides otherwise.

The issuance of unit options is intended to furnish additional compensation to plan participants and to align their economic interests with those of common unitholders.

Unit Appreciation Rights

Our long-term incentive plan provides for the grant of unit appreciation rights. A unit appreciation right (UAR) is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the UAR. Such excess will be paid in cash or common units, as determined by the plan administrator in its discretion. The plan administrator will determine who will receive an UAR award, and the terms and conditions of such UAR awards, in its sole discretion; provided, however, that unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant of the award. In general, unit appreciation rights granted will become exercisable as the UAR vests over a period of time or at certain times as determined by the plan administrator and set forth in an award agreement. In addition, the plan administrator may provide that unit appreciation rights will become exercisable upon a "change in control" of our partnership or our general partner, unless provided otherwise by the plan administrator. If a grantee's employment or consulting arrangement or membership on the Board of Directors terminates for any reason, the grantee's unvested unit appreciation rights will be automatically forfeited, and the grantee's vested options will be exercisable

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for only a limited period of time following such termination, unless, and to the extent, the grantee agreement or plan administrator provides otherwise.

The issuance of unit appreciation rights is intended to furnish additional compensation to plan participants and to align their economic interests with those of common unitholders.

Other Unit-Based Awards

Our long-term incentive plan permits the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting or other time or event determined by the plan administrator, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

U.S. Federal Income Tax Consequences of Awards Under the Long-Term Incentive Plan

Generally, there are no income tax consequences for the participant or us when awards are granted under our plan, unless such awards are not subject to a substantial risk of forfeiture upon grant, such as when they are fully vested, or unless a grantee files a valid "83(b) election" as to a restricted unit award. In the event of a fully vested award or an award on which a grantee filed a valid 83(b) election, the value of the award as of the date of grant, which would be the cash and/or the fair market value of a unit on the date of grant, will be taxable to the participant, and deductible by us, in the year the grant is made. Upon the payment to the participant of common units and/or cash in connection with the vesting of restricted units to which an 83(b) election was not made, the vesting of phantom units, or the exercise of unit options or unit appreciation rights, the participant will recognize compensation income equal to the cash and/or fair market value of the units as of the vesting date or date of exercise, and we will be entitled to a corresponding deduction. In addition, certain awards granted under this plan may constitute "deferred compensation" for purposes of Section 409A of the Internal Revenue Code, which we refer to as Section 409A, and which imposes certain restrictions on the election thereunder, and on the time and form of payment of affected compensation. Failure to satisfy the requirements of Section 409A as to awards subject to its requirements will subject the affected compensation to a 20% excise tax. The terms of our plan, together with the agreements for any awards granted under our plan, are intended to comply with Section 409A though satisfying a provided exception under the Final Regulations under Section 409A or through compliance with the Section 409A requirements for deferred compensation. As additional guidance is issued under Section 409A, we may alter the provisions of our plan and the terms of awards granted under our plan to comply with the requirements of, or satisfy an exception under, Section 409A and the guidance issued in connection therewith.

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SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common units, held by beneficial owners of 5% or more of our common units, as of August 15, 2007, as adjusted for this offering, by each director and named executive officer of our general partner, and by all directors and executive officers of our general partner as a group. The table assumes that the underwriters' over-allotment option to purchase additional common units is not exercised.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Lehman Brothers MLP Opportunity Fund L.P.(1)(2)	1,200,481	9.1	%
Michael J. Cannon(2)	1,200,481	9.1	%
Kyriacos A. Loupis(2)	1,200,481	9.1	%
Jeffrey P. Wood(2)	1,200,481	9.1	%
Citigroup Global Markets Inc.(1)(3)	850,000	6.5	%
Brendan O'Dea(3)	850,000	6.5	%
Third Point Partners LP(1)(4)	576,000	4.4	%
Third Point Partners Qualified LP(1)(4)	534,445	4.1	%
Third Point LLC(4)	1,110,445	8.5	%
Daniel S. Loeb(4)	1,110,445	8.5	%
Fiduciary/Claymore Opportunity Fund(1)(5)	525,211	4.0	%
FAMCO MLP Partners, LLC, Series ABP-1(1)(5)	150,060	1.1	%
Fiduciary Asset Management, LLC(5)	675,273	5.1	%
Charles D. Walbrandt(5)	675,273	5.1	%
Wiley D. Angell(5)	675,273	5.1	%
Joseph E. Gallagher(5)	675,273	5.1	%
James J. Cunnane, Jr.(5)	675,273	5.1	%
Mohammed Riad(5)	675,273	5.1	%
Timothy Swanson(5)	675,273	5.1	%
Quinn T. Kiley(5)	675,273	5.1	%
Katherine K. Dienner(5)	675,273	5.1	%
William N. Adams(5)	675,273	5.1	%
Valley Energy Investment Fund U.S., L.P.(1)(6)	840,337	6.4	%
Abraxas Energy Investments, LLC(7)	5,131,959	39.1	%
Energy Income and Growth Fund(1)(8)	225,090	1.7	%
Energy Income Partners, LLC(8)	225,090	1.7	%
James J. Murchie(8)	225,090	1.7	%
Eva Pao(8)	225,090	1.7	%
Linda Longville(8)	225,090	1.7	%
Saul Ballesteros(8)	225,090	1.7	%
Robert L.G. Watson(9)	—	*
Barbara M. Stuckey(9)	—	*
Clare Eastland-Villarreal(9)	—	*
Ralph F. Cox(9)	—	*
Bryant H. Patton(9)	—	*
Randolph C. Aldridge(9)	—	*
All directors and executive officers of Abraxas General Partner, LLC as a group(9)	—	*

*: Less than 1%
(1): Private Investor
(2): Michael J. Cannon, Kyriacos A. Loupis and Jeffrey P. Wood in their capacity as portfolio managers, share voting and investment control over the units held by Lehman Brothers MLP Opportunity Fund L.P. Each of Messrs. Cannon, Loupis and Wood disclaims beneficial ownership of all of such units. Lehman Brothers Inc., an affiliate of Lehman Brothers MLP Opportunity Fund L.P., is a member of the FINRA. The address of Lehman Brothers MLP Opportunity Fund L.P. is 399 Park Avenue, 9^th Floor, New York, NY 10022.

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(3): Brendan O'Dea in his capacity as its authorized employee, has voting and investment control over the units held by Citigroup Global Markets Inc. Mr. O'Dea disclaims beneficial ownership of all of such units. The address of Citigroup Global Markets Inc. is 390 Greenwich Street, 3^rd Floor, New York, NY 10013. Citigroup Global Markets Inc. is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and is a member of the FINRA. Citigroup Global Markets Inc. (i) purchased the securities for its own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing any transaction in violation of securities laws and (ii) at the time of purchase, Citigroup Global Markets Inc. did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the units purchased.
(4): Third Point LLC, and Daniel S. Loeb in his capacity as the CEO of Third Point LLC, have voting and investment control over the units held by Third Point Partners LP and Third Point Partners Qualified LP. Third Point LLC is the investment advisor for Third Point Partners LP and Third Point Partners Qualified LP. The address of Third Point LLC is 390 Park Avenue, 18^th Floor, New York, NY 10022.
(5): Pursuant to investment advisory agreements entered into with Fiduciary/Claymore Opportunity Fund and FAMCO MLP Partners, LLC, Series ABP-1, Fiduciary Asset Management, LLC. (FAMCO) holds voting and dispositive power with respect to the units held by such unitholders. The investment committee of FAMCO is responsible for the investment management of the unitholders' portfolio. As of September 14, 2007, the investment committee of FAMCO is comprised of Charles D. Walbrandt, Wiley D. Angell, Joseph E. Gallagher, James J. Cunnane, Jr., Mohammed Riad, Timothy Swanson, Quinn T. Kiley, Katherine K. Dienner and William N. Adams. The unitholders corresponding to this footnote have each represented that (i) it purchased the securities for the unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities. Piper Jaffray Companies, an affiliate of Fiduciary/Claymore Opportunity Fund and FAMCO MLP Partners, LLC, Series ABP-1 is a member of the FINRA. The address of Fiduciary/Claymore Opportunity Fund and FAMCO MLP Partners, LLC, Series ABP-1 is 8112 Maryland Avenue, Suite 400, St. Louis, MO 63105.
(6): An investment committee composed of employees of Merrill Lynch & Co., a member of the FINRA, or its affiliates, whose members may change from time to time, has voting and investment control over the units held by Valley Energy Investment Fund U.S., L.P. The address of Valley Energy Investment Fund U.S., L.P. is c/o Merrill Lynch Commodity Partners, 20 East Greenway Plaza Suite 950, Houston, TX 77046.
(7): The Board of Directors of Abraxas Petroleum, the sole member of Abraxas Investments, a member managed limited liability company whose board members may change from time to time, has voting and investment control (and has the power to appoint persons to act on its behalf in the exercise of such control) over the units held by Abraxas Investments. The members of the Board of Directors of Abraxas Petroleum disclaim beneficial ownership of all such units. The address of Abraxas Petroleum Corporation is 500 North Loop 1604 East, Suite 100, San Antonio, TX 78232.
(8): Pursuant to an interim investment advisory agreement entered into with Energy Income and Growth Fund, Energy Income Partners, LLC (EIP) holds voting and dispositive power with respect to the units held by such unitholder. The investment team of EIP is responsible for the investment management of the unitholder's portfolio. As of September 14, 2007, the investment team of EIP is comprised of James J. Murchie, Eva Pao, Linda Longville and Saul Ballesteros. The unitholder corresponding to this footnote has represented that (i) it purchased the securities for the unitholder's own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing such securities in any transaction in violation of securities laws and (ii) at the time of purchase, the unitholder did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the purchased securities. The address of Energy Income and Growth Fund is 49 Riverside Avenue, Westport, Connecticut 06880.
(9): None of the awards granted to the directors and executive officers of Abraxas General Partner, LLC under the long-term incentive plan described in "Management—Long-Term Incentive Plan" vests or is exercisable within 60 days.

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PRIVATE INVESTORS

In addition to the Private Investors listed in the beneficial ownership table, the following Private Investors also participated in the private placement of our common units:

Name		Common Units Beneficially Owned
Tortoise Capital Resources Corporation(1)		450,181
Tortoise Capital Advisors, L.L.C.(1)		450,181
H. Kevin Birzer(1)		450,181
Kenneth P. Malvey(1)		450,181
Zachary A. Hamel(1)		450,181
Terry C. Matlack(1)		450,181
David J. Schulte(1)		450,181
Martin B Perlman Associates(2)		43,261
MEDDS III(2)		52,800
PH Industries, Inc. Money Purchase Plan(2)		6,000
Martin Perlman(2)		102,061
Perlman Value Partners(3)		24,000
Daniel Perlman(3)		24,000
Morgan Stanley FBO Leonard Greenberg Roth IRA(4)		12,000
Leonard Greenberg(4)		12,000
Morgan Stanley FBO JoAnn Hassan IRA(5)		6,000
Morgan Stanley FBO JoAnn Hassan Roth IRA(5)		6,000
JoAnn Hassan(5)		12,000
Hartz Capital MLP, LLC(6)		150,061
Hartz Capital, Inc.(6)		150,061
Edward J. Stern(6)		150,061
Ronald J. Bangs(6)		150,061
Jonathan B. Schindel(6)		150,061

(1): Tortoise Capital Advisors, L.L.C. ("TCA") serves as the investment advisor to Tortoise Capital Resources Corporation. Pursuant to an Investment Advisory Agreement entered into with the unitholder, TCA holds voting and dispositive power with respect to the units held by the unitholder. The investment committee of TCA is responsible for the investment management of the unitholder's portfolio. The investment committee is comprised of H. Kevin Birzer, Zachary A. Hamel, Kenneth P. Malvey, Terry C. Matlack and David J. Schulte.
(2): Martin Perlman, in his capacity as portfolio manager, has voting and investment control over the units held by Martin B. Perlman Associates, MEDDS III and PH Industries, Inc. Money Purchase Plan. The address of Martin B. Perlman Associates, MEDDS III and PH Industries, Inc. Money Purchase Plan is 539 Durie Avenue, Closter, NJ 07624.
(3): Daniel Perlman has the power to vote or dispose of the units held in Perlman Value Partners. The address of Perlman Value Partners is 539 Durie Avenue, Closter, NJ 07624.
(4): Leonard Greenberg has the power to vote or dispose of the units held in Morgan Stanley FBO Leonard Greenberg Roth IRA. The address of Morgan Stanley FBO Leonard Greenberg Roth IRA is 539 Durie Avenue, Closter, NJ 07624.
(5): JoAnn Hassan has voting and investment control over the units held in Morgan Stanley FBO JoAnn Hassan IRA and Morgan Stanley FBO JoAnn Hassan Roth IRA. The address of Morgan Stanley FBO JoAnn Hassan IRA and Morgan Stanley FBO JoAnn Hassan Roth IRA is 539 Durie Avenue, Closter, NJ 07624.
(6): Edward J. Stern, Ronald J. Bangs and Jonathan B. Schindel, in their capacity as officers of Hartz Capital, Inc., which is the sole manager of Hartz Capital MLP, LLC, share voting and investment control over the units held by Hartz Capital MLP, LLC. Each of Messrs. Bangs and Schindel disclaims beneficial ownership of all of such units. The address of Hartz Capital MLP, LLC is 400 Plaza Drive, Secaucus, NJ 07094.

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SELLING UNITHOLDER

The selling unitholder named below is a Private Investor that acquired common units in connection with our private equity offering. The following table sets forth information concerning the ownership of common units by the selling unitholder immediately before and after this offering assuming:

•: the underwriters' over-allotment option to purchase additional common units is not exercised; and
•: the underwriters exercise their over-allotment option to purchase additional common units in full.

	Units Owned Prior to Offering			Units Owned After This Offering
Name of Selling Unitholder	Units	Percentage of Common Units Beneficially Owned	Units Offered By Selling Unitholder	Assuming Underwriters' Over-allotment Option is Not Exercised	Percentage of Common Units Beneficially Owned	Assuming Underwriters' Over-allotment Option is Exercised in Full	Percentage of Common Units Beneficially Owned
Citigroup Global Markets Inc.(1)	1,200,481	10.8%	350,481	850,000	6.5%	850,000	6.3%
Brendan O'Dea(1)	1,200,481	10.8%	350,481	850,000	6.5%	850,000	6.3%

(1): Brendan O'Dea in his capacity as its director, has voting and investment control over the units held by Citigroup Global Markets Inc. Mr. O'Dea disclaims beneficial ownership of all of such units. The address of Citigroup Global Markets Inc. is 390 Greenwich Street, 3^rd Floor, New York, NY 10013. Citigroup Global Markets Inc. is a broker-dealer registered pursuant to Section 15(b) of the Exchange Act and is a member of the NASD. Citigroup Global Markets Inc. (i) purchased the securities for its own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing any transaction in violation of securities laws and (ii) at the time of purchase, Citigroup Global Markets Inc. did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the units purchased.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Abraxas Investments, an affiliate of our general partner, will own 5,131,959 common units, representing approximately 38.2% of our common units (approximately 37.2% if the underwriters exercise their over-allotment option to purchase additional common units in full). In addition, our general partner will own a 2% general partner interest in us. Both of these entities are wholly-owned subsidiaries of Abraxas Petroleum.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with the Formation Transactions and to be made by us in connection with the ongoing operation and liquidation of Abraxas Energy Partners, L.P.

*PRIOR TO AND IN CONNECTION WITH THE OFFERING*
The consideration received by our general partner and its affiliates for their contribution in us		• 5,131,959 common units; and • a 2% general partner interest in us
Financial summary of the Formation Transactions		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.
*AFTER THE CLOSING OF THE OFFERING*
Distributions of available cash to our general partner and its affiliates		We will generally distribute 98% of our available cash to all unitholders, including affiliates of our general partner (as the holders of an aggregate of 5,131,959 common units), and 2% of our available cash to our general partner. Assuming we have sufficient available cash to pay the full initial quarterly distribution on all of our outstanding common units for four quarters, our general partner and its affiliates will receive an annual distribution of approximately $0.4 million on their 2% general partner interest and $7.7 million on their common units, excluding the restricted units granted in connection with this offering.

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Payments to our general partner and its affiliates		Our partnership agreement requires us to reimburse our general partner for 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, including expenses allocated to our general partner by its affiliates. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. We do not expect to incur any additional fees or to make other payments to these entities in connection with operating our business. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Our omnibus agreement requires us to reimburse Abraxas Petroleum for its expenses incurred on our behalf and to pay Abraxas Petroleum $1.5 million per year for the first two years following this offering for the provision of certain services. See "Summary of Formation Transaction Documents—Omnibus Agreement" below.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of Our General Partner."
*UPON LIQUIDATION*
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

In addition to the payments to be made to Abraxas Petroleum and its affiliates described above, we will also make payments to Abraxas Petroleum pursuant to the omnibus agreement and the operating agreement. See "—Summary of Formation Transaction Documents."

We do not have any policies or procedures for the review, approval or ratification of any transactions required to be reported under Item 404(a) of Regulation S-K. The Board of Directors of our general partner may adopt such policies and procedures after the completion of this offering. For information regarding potential conflicts of interest and the resolution of such conflicts under our partnership agreement, please read "Conflicts of Interest and Fiduciary Duties."

Summary of Formation Transaction Documents

We have entered into the various documents and agreements that effectuated the Formation Transactions. These agreements were not the result of arm's-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to us as could have been obtained from unaffiliated third parties.

Contribution, Conveyance and Assumption Agreement

On May 25, 2007, we entered into a contribution, conveyance and assumption agreement with Abraxas Petroleum, our general partner, Abraxas Investments and Abraxas Operating, which we refer to as our contribution agreement. For a description of the assets contributed to us and the

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consideration we conveyed for these assets, please read "Prospectus Summary—Formation Transactions" on page 2 and "Business—General" on page 83.

Under the contribution agreement, Abraxas Petroleum will indemnify us for all liabilities incurred in connection with the ownership and operation of the assets contributed to us for periods prior to May 25, 2007, other than environmental liabilities which are governed by the omnibus agreement, and we have agreed to indemnify Abraxas Petroleum for these liabilities first arising from and after May 25, 2007.

Purchase Agreement

On May 25, 2007, we entered into a purchase agreement with the Private Investors, which we refer to as the purchase agreement, pursuant to which we completed a private equity offering and issued 6,002,408 common units to the Private Investors, for gross proceeds of approximately $100.0 million. Our common units issued in connection with the purchase agreement were not registered under the Securities Act of 1933, as amended, or any applicable state securities laws. There was no general solicitation involved in the offer. We paid a cash commission of $7 million out of the proceeds of the sale to A.G. Edwards & Sons, Inc. which acted as our sole placement agent.

Registration Rights Agreement

On May 25, 2007, in connection with our private equity offering, we entered into a registration rights agreement with the Private Investors, which we refer to as our registration rights agreement. Under our registration rights agreement, we agreed as soon as practicable after May 25, 2007, (a) to prepare and file with the SEC a registration statement for (1) this initial public offering, or IPO, of our common units and (2) a shelf registration statement for the resale of the common units held by the Private Investors and (b) to use our commercially reasonable efforts to cause the IPO registration statement and the shelf registration statement to be declared effective by February 14, 2008. Therefore, in addition to the filing of this offering, we will also file with the SEC, a shelf registration statement for the resale of the common units held by the Private Investors.

Under our registration rights agreement, we agreed to cause the shelf registration statement to remain continuously effective for a period ending on the date that is the earlier of (x) the date on which all of the common units covered by the shelf registration statement have been distributed as set forth in the shelf registration statement, (y) the date on which the Private Investors may sell all common units then held by them without restriction under Rule 144(k), or (z) the date that such common units are otherwise no longer a Registrable Security (as such term is defined in our registration rights agreement).

We are required to pay liquidated damages if the IPO registration statement or the shelf registration statement is not declared effective by February 14, 2008, if the shelf registration statement is not maintained in accordance with the agreement and with respect to any common units required to be included in the shelf registration statement that are not included. The liquidated damages amount payable is $0.04165 per common unit entitled to liquidated damages for the first 60 days after February 14, 2008, with such amount increasing by an additional $0.04165 per common unit for each 30-day period for the next 60 days up to a maximum of $0.1666 per common unit. Liquidated damages are payable in cash, unless we become unable to pay liquidated damages in cash as a result of a restriction under our credit facility, in which case, we may pay the liquidated damages in the form of our common units. The determination of the number of common units payable as liquidated damages under our registration rights agreement is calculated by dividing the amount of liquidated damages payable, by the lesser of the market value of our common units at the time the liquidated damages are paid, or $16.66.

Subject to certain terms and conditions set forth in our registration rights agreement, Private Investors not selling their common units as part of this offering (but pursuant to a shelf registration

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statement, for example) will generally be eligible to sell their common units into the market beginning 60 days after the date of this prospectus except for the selling unitholder, who will generally be eligible to sell their common units into the market beginning 90 days after the date of this prospectus.

Exchange and Registration Rights Agreement

Along with Abraxas Petroleum and the Private Investors, we also entered into an exchange and registration rights agreement dated May 25, 2007. Under the terms of this agreement, in the event that we have not consummated this offering by November 15, 2008, which we refer to as the Trigger Date, the Private Investors will have the right to convert their common units purchased in the private placement offering into shares of common stock of Abraxas Petroleum, which we refer to as ABP common stock. Each of our common units will be convertible into a number of shares of ABP common stock equal to $16.66 divided by the then current market price of ABP common stock times 0.9. In the event that the rules of the American Stock Exchange require Abraxas Petroleum stockholder approval for such issuance, Abraxas Petroleum has agreed to call a special meeting of the stockholders, and the executive officers and directors of Abraxas Petroleum have agreed to vote the shares of ABP common stock then held by them in favor of such issuance. Abraxas Petroleum also agreed within 30 days of the Trigger Date, to prepare and file with the SEC a registration statement on Form S-3 or such other successor form (except that if Abraxas Petroleum is not then eligible to register for resale the ABP common stock on Form S-3, then such registration shall be on Form S-1 or any successor form), which we refer to as the Exchange Registration Statement, to enable the resale of ABP common stock, which we refer to as the Exchange Shares, by the investors or their transferees from time to time over any national stock exchange on which ABP's common stock is then traded. Abraxas Petroleum further agreed to use its commercially reasonable efforts to cause the Exchange Registration Statement to become effective by the 120^th calendar day following the Trigger Date, which we refer to as the Exchange Required Effective Date, and to cause it to remain continuously effective for a period ending on the date that is the earlier of (i) the date on which the Private Investors may sell all Exchange Shares then held by them without restriction under Rule 144(k), or (ii) such time as all Exchange Shares have been sold or otherwise transferred. If the Exchange Registration Statement is not declared effective by the Exchange Required Effective Date, Abraxas Petroleum is required to pay an amount in cash as liquidated damages equal to 1.0% of $3.83 times the number of Exchange Shares then held by such investor per each 30 day period until the Exchange Registration Statement is declared effective.

Omnibus Agreement

Our omnibus agreement, among other things, governs (i) the obligations of Abraxas Petroleum to provide certain general and administrative services to us and to our subsidiaries and (ii) Abraxas Petroleum's obligations to indemnify us and Abraxas Operating against certain environmental, tax and other liabilities. In connection with its provision of services, we are required to reimburse Abraxas Petroleum for all direct and indirect expenses incurred on our behalf and on behalf of our subsidiaries. We will pay Abraxas Petroleum $1.5 million per year for general and administrative expenses for the first two years following this offering, subject to annual adjustments for inflation and acquisition or other expansion adjustments. Reimbursements for certain public company expenses and insurance coverage expenses incurred by Abraxas Petroleum on our behalf pursuant to our omnibus agreement are not subject to this fee. The $1.5 million fee 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. Following the two year period, we do not believe that these general and administrative expenses will materially increase, except in connection with acquisitions. For the next two years, we have budgeted $2.0 million per year for general and administrative expenses, which consists of the $1.5 million payment to Abraxas Petroleum plus incremental expenses of $0.5 million as a result of being a publicly traded partnership. We expect our

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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.

Under the omnibus agreement Abraxas Petroleum will indemnify us for three years after the closing of this offering against certain potential environmental claims. Additionally, Abraxas Petroleum will indemnify us for losses attributable to right of way fees and taxes attributable to pre-closing operations. 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 the closing date of this offering. 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 will indemnify Abraxas Petroleum for all losses attributable to post-closing operations of the assets contributed to us, to the extent not subject to Abraxas Petroleum's indemnification obligations.

Operating Agreement

On May 25, 2007, Abraxas Operating entered into an operating agreement with Abraxas Petroleum. Pursuant to the operating agreement, Abraxas Petroleum will act as operator of our properties, if our working interest entitles us to control the appointment of the operator. In addition, Abraxas Petroleum will continue as operator of our properties that were subject to operating agreements prior to the Formation Transactions, to the extent Abraxas Petroleum was the operator prior to the contribution of our properties to us. Under these operating agreements, we will reimburse Abraxas Petroleum for operating expenses incurred on our behalf. 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. For the next two years, we have budgeted $1.66 per Mcfe for total operating expenses, including $1.00 per Mcfe for lease operating expenses based on our historical actuals, excluding production taxes, which we have budgeted at 9% of oil and gas revenues.

Under the 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 other equipment used on our properties. In addition, direct expenses will include the allocable share of the cost of the Abraxas Petroleum employees who perform services on our properties. The allocation of the cost of Abraxas Petroleum employees who perform services on our properties will be based on time sheets maintained by Abraxas Petroleum's employees.

Second Amended and Restated Partnership Agreement

On May 25, 2007, our general partner, Abraxas Investments and the Private Investors entered into a partnership agreement, which was amended and restated on September 19, 2007. Among other

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things, our partnership agreement provides for quarterly distributions of available cash to all unitholders on a pro rata basis, including our general partner and to Abraxas Investments. See "The Partnership Agreement" beginning on page 128, for a discussion regarding distributions of available cash.

Investors' Rights Agreement

Pursuant to the terms of an investors' rights agreement dated May 25, 2007, entered into by us, our general partner, Abraxas Petroleum and certain of the Private Investors, the Private Investors obtained the right to designate one person to serve as a member of the Board of Directors of our general partner until such time as the registration statement of which this prospectus is a part becomes effective. The Private Investors have selected Jeffrey P. Wood to serve on the Board of Directors of our general partner as their director-designee.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may continue to arise in the future as a result of the relationships among us and our general partner and its affiliates. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to affiliates of Abraxas Petroleum, which owns our general partner. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our limited partners. The Board of Directors or the audit and conflicts committee of the Board of Directors of our general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any of our other partners, on the other, our general partner will resolve that conflict. Potential conflicts of interest will be identified to the Board of Directors of our general partner by members of its management. The Board of Directors of our general partner will then determine whether to submit the potential conflict of interest to the audit and conflicts committee. We anticipate that any material transaction between Abraxas Petroleum or any of its affiliates and us, including any potential acquisitions of properties, will be submitted to the audit and conflicts committee. Our partnership agreement contains provisions that modify and limit the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of our general partner's fiduciary duty to us.

Our general partner is responsible for identifying any such conflict of interest and our general partner may choose to resolve the conflict of interest by any one of the methods described in the following sentence. Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•: approved by the audit and conflicts committee, although our general partner is not obligated to seek such approval;
•: approved by the vote of the holders of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•: on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•: fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

As required by our partnership agreement, the Board of Directors of our general partner will maintain a conflicts committee, which will be established and designated as the audit and conflicts committee, and which will be comprised of three independent directors, consistent with the rules of the American Stock Exchange. Our general partner may, but is not required to, seek approval from the audit and conflicts committee of a resolution of a conflict of interest with our general partner or its affiliates. If our general partner seeks approval from the audit and conflicts committee, the audit and conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the 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. If a matter is submitted to the audit and conflicts committee and the audit and conflicts committee does not approve the matter, we will not proceed with the matter unless and until the matter has been modified in such a manner that the audit and conflicts committee determines is fair and reasonable to us. If our general partner does not seek approval from the audit and conflicts committee and its Board of Directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies

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either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors 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. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the audit and conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to believe that he is acting in our best interests.

Conflicts of interest could arise in the situations described below, among others.

Actions taken by our general partner may affect the amount of cash available for distribution to our common unitholders.

The amount of cash that is available for distribution to our common unitholders is affected by decisions of our general partner regarding such matters as:

•: the amount and timing of capital expenditures;
•: asset sales or acquisitions;
•: borrowings under our credit facility;
•: the issuance of additional units;
•: the creation, reduction or increase of cash reserves in any quarter; and
•: corporate opportunities.

We will pay fees to and reimburse our general partner and its affiliates for expenses.

Our partnership agreement requires us to reimburse our general partner for 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, including overhead allocated to our general partner by its affiliates, including Abraxas Petroleum. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Pursuant to our omnibus agreement with Abraxas Petroleum, Abraxas Petroleum will perform general and administrative services for us and for Abraxas Operating, such as accounting, finance, land, legal and engineering. We will pay Abraxas Petroleum an annual fee of $1.5 million for performing these services, plus related expenses. Abraxas Petroleum and Abraxas Operating have entered into an operating agreement, under which Abraxas Petroleum will operate our properties that were not subject to operating agreements prior to the Formation Transactions. Abraxas Petroleum will continue as operator of our properties that were subject to operating agreements, to the extent Abraxas Petroleum was the operator prior to the contribution of our properties to us. 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" beginning on page 118.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only against our assets and not against our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of the fiduciary duties owed by our general partner to our unitholders, even if we could have obtained more favorable terms without the limitation on liability.

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Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result of arm's-length negotiations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Common units are subject to our general partner's limited call right.

Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price.

We may not choose to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who will perform services for us are selected by our general partner or by the audit and conflicts committee of its Board of Directors, and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of our common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of our common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Acquisitions of Competing Businesses; Potential Future Conflicts.

From time to time, we or our affiliates may acquire entities whose businesses compete with us. In addition, future conflicts of interest may arise between us and any entities we or our affiliates acquire. It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determine how we will address and resolve any such future conflicts of interest. However, the resolution of these conflicts may not always be in our best interest or those of our unitholders.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. The fiduciary duties our general partner owes to our unitholders are prescribed by law and our partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

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Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that our general partner might otherwise owe. We have adopted these restrictions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. These modifications are detrimental to the common unitholders because they restrict the remedies available to common unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the unitholders.

State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in "good faith" and will not be subject to any other standard under applicable law. "Good faith" requires that the person or persons making such determination or taking or declining to take such other action believe that the determination or other action is in the best interests of the partnership or the holders of the common units, as the case may be. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our unitholders or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was criminal.

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Special provisions regarding affiliated transactions	Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the audit and conflicts committee of the Board of Directors of our general partner, must be:
	•	on terms no less favorable to us than those generally provided to or available from unrelated third parties; or
	•	"fair and reasonable" to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
	If our general partner does not seek approval from the audit and conflicts committee of its Board of Directors, or the common unitholders and the Board of Directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming that presumption. These standards reduce the obligations to which our general partner would otherwise be held.
Rights and remedies of unitholders	The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of a partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of it and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read "The Partnership Agreement—Indemnification" beginning on page 139.

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DESCRIPTION OF THE COMMON UNITS

The Units

Our common units represent limited partner interests in us. The holders of units are entitled to receive quarterly cash distributions and exercise the rights or privileges available to unitholders under our partnership agreement. For a description of the rights and preferences of holders of common units in and to quarterly cash distributions, please read this section and "Cash Distribution Policy and Restrictions on Distributions" beginning on page 41. For a description of the rights and privileges of unitholders under our partnership agreement, including voting rights, please read "The Partnership Agreement" beginning on page 128.

Transfer Agent and Registrar

Duties

American Stock Transfer and Trust Company will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

•: surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
•: special charges for services requested by a common unitholder; and
•: other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, so long as it acted in good faith.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is recorded in our books and records. Each transferee:

•: represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
•: automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;
•: gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering; and
•: if such certification is requested by our general partner, certifies that the transferee is an Eligible Holder.

As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, an Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof;

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(3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly. The transfer agent has been appointed as registrar and transfer agent for the purpose of registering the common units and transfers of such common units from and after this offering.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders' rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfers of securities and the terms of our partnership agreement. Pursuant to our partnership agreement, in addition to other rights acquired upon transfer, the transferor gives the transferee the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange rules or regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in this prospectus. We will provide prospective investors with a copy of the partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•: with regard to distributions of available cash, please read "Cash Distribution Policy and Restrictions on Distributions" beginning on page 41;
•: with regard to the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties" beginning on page 121;
•: with regard to rights of holders of units, please read "Description of the Common Units" beginning on page 126; and
•: with regard to allocations of taxable income, taxable loss and other matters, please read "Material Tax Consequences" beginning on page 141.

Organization and Duration

We were formed in May 2007 and have a perpetual existence.

Purpose

Under our partnership agreement, we are permitted to engage, directly or indirectly, in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under the Delaware Act; provided that our general partner may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us, our affiliates and our subsidiaries to engage in activities other than the exploitation, development, production and acquisition of oil and gas properties, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business. For a further description of limits on our business, please read "Certain Relationships and Related Transactions" beginning on page 115.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution as a limited partnership, for the admission, withdrawal, removal or substitution of any partner, the determination of rights, preferences and privileges of any class or series of additional partnership securities we may issue, or to give effect to a merger, consolidation or conversion involving us. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement. Please read "—Amendments to Our Partnership Agreement."

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•: to remove or replace our general partner;
•: to approve some amendments to our partnership agreement; or
•: to take (or refrain from taking) other action under our partnership agreement;

constituted "participation in the control" of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years from the date of the distribution. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our interest in Abraxas Operating or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. In voting their units, affiliates of our general partner will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

Issuance of additional common units		No approval right following this offering. Please read "—Issuance of Additional Securities."
Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of the holders of a majority of our outstanding units. Please read "—Amendments to Our Partnership Agreement."
Merger of our partnership or the sale of all or substantially all of our assets		The approval of the holders of a majority of our outstanding units in certain circumstances. Please read "—Merger, Consolidation, Conversion, Sale, or Other Disposition of Assets."
Dissolution of our partnership		The approval of the holders of a majority of our outstanding units. Please read "—Termination or Dissolution."
Continuation of our business upon dissolution		The approval of the holders of a majority of our outstanding units. Please read "—Termination or Dissolution."
Withdrawal of our general partner		Under most circumstances, the approval of the holders of a majority of the units, excluding units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2017 in a manner that would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of Our General Partner."
Removal of our general partner		The approval of the holders of at least 66²/3% of the outstanding units voting as a single class, including units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of Our General Partner."

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Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to (i) an affiliate (other than an individual) or (ii) another person (other than an individual) in connection with the merger or consolidation of the general partner with or into, or sale by the general partner of all or substantially all of its assets to, such person. The approval of the holders of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2017. Please read "—Transfer of General Partner Interest."
Transfer of ownership interests in our general partner		No approval required at any time. Please read "—Transfer of Ownership Interests in Our General Partner."

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and on the terms and conditions established by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which our common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities that may effectively rank senior to our common units.

If we issue additional units in the future, our general partner is not obligated to, but may, contribute a proportionate amount of capital to us to maintain a 2% general partner interest. If our general partner does not contribute a proportionate additional amount of capital, our general partner's initial 2% interest would be reduced. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates that existed immediately prior to each issuance. Other than our general partner, the holders of common units will not have a preemptive right to acquire additional common units or other partnership securities.

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Amendments to Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. To adopt a proposed amendment, other than the amendments discussed below under "—No Unitholder Approval," our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of our outstanding units.

Prohibited Amendments

Generally, no amendment may be made that would:

(1): have the effect of reducing the voting percentage of outstanding units required to take any action under the provisions of our partnership agreement;
(2): enlarge the obligations of any limited partner without its consent; or
(3): enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) to (3) above can be amended upon the approval of the holders of at least 90% of the outstanding units. Upon completion of this offering, Abraxas Investments, an affiliate of our general partner, will own 5,131,959 of our units, which represent approximately 39.3% of our outstanding common units assuming that the underwriters' do not exercise their over-allotment option to purchase additional common units.

No Unitholder Approval

Our general partner generally may make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

(1): a change in our name, the location of our principal place of business, our registered agent or our registered office;
(2): the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
(3): a change that our general partner determines to be necessary or advisable to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the partnership and its subsidiaries will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;
(4): an amendment that is necessary, in the opinion of our counsel, to prevent the partnership or our general partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisors Act of 1940, as amended, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, whether or not substantially

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similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(5): an amendment that our general partner determines to be necessary or appropriate for the authorization of the issuance of additional partnership securities in accordance with our partnership agreement;
(6): any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
(7): an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;
(8): any amendment that our general partner determines to be necessary or appropriate for the formation by the partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
(9): a change in our fiscal year or taxable year and related changes;
(10): certain mergers or asset conveyances permitted by our partnership agreement; and
(11): any other amendments substantially similar to any of the matters described in (1) through (10) above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partners, or assignee if our general partner determines that those amendments:

(1): do not adversely affect our limited partners (or any particular class of limited partners) in any material respect;
(2): are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
(3): are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
(4): are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
(5): are required to effect the intent expressed in the purchase agreement, our omnibus agreement, our contribution agreement, our registration rights agreement, our credit facilities, this prospectus or as otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment to our partnership agreement will not affect the limitation of liability to the limited partners or result in our being treated as a corporation for federal income tax purposes in connection with any of the amendments described under "—No Unitholder Approval." No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of the holders of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the

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affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a majority of our outstanding units, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to our partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the units to be issued do not exceed 20% of our outstanding units immediately prior to the transaction.

Our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity under certain circumstances including if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. In addition, our general partner must receive an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity must provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters' rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination or Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

(1): the election of our general partner to dissolve us, if approved by the holders of a majority of our outstanding units;
(2): there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act;
(3): the entry of a decree of judicial dissolution of our partnership; and
(4): the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

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Upon a dissolution under clause (4) above, the holders of a majority of our outstanding units may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of a majority of our outstanding units subject to receipt by us of an opinion of counsel to the effect that:

•: the action would not result in the loss of limited liability of any limited partner; and
•: neither our partnership, our operating company nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all the powers of our general partner that are necessary or appropriate, liquidate our assets. The proceeds of the liquidation will be applied as follows:

•: first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and
•: then, to all partners in accordance with the positive balance in the respective capital accounts.

Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2017 without obtaining the approval of the holders of a majority of our outstanding common units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days' notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders (See "—Transfer of General Partner Interests").

Upon the voluntary withdrawal of our general partner, other than as a result of its transfer of all or part of its general partner interest in us, the holders of a majority of our outstanding common units, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner.

Our general partner may not be removed unless that removal is approved by unitholders owning not less than 66²/3% of our common units voting as a single class, including units held by our general

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partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by a majority of our outstanding units, including those held by our general partner and its affiliates. The ownership of more than 33¹/3% of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. Upon completion of this offering, Abraxas Investments, an affiliate of our general partner, will own 5,131,959 of our common units, and our general partner will own 268,983 general partner units, which in the aggregate will represent approximately 40.2% of our outstanding units, assuming that the underwriters do not exercise their over-allotment option to purchase additional common units.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:

•: an affiliate of our general partner (other than an individual); or
•: another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in us to another entity prior to December 31, 2017 without the approval of the holders of a majority of the common units outstanding, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer common units to one or more persons without unitholder approval.

Transfer of Ownership Interests in Our General Partner

At any time, Abraxas Petroleum, as the sole member of our general partner, may sell or transfer all or part of its ownership interest in our general partner without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner as general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units then outstanding, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.

Limited Call Right

If at any time our general partner and its affiliates hold more than 80% of the limited partner interests of any class then outstanding, our general partner will have the right, but not the obligation,

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which it may assign in whole or in part to any of its affiliates or us, to purchase all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days' notice. The purchase price in the event of this purchase is the greater of:

•: the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date our general partner mails notice of its election to purchase the limited partner interests; and
•: the current market price of the limited partner interests of the class as of the date three days prior to the date that notice is mailed.

As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read "Material Tax Consequences—Disposition of Common Units."

Upon completion of this offering, Abraxas Investments, an affiliate of our general partner, will own 5,131,959 of our units, which will represent approximately 39% of our outstanding common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units, and only one class of limited partner interests will be outstanding.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by non-eligible holders will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Special meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting was called (including outstanding units deemed owned by our general partner), represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities" above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes except such units may be considered to be outstanding for purposes of the withdrawal of our general partner. Common units held in nominee or street name account will be voted by the broker or

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other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the transferred units when such transfer and admission is reflected in our books and records. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Eligible Holders; Redemption

To comply with certain U.S. laws relating to the ownership of interests in oil and gas leases on federal lands, our general partner may require transferees to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify that the unitholder is an Eligible Holder. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a transferee or unitholder, as the case may be, fails upon the request of our general partner to furnish:

•: a transfer application containing the required certification;
•: a re-certification containing the required certification within 30 days after request; or
•: provides a false certification

then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our affiliates, to redeem all but not less than all of the units held by such unitholder 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. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

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Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

(1): our general partner;
(2): any departing general partner;
(3): any person who is or was an affiliate of our general partner or any departing general partner;
(4): any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;
(5): any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner or any affiliate of our general partner or any departing general partner provided that a person will not be an indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodian services; and
(6): any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Payment of Fees and Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or 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. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

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Right to Inspect Our Books and Records

A limited partner can, for a purpose reasonably related to the limited partner's interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, obtain:

•: a current list of the name and last known address of each partner;
•: a copy of our tax returns;
•: information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;
•: copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement;
•: information regarding the status of our business and financial condition; and
•: any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read below "Units Eligible for Future Sale."

UNITS ELIGIBLE FOR FUTURE SALE

Pursuant to our registration rights agreement with the Private Investors, we agreed as soon as practicable after May 25, 2007, to use our commercially reasonable efforts (a) to prepare and file with the SEC a registration statement for (1) this initial public offering or IPO of the common units and (2) a shelf registration statement for the resale of the common units held by the Private Investors and (b) to cause the registration statement of which this prospectus is a part and the shelf registration statement to be declared effective by February 14, 2008. In addition to this offering, we intend to file a shelf registration statement for the resale of a total of 5,651,927 common units held by the Private Investors.

After the sale of the common units offered by this prospectus, Abraxas Investments, an affiliate of our general partner, will own 5,131,959 of our common units, which will represent approximately 39% of our outstanding common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units. The sale of the common units could have an adverse impact on the price of the common units or on any trading market that may develop.

We intend to file a registration statement on Form S-8 under the Securities Act to register 1,136,160 common units issued or reserved for issuance under our long-term incentive plan. Accordingly, common units registered under such registration statement will be available for sale in the open market, unless such common units are subject to vesting restrictions with us or the lock-up restrictions described below in "Underwriting" beginning on page 163. The unit options and restricted

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units that will be granted in conjunction with this offering, which total 284,750 units in the aggregate, all vest over four years.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

•: 1% of the total number of the securities outstanding; or
•: the average weekly reported trading volume of the units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Our partnership agreement does not restrict our ability to issue equity securities ranking junior to the common units at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities" beginning on page 131.

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 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 connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

We, the officers and directors of our general partner, our general partner and its affiliates have agreed not to sell any common units for a period of 180 days from the date of this prospectus. Please read "Underwriting" beginning on page 163, for a description of these lock-up provisions.

MATERIAL TAX CONSEQUENCES

This section describes certain material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States. This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States who are not rendering services

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to us, and has only limited application to corporations, estates, trusts, non-resident aliens, or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs), or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local, and foreign tax consequences particular to him of an investment in us and in the ownership or disposition of our units.

References in this section to "us" or "we" are references to Abraxas Energy and its subsidiaries. This section is not to be construed as a substitute for careful tax planning.

Summary

The statements contained in this section constitute the opinion of our counsel, Jackson Walker L.L.P., regarding the material federal tax consequences to prospective individual investors of the ownership and disposition of our units.

General

The following discussion of the tax aspects of an investment in our units is based on the Internal Revenue Code of 1986, as amended, which we refer to as the Code, existing Treasury Department regulations, which we refer to as the Treasury Regulations, and administrative rulings and judicial decisions interpreting the Code as of the date of this prospectus. Tax legislation may be enacted in the future that would affect us and a unitholder's investment in us. Additionally, the interpretation of existing law and regulations described here may be challenged by the IRS during an audit of our information return. If successful, such a challenge likely would result in adjustment of a unitholder's individual return.

The tax consequences to us and our unitholders are highly dependent on matters of fact that may occur at a future date and are not addressed by our tax counsel. This section represents an expression of general federal income tax consequences of owning our units, insofar as it relates to matters of law and legal conclusions. This section is based on the assumptions and qualifications stated or referenced in this section. It is neither a guarantee of the indicated result nor an undertaking to defend the indicated result should it be challenged by the IRS. No rulings have been or will be requested from the IRS concerning any of the tax matters we describe. Accordingly, you should know that neither the tax summary nor the opinion of our tax counsel assures the intended tax consequences because they are in no way binding on the IRS or any court of law. The IRS or a court may disagree with the following discussion or with any of the positions taken by us for federal income tax reporting purposes, and the opinion of our tax counsel cannot be used by an investor for the purpose of avoiding penalties relating to a substantial understatement of income tax.

For the reasons described in greater detail later, Jackson Walker L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales" beginning on page 149); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees" beginning on page 156) and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Unit Ownership—Section 754 Election" beginning on page 150 and "—Uniformity of Units" beginning on page 157).

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Partnership Status

A partnership is not a taxable entity for federal tax purposes. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner's adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be treated as corporations for federal tax purposes. However, an exception from corporate tax treatment exists with respect to publicly traded partnerships where 90% or more of the partnership's gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation, storage and marketing of natural resources, including oil, gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.

We have entered into hedging arrangements as required by our lender to reduce the impact of oil and gas price volatility on our cash flow from operations. Although it is not currently the case, in the future, depending on future price changes, a significant part of our gross income—well in excess of the prohibited 10%—could be generated from these fixed price commodity swaps. There is no direct published authority on whether income from hedging activities is deemed to be "derived from the exploration…production…or marketing" of oil and gas.

While we regard our hedging arrangement as a forward contract for the sale of a specified amount of our oil and gas production at a specified price at a specified future time, i.e., as income derived from our future production, we have no plans to seek any private ruling from the IRS. Thus, there will be no direct authority on this point. Should the IRS successfully argue that our hedging income is not "derived from the exploration…production…or marketing" of oil and gas, our hedging income would be treated as part of the prohibited 10%, which would mean that we may be treated, for federal income tax purposes, as a corporation instead of a partnership, as discussed below.

Jackson Walker L.L.P. has opined to us what types of income constitute qualifying income, and in analyzing these types, we estimate that less than [ • ]% of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon, and subject to, this estimate, the factual representations made by us and our general partner, and a review of the applicable legal authorities, Jackson Walker L.L.P. is of the opinion that at least 90% of our gross income in our year to date constitutes qualifying income for purposes of the exception under Section 7704 of the Code (the "Qualifying Income Exception").

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate qualifying income under Section 7704 of the Code. Instead, we have relied on the opinion of Jackson Walker L.L.P. that, based upon the Code, the Treasury Regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership for federal tax purposes and our operating subsidiary will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Jackson Walker L.L.P. has relied upon the following factual representations made by us and our general partner:

•: neither we nor our operating subsidiary has elected or will elect to be treated as a corporation for federal tax purposes;

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•: at least 90% of our gross income is income of the type that Jackson Walker L.L.P. has opined is qualifying income within the meaning of Section 7704(d) of the Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we are taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our federal tax return rather than being passed through to the unitholders, and our net income would be taxed to us at federal corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, and taxable capital gain thereafter. Accordingly, treatment as a corporation for federal tax purposes would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Jackson Walker L.L.P.'s opinion that we will be treated as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Abraxas Energy will be treated as partners of Abraxas Energy for federal income tax purposes. The following persons will also be treated as partners of Abraxas Energy:

•: assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and
•: unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units.

As there is no direct or indirect controlling authority addressing assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, Jackson Walker L.L.P.'s opinion does not extend to such persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales" beginning on page 149.

Income, gain, deductions or losses of our partnership would not be attributable to a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by such a

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unitholder would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners of Abraxas Energy for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We, as a partnership, are not subject to federal income taxation. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Items of income, gain, loss and deduction will be allocated for our taxable year ending with or within a unitholder's taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be a gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as "non-recourse liabilities," will be treated as a distribution of cash to that unitholder.

A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our non-recourse liabilities, and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables" and/or substantially appreciated "inventory items," both as defined in the Code, and collectively, "Section 751 Assets," and to the extent of recapture of intangible drilling costs, depletion and depreciation. To the extent a non-pro rata distribution reduces your share of our Section 751 Assets, you will be treated as having been distributed your proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to you. This latter deemed exchange will generally result in your realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) your tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2009, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be [ • ]% or less of the cash distributed with respect to that period. We anticipate that thereafter, the ratio of taxable income allocable to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the initial quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital, and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The

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actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

•: gross income from operations exceeds the amount required to make our expected quarterly distributions on all units, yet we only distribute the expected quarterly distribution on all units; or
•: we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for federal income tax purposes or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our non-recourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our non-recourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the tax basis of the underlying producing properties, by any decreases in his share of our non-recourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our non-recourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss" beginning on page 155.

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder's stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable in the future to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our non-recourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our non-recourse liabilities. Moreover, a unitholder's at risk amount will decrease by the amount of the

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unitholder's depletion deductions and will increase to the extent of the amount by which the unitholder's percentage depletion deductions with respect to our property exceed the unitholder's share of the tax basis of that property.

The at risk limitation applies on an activity-by-activity basis, and in the case of oil and gas properties, each property is treated as a separate activity. Thus, a taxpayer's interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer's oil and gas properties. It is uncertain how this rule is implemented in the case of multiple oil and gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a unitholder's at risk limitation with respect to us. If a unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his units as a whole.

Passive losses in entities that limit a tax payer's liability will be subject to the passive loss limitation rules. The passive loss limitation generally provides that individuals, estates, trusts, and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, only to the extent of the taxpayer's income from those passive activities. The passive loss limitation is especially restrictive for investments in publicly traded partnerships. Consequently, any losses we generate will be available to offset only passive income generated in the future from our own activities and will not be available to offset income from other passive activities or investments, a unitholder's investments in other publicly traded partnerships, or a unitholder's salary or active business income. If we dispose of all or only a part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Notwithstanding whether an oil and gas property is a separate activity, passive losses that are not deductible because they exceed a unitholder's share of income may only be deducted by the unitholder in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after certain other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.

A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:

•: interest on indebtedness properly allocable to property held for investment;
•: our interest expense attributed to portfolio income; and
•: the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a

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publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder's share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts (reduced by certain items described in the Treasury Regulations including all reasonably expected depletion allowances), and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by our general partner and its affiliates, referred to in this discussion as Contributed Property. These "Section 704(c) Allocations" are required to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and the "tax" capital account, credited with the tax basis of Contributed Property. The effect of these allocations to a unitholder purchasing common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. If we issue additional common units or engage in certain other transactions in the future, "Reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to all unitholders, including purchasers of common units in this offering, to account for the difference between "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated, to the extent possible, to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner's share

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of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

•: his relative contributions to us;
•: the interests of all the partners in profits and losses;
•: the interest of all the partners in cash flow; and
•: the rights of all the partners to distributions of capital upon liquidation.

Jackson Walker L.L.P. is of the opinion that, with the exception of the issues described in "—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•: any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
•: any cash distributions received by the unitholder as to those units would be fully taxable; and
•: all of these distributions would appear to be ordinary income.

Because there is no direct authority on the issue related to partnership interests, Jackson Walker L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26.0% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28.0% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest effective U.S. federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than 12 months at the time of disposition.

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Section 754 Election

We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder's inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we will adopt), the Treasury Regulations under Section 743 of the Code require a portion of the Section 743(b) adjustment that is attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read "—Uniformity of Units" beginning on page 157.

Although Jackson Walker L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect judicial or regulatory authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units" beginning on page 157.

A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A tax basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial tax basis reduction. Generally a built-in loss or a tax basis reduction is substantial if it exceeds $250,000.

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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees" beginning on page 156.

Depletion Deductions

Subject to the limitations on deductibility of taxable losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and gas interests. Although the Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder's gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder's daily volume of production of domestic oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and gas production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

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In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder's total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder's total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (1) dividing the unitholder's share of the tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of gas) remaining as of the beginning of the taxable year and (2) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder's share of the total tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our oil and gas interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership and because the availability of the depletion deduction depends upon the unitholder's own factual circumstances, no assurance can be given to a particular unitholder with respect to the availability or extent of percentage depletion deductions to such unitholder for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies, and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An "integrated oil company" is a taxpayer that has economic interests in oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an "independent producer" that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly

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through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of gas) on average for any day during the taxable year or in the retail marketing of oil and gas products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See "—Disposition of Common Units—Recognition of Gain or Loss."

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 6% for qualified production activities income generated in the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder's qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder's share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read "—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses" beginning on page 146.

The amount of a unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder's allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder and its availability is dependent upon each unitholder's own factual circumstances, no assurance can be given to a particular unitholder as to the availability or extent of

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the Section 199 deduction to such unitholder. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Potential Changes to Legislation

If enacted, proposed legislation being reviewed by Congress, which is intended to promote renewable and alternative energy sources, would deny certain oil producers the ability to use the deduction currently offered under Code Section 199 for domestic production activities.

Lease Acquisition Costs

The cost of acquiring oil and gas leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read "—Depletion Deductions" beginning on page 151.

Geophysical Costs

The cost of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation, depletion and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner and its affiliates. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" beginning on page 148.

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss" beginning on page 155.

The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the

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classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our non-recourse liabilities. Because the amount realized includes a unitholder's share of our non-recourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depletion, IDC, and depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, may

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designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•: a short sale;
•: an offsetting notional principal contract; or
•: a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the "Allocation Date." However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations as there is no controlling authority on this issue. Accordingly, Jackson Walker L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. We use this method because it is not administratively feasible to make these allocations on a daily basis. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is required to notify us in

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writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transactions and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties.

Constructive Termination

We will be considered to have been terminated for tax purposes 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. Among other things, a constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in our filing two tax returns (and unitholders' receiving two Schedule K-1s) for one calendar year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election" beginning on page 150.

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the Treasury Regulations under Section 743 of the Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election" beginning on page 150. To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material

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adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss" beginning on page 155.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or "mutual fund," is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a "qualified publicly traded partnership" is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Non-resident aliens and foreign corporations, trusts, or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss, or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss

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and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Jackson Walker L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of his return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. Our partnership agreement names Abraxas General Partner, LLC as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;

•

whether the beneficial owner is:

•: a person that is not a U.S. person;
•: a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or
•: a tax-exempt entity;

•

the amount and description of units held, acquired or transferred for the beneficial owner; and

•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

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Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•: for which there is, or was, "substantial authority"; or
•: as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists relating to such a transaction, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions

If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses in excess of $2 million. Please read "—Information Returns and Audit Procedures" above, beginning on page 158.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

•: accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-related Penalties,"

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•: for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and
•: in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or conduct business in Texas. We may also own property or conduct business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we conduct business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Unit Ownership—Entity-Level Collections" beginning on page 148. Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Jackson Walker L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN OUR PARTNERSHIP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Code. For these purposes, the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

•: whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
•: whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and
•: whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Code prohibits employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Code with respect to the plan.

In addition to considering whether the purchase of units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:

(1): the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;
(2): the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or
(3): there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above and may also satisfy the requirements in (3) above.

Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Subject to the terms and conditions of the underwriting agreement between us, the selling unitholder and the underwriters, the underwriters have agreed severally to purchase from us and the selling unitholder the following number of common units at the offering price less the underwriting discount set forth on the cover page of this prospectus.

Underwriters			Number of Common Units
A.G. Edwards & Sons, Inc.
RBC Capital Markets Corporation
C.K. Cooper & Company
	Total

The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions and that the underwriters will purchase all such common units if any of the common units are purchased. The underwriters are obligated to take and pay for all of the common units offered by this prospectus, other than those covered by the over-allotment option described below, if any are taken.

The underwriters have advised us and the selling unitholder that they propose to offer the common units to the public at the offering price set forth on the cover page of this prospectus and to certain dealers at such price less a selling concession not in excess of $ per common unit. The underwriters may allow, and such dealers may re-allow, a concession not in excess of $ per common unit to certain other dealers. After the offering, the offering price and other selling terms may be changed by the underwriters, but any such changes will not affect the net proceeds to be received by us and the selling unitholder in the offering.

Option to Purchase Additional Common Units. Pursuant to the underwriting agreement, we have granted to the underwriters an option, exercisable in whole or in part for 30 days after the date of this prospectus, to purchase up to 352,572 additional common units at the offering price, less the underwriting discount set forth on the cover page of this prospectus, solely to cover over-allotments.

To the extent the underwriters exercise such over-allotment option, the underwriters will become obligated, subject to certain conditions, to purchase approximately the same percentage of such additional units as the number set forth next to such underwriter's name in the preceding table bears to the total number of units in the table, and we will be obligated, pursuant to the over-allotment option, to sell such units to the underwriters.

Lock-up Agreements. We, our general partner, Abraxas Petroleum and the directors and executive officers of our general partner have agreed that during the 180 days after the date of this prospectus, we and they will not, without the prior written consent of A.G. Edwards & Sons, Inc., directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units within the time period of the lock-up, other than (1) pursuant to employee benefit plans as in existence as of the date of this prospectus, (2) to affiliates, (3) in connection with accretive acquisitions of assets or businesses in which common units are issued as consideration, or (4) in connection with the over-allotment option; provided, however, any such recipient of common units furnish to A.G. Edwards & Sons, Inc., a letter agreeing to be bound by these provisions for the remainder of the 180-day period. Notwithstanding the foregoing, if (1) during the last 17 days of the 180-day period, we issue an earnings release or material news or a material event relating to us occurs; or (2) prior to the expiration of the 180-day restricted period, we

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announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, the "lock-up" restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event. A.G. Edwards & Sons, Inc. may, in its sole discretion, allow any of these parties to offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units prior to the expiration of such 180-day period in whole or in part at anytime without notice. A.G. Edwards & Sons, Inc. has informed us that in the event that consent to a waiver of these restrictions is requested by us or any other person, A.G. Edwards & Sons, Inc., in deciding whether to grant its consent, will consider the unitholder's reasons for requesting the release, the number of units for which the release is being requested and market conditions at the time of the request for such release. However, A.G. Edwards & Sons, Inc. has informed us that as of the date of this prospectus there are no agreements between A.G. Edwards & Sons, Inc. and any party that would allow such party to transfer any common units, nor does it have any intention of releasing any of the common units subject to the lock-up agreements prior to the expiration of the lock-up period at this time.

The selling unitholder and the other Private Investors have agreed to restrictions on their ability to sell or otherwise dispose of their units similar to those described above for a period of 90 and 60 days, respectively, beginning on the date of this prospectus, subject to similar extensions as those for the 180-day period described above.

IPO Pricing. Prior to this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiation between us and the underwriters. The principal factors that will be considered in determining the public offering price include the following:

•: the information set forth in this prospectus and otherwise available to the underwriters;
•: market conditions for initial public offerings;
•: the history and the prospects for the industry in which we compete;
•: the ability of our management;
•: our prospects for future earnings;
•: the present state of our development and our current financial condition;
•: the general condition of the securities markets at the time of this offering; and
•: the recent market prices of, and the demand for, publicly traded common units of generally comparable entities.

Discounts and Commissions. The following table summarizes the discounts that we will pay to the underwriters in connection with the offering, excluding a financial advisory fee for evaluation, analysis and structuring of our partnership and this offering. These amounts assume both no exercise and full exercise of the underwriters' over-allotment option to purchase additional common units.

			Total
		Per Unit	No Exercise	Full Exercise
Underwriting discounts paid by us		$	$	$
Underwriting discounts paid by selling unitholder		$

	Total		$	$

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We estimate that total expenses of this offering, all of which will be paid by us, other than underwriting discounts and commissions, will be approximately $0.8 million.

Indemnification. We, our general partner, Abraxas Petroleum, and the selling unitholder have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments that may be required with respect to these liabilities.

Stabilization. Until the distribution of the common units is completed, rules of the SEC may limit the ability of the underwriters and certain selling group members to bid for and purchase the common units. As an exception to these rules, the underwriters are permitted to engage in certain transactions that stabilize, maintain or otherwise affect the price of the common units.

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate-covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.
•: Syndicate-covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, resulting in a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
•: Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate-covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters' purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the American Stock Exchange or otherwise.

The underwriters will deliver a prospectus to all purchasers of common units in the short sales. The purchasers of common units in short sales are entitled to the same remedies under the federal securities laws as any other purchaser of common units covered by this prospectus.

The underwriters are not obligated to engage in any of the transactions described above. If they do engage in any of these transactions, they may discontinue them at any time.

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Directed Unit Program. At our request, the underwriters are reserving up to 100,000 common units for sale at the initial public offering price to directors, officers, employees, family members of directors, officers and employees, business associates and other third parties through a directed unit program. We do not know if such persons will choose to purchase all or any portion of the reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Any common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus.

Neither we nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Because the Financial Industry Regulatory Association views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

No sales to accounts over which any underwriter exercises discretionary authority may be made without the prior written approval of the customer.

Financial Advisory Services Fee. The underwriters will earn 0.5% of the gross proceeds of the offering, including any exercise of the underwriters' over-allotment option to purchase additional common units, for financial advisory services rendered to us. The Financial Industry Regulatory Association considers this fee to represent compensation earned in connection with this offering.

Electronic Prospectuses. A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters participating in this offering. Other than the prospectus in electronic format, the information on any such website, or accessible through such website, is not part of this prospectus.

Conflicts/Affiliates. Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us. They have received customary fees and commissions for these transactions.

An affiliate of RBC Capital Markets Corporation, an underwriter for this offering, is a lender under our credit facility and will be fully repaid with a portion of the net proceeds from this offering. As a result, RBC Capital Markets Corporation will receive more than 10% of the proceeds from this offering. However, because this offering is being made in compliance with Rule 2810 of the NASD Conduct Rules, a Qualified Independent Underwriter is not required.

We have applied to list our common units on the American Stock Exchange under the symbol "ABE".

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Jackson Walker L.L.P., San Antonio, Texas. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements and management's report on the effectiveness of internal control over financial reporting of Abraxas Petroleum Corporation and the balance sheets of Abraxas

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Energy Partners, L.P. and Abraxas General Partner, LLC, included in this Prospectus and in the Registration Statement have been audited by BDO Seidman, LLP, an independent registered public accounting firm, to the extent and for the periods set forth in their reports appearing elsewhere herein and in the Registration Statement, and are included in reliance upon such reports given upon the authority of said firm as experts in auditing and accounting.

The information appearing in this prospectus concerning estimates of our oil and gas reserves as of June 30, 2007 was prepared by DeGolyer and MacNaughton, an independent engineering firm, with respect to our properties and has been included herein upon the authority of this firm as an expert.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-l regarding the units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:

•: the volatility of oil and gas prices;
•: discovery, estimation, development and replacement of oil and gas reserves;
•: cash flow, liquidity and financial position;
•: business and financial strategy;
•: amount, nature and timing of capital expenditures, including future development costs;
•: availability and terms of capital;
•: timing and amount of future production of oil and gas;
•: availability of drilling and production equipment;
•: operating costs and other expenses;
•: prospect development and property acquisitions;
•: marketing of oil and gas;
•: hedging arrangements;
•: competition in the oil and gas industry;
•: the impact of weather and the occurrence of natural disasters such as fires, floods, earthquakes and other catastrophic events and natural disasters;
•: governmental regulation of the oil and gas industry;
•: developments in oil-producing and gas-producing countries; and
•: strategic plans, expectations and objectives for future operations.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the "Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business" and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as "may," "could," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "continue," the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by us. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the "Risk Factors" section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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INDEX TO FINANCIAL STATEMENTS


Abraxas Energy Partners, L.P.
Unaudited Pro Forma Consolidated Financial Statements Basis of Presentation
Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2006
Unaudited Pro Forma Consolidated Statement of Operations for the six months ended June 30, 2007
Notes to Unaudited Pro Forma Financial Statements
Abraxas Petroleum Corporation
Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Consolidated Balance Sheets at December 31, 2006 and 2005
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Stockholders' Deficit for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Cash Flow for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Other Comprehensive Income for the years ended December 31, 2006, 2005 and 2004
Notes to Consolidated Financial Statements
Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets at June 30, 2007 (unaudited) and December 31, 2006
Condensed Consolidated Statements of Operations—Six Months Ended June 30, 2007 and 2006 (unaudited)
Condensed Consolidated Statements of Cash Flow—Six Months Ended June 30, 2007 and 2006 (unaudited)
Notes to Condensed Consolidated Financial Statements
Abraxas Energy Partners, L.P.
Report of Independent Registered Public Accounting Firm
Balance Sheet as of May 18, 2007
Notes to the Balance Sheet
Condensed Consolidated Balance Sheet at June 30, 2007 (unaudited)
Condensed Consolidated Statement of Operations—Period From Formation Through June 30, 2007 (unaudited)
Condensed Consolidated Statements of Cash Flow—Period From Formation Through June 30, 2007 (unaudited)
Notes to Condensed Consolidated Financial Statements
Abraxas General Partner, LLC
Report of Independent Registered Public Accounting Firm
Balance Sheet as of May 18, 2007
Notes to the Balance Sheet

F-1

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The following unaudited pro forma consolidated financial information is derived from the historical financial statements of Abraxas Petroleum, and reflects (1) the Formation Transactions described below, and (2) the completion of this offering and the use of proceeds from this offering as described below.

The Unaudited Pro Forma Consolidated Statements of Operations for the year ended December 31, 2006 and for the six month period ended June 30, 2007 have been prepared assuming that the Formation Transactions and this offering were consummated on January 1, 2006.

The Unaudited Pro Forma Consolidated Financial Information should be read in conjunction with the notes thereto, as well as the Consolidated Financial Statements of Abraxas Petroleum and the notes thereto.

The Unaudited Pro Forma Consolidated Financial Information is not indicative of our financial position or the results of operations that might have actually occurred if the Formation Transactions and the completion of this offering occurred at the dates presented, or of our future financial position or results of operations. In addition, future results may vary significantly from the results reflected in such statements due to normal oil and gas production declines, reductions in prices paid for oil and gas, future acquisitions and other factors.

Formation Transactions

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

•: Abraxas Petroleum contributed our 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, 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.

We intend to use the net proceeds from this offering to repay in full the indebtedness outstanding under our credit facility, and to fund future capital expenditures (including acquisition, exploitation and development costs), working capital and for other general partnership purposes.

F-2

ABRAXAS ENERGY PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2006

		Abraxas Petroleum— Historical			Pro Forma Adjustments related to Formation Transactions			Pro Forma Abraxas Energy After Formation Transactions		Pro Forma Adjustments related to this Offering			Pro Forma Abraxas Energy After this Offering
		(In thousands)
Revenues:
	Oil and gas production revenues	$	50,094		$	(8,074	)(a)	$	42,020	$	—		$	42,020
	Realized gain on hedging transactions		—			112			112		—			112
	Unrealized gain on hedging transactions		—			71	(a)		71		—			71
	Rig revenues		1,613			(1,613	)(a)		—		—			—
	Other		16			(16	)(a)		—		—			—

			51,723			(9,520	)		42,203		—			42,203
Operating costs and expenses:
	Lease operating and production taxes		11,776			(3,084	)(a)		8,692		—			8,692
	Depreciation, depletion, and amortization		14,393			(1,897	)(a)		12,496		—			12,496
	Rig operations		819			(819	)(a)		—		—			—
	General and administrative		4,162			(2,662	)(b)		1,500		—			1,500
	Stock-based compensation		998			(998	)		—		983	(c)		983	(c)

			32,148			(9,460	)		22,688		983			23,671

Operating income			19,575			(60	)		19,515		(983	)		18,532
Other (income) expense:
	Interest income		(29	)		29			—		—			—
	Interest expense		16,767			(14,198	)(d)		2,569		(2,496	)(e)		73
	Amortization of deferred financing fees		1,591			(1,392	)(f)		199		—			199

			18,329			(15,561	)		2,768		(2,496	)		272
Income before tax			1,246			15,501			16,747		1,513			18,260
Income tax			—			—			—		—			—

Net income		$	1,246		$	15,501		$	16,747	$	1,513		$	18,260

Net income per common share/unit—basic		$	0.03					$	1.47				$	1.36

Net income per common share/unit—diluted		$	0.03					$	1.47				$	1.36

Weighted average shares/units outstanding—basic			42,578,584						11,361,599					13,449,150

Weighted average shares/units outstanding—diluted			43,862,381						11,361,599					13,449,150

Please refer to Note 1 of the Notes to Unaudited Consolidated Pro Forma Financial Statements.

F-3

ABRAXAS ENERGY PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2007

		Abraxas Petroleum— Historical			Pro Forma Adjustments related to Formation Transactions			Pro Forma Abraxas Energy After Formation Transactions			Pro Forma Adjustments related to this Offering			Pro Forma Abraxas Energy After this Offering
		(In thousands)
Revenues:
	Oil and gas production revenues	$	24,192		$	(4,011	)(a)	$	20,181		$	—		$	20,181
	Realized gain (loss) on hedging transactions		(126	)		55	(a)		(71	)		—			(71	)
	Unrealized gain (loss) on hedging transactions		1,816			(30	)(a)		1,786			—			1,786
	Rig revenues		639			(639	)(a)		—			—			—
	Other		3			(3	)(a)		—			—			—

			26,524			(4,628	)		21,896			—			21,896
Operating costs and expenses:
	Lease operating and production taxes		6,025			(1,359	)(a)		4,666			—			4,666
	Depreciation, depletion, and amortization		6,756			(1,018	)(a)		5,738			—			5,738
	Rig operations		373			(373	)(a)		—			—			—
	General and administrative		2,039			(1,289	)(b)		750			—			750
	Stock-based compensation		544			(544	)		—			492	(c)		492	(c)

			15,737			(4,583	)		11,154			492			11,646

Operating income			10,787			(45	)		10,742			(492	)		10,250
Other (income) expense:
	Interest income		(67	)		67			—			—			—
	Interest expense		6,935			(5,665	)(d)		1,270			(1,239	)(e)		31
	Amortization of deferred financing fees		547			(447	)(f)		100			—			100
	Loss on debt extinguishment		6,455			—			6,455			—			6,455
	Gain on sale of assets		(58,498	)		58,498	(g)		—			—		&n

Abraxas Energy Partners LP S-1/A