Index to Financial Statements

As filed with the Securities and Exchange Commission on May 15, 2009

Registration No. 333-144537

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 11

Form S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

ABRAXAS ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

1311

26-0144848

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification Number)

18803 Meisner Drive

San Antonio, Texas 78258

(210) 490-4788

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



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

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

Copies to:

Steven R. Jacobs

Jackson Walker L.L.P.

112 E. Pecan Street, Suite 2400

San Antonio, Texas 78205

(210) 978-7727

Elise F. Green

Jackson Walker L.L.P.

100 Congress Avenue, Suite 1100

Austin, Texas 78701

(512) 236-2000

Harvey J. Kesner

Sichenzia Ross Friedman Ference LLP

61 Broadway, 32^nd Floor

New York, NY 10006

(212) 930-9700

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. x

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer x

(Do not check if a
smaller reporting company)

Smaller reporting company ¨

CALCULATION OF REGISTRATION FEE



Title of each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Aggregate Offering Price (1)(2)(3)	Amount of Registration Fee
Common Units representing limited partner interests	4,600,000(1)	$27,600,000	$1,540.08
Redeemable Warrants	2,300,000(3)	—	—(4)
Common Units representing limited partner interests underlying the Redeemable Warrants	2,300,000(3)(5)	$13,800,000	$962.55(6)
Total Registration Fee.			$2,502.63(7)

(1)	Includes common units issuable upon exercise of the underwriter’s option to purchase additional common units.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

(3)	Includes redeemable warrants issuable upon exercise of the underwriter’s option to purchase additional redeemable warrants.

(4)	No fee pursuant to Rule 457(g).

(5)	Pursuant to Rule 416, there are being registered such indeterminable additional securities as may be issued as a result of the anti-dilution provisions.

(6)	Calculated pursuant to Rule 457(g).

(7)	The registrant previously paid a registration fee of $3,257.71 with prior filings of this registration statement at the then applicable filing rate.

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.

Index to Financial Statements

SUBJECT TO COMPLETION, DATED MAY 15, 2009

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

PRELIMINARY PROSPECTUS

4,000,000 Common Units

2,000,000 Redeemable Warrants to Purchase Common Units

LOGO

Abraxas Energy Partners, L.P. is a limited partnership formed in May 2007 by Abraxas Petroleum Corporation. This is an initial public offering of our securities. We are offering 4,000,000 common units, representing limited partner interests, and 2,000,000 redeemable warrants. For each common unit purchased, the holder will receive one half (1/2) of one redeemable warrant. Each whole redeemable warrant will entitle the holder to purchase one common unit at a price of [$ ], provided that there is an effective registration statement covering the common units underlying the redeemable warrants at the time of exercise or there is an exemption from registration available. The redeemable warrants will expire five years from the date of this prospectus, or earlier upon redemption. As part of this offering, Abraxas Petroleum Corporation, one of our principal unitholders and the parent corporation of our general partner, or its designee, has agreed to purchase from us up to 600,000 common units and 300,000 redeemable warrants offered hereby that are not sold by the underwriters. For more information, please read “Certain Relationships and Related Party Transactions—Standby Purchase Agreement” and “Underwriting.” We expect the initial public offering price to be between $4.00 and $6.00 per common unit. Our common units have been approved for listing on the NASDAQ Stock Market under the symbol “AXLP” and we have applied for the quotation of our redeemable warrants on the NASDAQ Stock Market under the symbol “AXLPW.”

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

These risks include the following:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

You will experience immediate and substantial dilution of $4.59 in tangible net book value per common unit.

•

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

•

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

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

PRICE $ PER COMMON UNIT


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

We have granted the underwriters a 45-day option to purchase up to an additional 600,000 common units and 300,000 redeemable warrants from us on the same terms and conditions set forth above to cover over-allotments. Rodman & Renshaw, LLC, on behalf of the underwriters, expects to deliver the common units and redeemable warrants on or about , 2009.

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

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

The date of this prospectus is , 2009

Index to Financial Statements

LOGO

Index to Financial Statements

TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
ABRAXAS ENERGY PARTNERS, L.P.		1
Overview		1
Our Properties		2
Formation Transactions		3
Business Strategy		4
Competitive Strengths		4
Hedging		4
Summary of Risk Factors		5
Our Relationship with Abraxas Petroleum		7
Summary of Conflicts of Interest and Fiduciary Duties		8
Principal Executive Offices and Internet Address		8
Partnership Structure		9
The Offering		11
Summary Historical and Pro Forma Financial and Operating Data		15
Non-GAAP Financial Measures		18
RISK FACTORS		20
Risks Related to Our Business		20
Risks Inherent in an Investment in Us		32
Tax Risks to Common Unit Holders and Redeemable Warrant Holders		38
USE OF PROCEEDS		42
CAPITALIZATION		43
DILUTION		44
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		46
Our Cash Distribution Policy		46
Our Initial Distribution Rate		48
Pro Forma Financial Information and Estimated Cash Available for Distributions		50
Assumptions and Considerations		55
How We Make Cash Distributions		62
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA		64
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		67
Overview		67
Basis of Presentation		67
How We Evaluate Our Operations		68
Outlook		72
Factors Affecting Comparability of Future Results		73
Results of Operations		75
Liquidity and Capital Resources		81
Critical Accounting Policies		87
Recent Accounting Pronouncements		90
Quantitative and Qualitative Disclosures about Market Risk		92
BUSINESS		95
General		95
Our Properties		95
Business Strategy		99
Competitive Strengths		100
Acreage		101

Index to Financial Statements


Productive Wells		101
Reserves Information		101
Oil and Gas Production and Sales Prices		102
Drilling Activities		103
Hedging Activity		103
Markets and Customers		103
Our Relationship with Abraxas Petroleum		104
Well Operations		104
Regulation of Oil and Gas Activities		105
Environmental Matters		108
Title to Properties		112
Competition		112
Employees		112
Office Facilities		112
Legal Proceedings		113
MANAGEMENT		114
Management of Abraxas Energy		114
Directors and Executive Officers of Our General Partner		115
Payment of Fees and Reimbursement of Expenses		117
Executive Compensation		117
Compensation Discussion and Analysis		119
Compensation of Directors		121
Long-Term Incentive Plan		122
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		126
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		129
Distributions and Payments to Our General Partner and Its Affiliates		129
Summary of Formation Transaction Documents		130
Standby Purchase Agreement		134
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		135
Conflicts of Interest		135
Fiduciary Duties		137
DESCRIPTION OF THE COMMON UNITS AND THE REDEEMABLE WARRANTS		140
The Common Units		140
The Redeemable Warrants		140
Transfer Agent and Registrar		141
Transfer of Common Units and Redeemable Warrants		141
THE PARTNERSHIP AGREEMENT		143
Organization and Duration		143
Purpose		143
Power of Attorney		143
Capital Contributions		144
Limited Liability		144
Voting Rights		145
Issuance of Additional Securities		146
Amendments to Our Partnership Agreement		147
Prohibited Amendments		147
No Unitholder Approval		147
Opinion of Counsel and Unitholder Approval		148
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		148
Termination or Dissolution		149
Liquidation and Distribution of Proceeds		149
Withdrawal or Removal of Our General Partner		150

Index to Financial Statements


Transfer of General Partner Interest		150
Transfer of Ownership Interests in Our General Partner		151
Change of Management Provisions		151
Limited Call Right		151
Meetings; Voting		151
Status as Limited Partner		152
Non-Eligible Holders; Redemption		152
Indemnification		153
Payment of Fees and Reimbursement of Expenses		153
Books and Reports		153
Right to Inspect Our Books and Records		154
Registration Rights		154
UNITS ELIGIBLE FOR FUTURE SALE		154
MATERIAL TAX CONSEQUENCES		157
Summary		157
General		157
Purchase Price Allocation Issues		158
Partnership Status		158
Limited Partner Status		160
Tax Consequences of Unit Ownership		160
Tax Consequences of an Investment in the Redeemable Warrants		166
Tax Treatment of Operations		167
Disposition of Common Units		171
Uniformity of Units		173
Tax-Exempt Organizations and Other Investors		174
Administrative Matters		174
State, Local, Foreign and Other Tax Considerations		176
INVESTMENT IN OUR PARTNERSHIP BY EMPLOYEE BENEFIT PLANS		178
UNDERWRITING		179
VALIDITY OF THE SECURITIES		183
EXPERTS		183
WHERE YOU CAN FIND MORE INFORMATION		184
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		184
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A SECOND AMENDED AND RESTATED LIMITED PARTNERSHIP AGREEMENT OF ABRAXAS ENERGY PARTNERS, L.P.		A-1
APPENDIX B GLOSSARY OF CERTAIN TERMS		B-1
APPENDIX C APPLICATION FOR TRANSFER OF COMMON UNITS		C-1
APPENDIX D RESERVE ENGINEER’S LETTER		D-1

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

iii

Index to Financial Statements

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

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

Index to Financial Statements

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 $5.00 per common unit, that the underwriters’ over-allotment option to purchase additional common units and redeemable warrants is not exercised, that none of the redeemable warrants are exercised and that Abraxas Petroleum does not purchase any common units in this offering. You should read “Risk Factors” beginning on page 20 for information about important factors that you should consider carefully before buying our common units and redeemable warrants. Our reserve information is derived from a reserve report prepared by DeGolyer and MacNaughton, an independent engineering firm, for approximately 93% of the standardized measure of our properties. Reserve estimates for our remaining properties were prepared by Abraxas Petroleum personnel. The properties included in the reserve report prepared by DeGolyer and MacNaughton were selected by us. For more information, see “Business—Reserves Information.” Natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil.

ABRAXAS ENERGY PARTNERS, L.P.

Overview

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

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

Index to Financial Statements

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


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

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

(1)

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

Our Properties

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

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

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

Our Rocky Mountain properties consist of the following:

•

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

•

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

Our Mid-Continent properties consist of the following:

•

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

Index to Financial Statements

•

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

•

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

Our Permian Basin properties consist of the following:

•

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

•

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

•

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

Our Gulf Coast properties consist of the following:

•

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

•

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

•

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

Formation Transactions

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

•

Abraxas Petroleum contributed properties to Abraxas Operating;

•

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

•

we borrowed $35.0 million under our credit facility; and

•

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

Index to Financial Statements

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

•

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

•

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

•

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

•

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

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

Business Strategy

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

•

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

•

Making sufficient capital expenditures to maintain our current production levels over the long-term;

•

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

•

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

•

Reducing cash flow volatility through commodity price hedging.

Competitive Strengths

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

•

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

•

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

•

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

•

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

•

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

•

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

Hedging

We are currently a party to derivative contracts, which we sometimes refer to as hedging arrangements, and we intend to enter into hedging arrangements in the future, to reduce the impact of oil and gas price volatility on our cash flow from operations. At May 8, 2009 and continuing through December 2012, we had NYMEX-based fixed price commodity swaps covering approximately 80% (85% for 2009-2011 and 60% for 2012) of our

Index to Financial Statements

estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $81.08 per barrel of oil and $8.14 per MMbtu of gas which are significantly higher than market prices on May 8, 2009 of $58.63 per barrel of oil and $4.31 per MMbtu of gas. By removing a significant portion of price volatility from our oil and gas production for the next three years, we believe we have mitigated, but not eliminated, the potential effects of changing oil and gas prices on our cash flow from operations for those periods. Because the prices at which we have hedged our production are significantly higher than current prices, we will realize greater cash flow on the portion of production that we have hedged as a result of these higher contract prices than we would have without these arrangements. Conversely, we will sustain realized and unrealized losses on our derivative contracts if prevailing market prices for our oil and gas are higher than our contract prices. We have elected out of hedge accounting as prescribed by applicable accounting rules. For more information on our hedging arrangements, please read “Management’s Discussion & Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives” and “—Quantitative and Qualitative Disclosures about Market Risk—Hedging Activity and Sensitivity.” Please read also “Risk Factors—Risks Related to Our Business” for a discussion of certain risk factors relating to our hedging activities.

Summary of Risk Factors

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

Risks Related to Our Business

•

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

•

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

•

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

•

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

•

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

•

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

•

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

Index to Financial Statements

•

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

•

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

•

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

•

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

Risks Inherent in an Investment in Us

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

You will experience immediate and substantial dilution of $4.59 in tangible net book value per common unit.

•

You will not be able to exercise your redeemable warrants if we do not have an effective registration statement in place when you desire to do so.

•

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

•

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

Index to Financial Statements

•

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

Tax Risks to Common Unit Holders and Redeemable Warrant Holders

•

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

•

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

•

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

•

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

•

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

•

We will treat each purchaser of 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.

•

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

•

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

•

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

Our Relationship with Abraxas Petroleum

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

Upon the completion of this offering, Abraxas Petroleum will beneficially own a 2% general partner interest and a 33.9% limited partner interest in us, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants and that Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering. We have entered into a standby purchase agreement with

Index to Financial Statements

Abraxas Petroleum under which Abraxas Petroleum, or its designee, has agreed to purchase from us up to 600,000 common units (and 300,000 redeemable warrants) offered hereby that are not sold by the underwriters. For more information, please read “Certain Relationships and Related Party Transactions—Standby Purchase Agreement” and “Underwriting.” We have entered into an omnibus agreement with Abraxas Petroleum and our general partner regarding certain payment and indemnification matters, including the payment of plugging and abandonment costs and environmental liabilities, and an operating agreement regarding the operation of our properties. For more information, please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “—Operating Agreement.” While we believe that our relationship with Abraxas Petroleum is a significant competitive strength, it is also a source of potential conflicts. For example, Abraxas Petroleum is not prohibited from competing with us and may acquire or dispose of assets in the future without any obligation to offer us the opportunity to purchase those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

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

Summary of Conflicts of Interest and Fiduciary Duties

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

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

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

Principal Executive Offices and Internet Address

Our principal executive offices are located at 18803 Meisner Drive, San Antonio, Texas 78258 and our telephone number is (210) 490-4788. Our website will be located at www.abraxasenergypartners.com.

Index to Financial Statements

Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

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

PARTNERSHIP STRUCTURE

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


	Assumes no exercise of the underwriters’ over- allotment option and that Abraxas Petroleum does not purchase any units in this offering(1)			Assumes no exercise of the underwriters’ over- allotment option and that Abraxas Petroleum purchases all of the common units it has agreed to purchase in this offering(1)			Assumes full exercise of the underwriters’ over- allotment option and that Abraxas Petroleum does not purchase units in this offering(1)
	Number of Units	Percentage		Number of Units	Percentage		Number of Units	Percentage
Public common units	4,000,000	25.4	%	3,400,000	21.6	%	4,600,000	28.1	%
Private Investors’ common units	6,059,651	38.4	%	6,059,651	38.4	%	6,059,651	37.0	%
Abraxas Petroleum and affiliates:
Common units	5,350,598	33.9	%	5,950,598	37.7	%	5,350,598	32.6	%
General Partner units	316,617	2.0	%	316,617	2.0	%	328,862	2.0	%
Restricted common units	52,000	0.3	%	52,000	0.3	%	52,000	0.3	%

Total	15,778,866	100	%	15,778,866	100	%	16,391,111	100	%

(1)	Does not include the common units underlying the redeemable warrants.

Index to Financial Statements

The following diagram of our organizational structure (a) assumes (i) the sale of all the common units offered hereby, (ii) the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants, (iii) Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering, and (b) does not include the common units underlying the redeemable warrants.

LOGO

(1)	In connection with this offering, our general partner will be purchasing 89,385 additional general partner units, for a total of 316,617 general partner units, to maintain a 2% general partner interest in us.

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

Index to Financial Statements

THE OFFERING

Securities offered to the public

4,000,000 common units and 2,000,000 redeemable warrants, or 4,600,000 common units and 2,300,000 redeemable warrants if the underwriters exercise their over-allotment option to purchase additional common units and redeemable warrants in full. As part of this offering, Abraxas Petroleum has agreed to purchase from us up to 600,000 common units and 300,000 redeemable warrants offered hereby that are not sold by the underwriters. For more information, please read “Certain Relationships and Related Party Transactions—Standby Purchase Agreement” and “Underwriting.”

Units outstanding after this offering

15,462,249 common units, representing a 98% limited partner interest in us. Our general partner will own 316,617 general partner units, representing a 2% general partner interest in us after making a proportionate capital contribution of $0.4 million. Our total units outstanding after this offering will be 15,778,866 units (17,778,866) units if all of the redeemable warrants are exercised).

If the underwriters exercise their over-allotment option to purchase additional units in full, there will be 16,062,249 common units and 328,862 general partner units, or a total of 16,391,111 units outstanding (18,691,111 units if all of the redeemable warrants are exercised).

Redeemable Warrants

Exercisability:

Each redeemable warrant is exercisable to purchase one common unit. Redeemable warrants may only be exercised for cash.

Exercise price:

$[ ]

Exercise period:

Each redeemable warrant will become exercisable on the date of this prospectus. The warrants will expire at 5:00 p.m., New York time, on , 2014 or earlier upon redemption.

Redemption:

We may redeem the outstanding warrants:

•

in whole but not in part;

•

at a price of $0.01 per warrant;

•

upon a minimum of 30 days’ prior written notice of redemption; and

•

if the last sale price of our common units equals or exceeds $[ ] per common unit for any 20 trading days within a 30 trading day period ending three business days before we deliver a notice of redemption.

Rights:

Redeemable warrant holders do not have the rights or privileges of holders of common units, including voting rights, until they exercise their redeemable warrants and receive common units. After the issuance of common units upon exercise of the redeemable warrants, each holder will be entitled to one vote for each common unit held of record on all matters to be voted on by unitholders.

Index to Financial Statements

Use of proceeds

We intend to use the net proceeds of approximately $18.5 million from this offering, after deducting approximately $1.9 million for underwriting discounts and offering expenses to be paid with proceeds from this offering, together with our general partner’s proportionate capital contribution of $0.4 million and any proceeds from the exercise of the underwriters’ over-allotment option to partially repay the indebtedness outstanding under our subordinated credit facility.

At May 8, 2009, the principal balance outstanding under our subordinated credit facility was $40.0 million. The maturity date of our subordinated credit facility is July 1, 2009. We intend to re-finance this indebtedness prior to its scheduled maturity; however, there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial advisor to assist us in this re-financing.

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

Cash distributions

We expect to make an initial quarterly distribution of $0.25 per unit ($1.00 per unit on an annualized basis) on all of our units after completion of this offering, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions—Our Initial Distribution Rate.”

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

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

The amount of pro forma available cash generated during the year ended December 31, 2008 and during the twelve months ended March 31, 2009 would have been sufficient to allow us to pay the full initial quarterly distribution for four quarters on all of our units. For a

Index to Financial Statements

calculation of our ability to make distributions to unitholders based on our pro forma results for 2008, please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Consolidated Available Cash for the Year Ended December 31, 2008 and the Twelve Months Ended March 31, 2009.”

We believe that, based on estimates contained in the assumptions listed under the caption “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Month Period Ending June 30, 2010” and “—Assumptions and Considerations,” we will have sufficient cash available for distribution to pay the initial quarterly distribution for the four quarters ending June 30, 2010 at an initial quarterly distribution rate of $0.25 per unit ($1.00 per unit on an annualized basis) on all of our units.

Issuance of additional units

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

Limited voting rights

Our general partner will manage our business. Unlike the stockholders of a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/3% of the outstanding common units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of approximately 34.9% of our common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants and that Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering. This will give Abraxas Petroleum the ability to prevent our general partner’s involuntary removal. Please read “The Partnership Agreement—Voting Rights.”

Limited call right

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

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2011, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.00 per unit, we estimate that your average allocable federal taxable income per year

Index to Financial Statements

will be no more than $0.20 per unit. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

Material tax consequences

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

Agreement to be bound by the Partnership Agreement

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

Exchange listing and trading symbol

Our common units have been approved for listing on the NASDAQ Stock Market under the symbol “AXLP” and we have applied for the quotation of our redeemable warrants on the NASDAQ Stock Market under the symbol “AXLPW.”

Eligible Holders and redemption

We currently own interests in federal leases, which may require unitholders or their transferees to certify or re-certify to us their status as Eligible Holders. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. If a unitholder or transferee of a unitholder, as the case may be, does not properly complete a certification or re-certification as to its status as an Eligible Holder, or if such unitholder or transferee is not an Eligible Holder, such person will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we have the right to redeem such units at a price which is equal to the average daily closing price per common unit for the 20 consecutive trading days prior to the date of determination of the price at which such units would be redeemed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Description of the Common Units and Redeemable Warrants—Transfer of Common Units” and “The Partnership Agreement—Non-Eligible Holders; Redemption.”

Index to Financial Statements

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows summary historical financial and operating data of Abraxas Petroleum and our pro forma and historical financial data for the periods and as of the dates indicated. The summary historical financial data of Abraxas Petroleum as of December 31, 2006 and for the year ended December 31, 2006 and for the period from January 1 to May 24, 2007 and the summary historical financial data of Abraxas Energy as of December 31, 2007 and 2008 and for the period from May 25 to December 31, 2007 and for the year ended December 31, 2008 are derived from the audited consolidated financial statements included elsewhere in this prospectus. The summary historical financial data of Abraxas Energy as of March 31, 2009 and for the three months ended March 31, 2009 and 2008 are derived from the unaudited condensed consolidated financial statements included elsewhere in this prospectus. The financial condition and results of operations of Abraxas Petroleum for the periods up to May 24, 2007 are referred to in this prospectus as “Predecessor,” and the financial condition and results of operations for periods subsequent to May 24, 2007 are referred to as “Successor” and represent only those of Abraxas Energy. The summary pro forma financial data of Abraxas Energy for the year ended December 31, 2008 and as of and for the three months ended March 31, 2009 are derived from the unaudited pro forma financial statements included elsewhere in this prospectus and give effect to:

•

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

•

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

The unaudited pro forma statement of operations data for the year ended December 31, 2008 and for the three months ended March 31, 2009 assume the St. Mary Acquisition and this offering occurred on January 1, 2008. The unaudited pro forma balance sheet as of March 31, 2009 assumes that this offering occurred on March 31, 2009. This pro forma financial data does not reflect incremental expenses we expect to incur as a publicly traded partnership of $0.8 million per year.

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

Index to Financial Statements

Summary Historical and Unaudited Pro Forma Financial Data


	Historical																		Pro Forma (unaudited)
	Predecessor						Successor												Pro Forma (unaudited)
	Abraxas Petroleum						Abraxas Energy												Abraxas Energy
										Year Ended December 31,			Three Months Ended March 31,			Three Months Ended March 31,			St. Mary Acquisition			After Offering			After Offering
	Years Ended December 31,			January 1 - May 24			May 25 - December 31,			Year Ended December 31,			Three Months Ended March 31,			Three Months Ended March 31,			Year Ended December 31,						Three Months Ended March 31,
	2006			2007			2007			2008			2008			2009			2008						2009
													(unaudited)			(unaudited)
	(In thousands, except per share/unit data)
Total operating revenue	$	51,077		$	19,305		$	22,148		$	83,391		$	18,816		$	8,630		$	87,045		$	87,045		$	8,630
Lease operating and production taxes		11,776			4,757			5,136			22,577			4,426			4,804			23,621			23,621			4,804
Depreciation, depletion and amortization		14,939			5,773			7,039			20,063			4,504			3,526			20,955			20,955			3,526
Ceiling-test impairment		—			—			—			97,121			—			2,775			97,121			97,121			2,775
General and administrative		5,160			1,867			987			2,657			514			807			2,657			2,657			807
Net interest expense		16,738			6,371			1,774			10,181			2,431			2,436			10,704			9,396			1,933
Amortization of deferred financing fees		1,591			632			121			988			184			202			1,054			1,054			202
Financing fees		—			—			—			359			—			362			359			359			362
Loss (gain) on derivative contracts		(646	)		218			4,125			(28,333	)		26,958			(12,865	)		(28,333	)		(28,333	)		(12,865	)
Loss on debt extinguishment		—			—			6,455			—			—			—			—			—			—
Other		—			—			—			1,105			—			21			1,105			1,105			21

Income (loss)	$	700		$	(608	)	$	(3,489	)	$	(43,327	)	$	(20,201	)	$	6,562		$	(42,198	)	$	(40,888	)	$	7,065
Income (loss) per common share/unit:
Basic	$	0.02		$	(0.01	)	$	(0.31	)	$	(3.81	)	$	(1.78	)	$	0.58		$	(3.71	)	$	(2.59	)	$	0.45
Diluted(1)	$	0.02		$	(0.01	)	$	(0.31	)	$	(3.81	)	$	(1.78	)	$	0.58		$	(3.71	)	$	(2.59	)	$	0.45
Other Financial Data:
Adjusted EBITDA(2)	$	33,887		$	12,305		$	18,031		$	47,166		$	13,876		$	9,071		$	49,776		$	49,776		$	9,071
Capital expenditures	$	26,346		$	6,622		$	14,086		$	131,900		$	127,895		$	2,293
Net cash provided by (used in):
Operating activities	$	15,561		$	10,150		$	5,466		$	30,474		$	13,473		$	5,925
Investing activities	$	(14,102	)	$	(6,622	)	$	(14,086	)	$	(131,900	)	$	(127,895	)	$	(2,293	)
Financing activities	$	(1,458	)	$	(1,742	)	$	10,379		$	101,591		$	113,795		$	(4,943	)

(1)	Does not include the common units underlying the redeemable warrants.

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


	Predecessor			Successor		Successor			Successor (unaudited)		Pro Forma After Offering (unaudited)
	Abraxas Petroleum			Abraxas Energy		Abraxas Energy			Abraxas Energy
	At December 31,								At March 31,
	2006			2007		2008			2009
	(In thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	(3,719	)	$	3,740	$	(14,595	)	(11,983	)	6,547
Total assets		116,940			105,703		169,240		169,991		169,991
Current maturities of long-term debt		—			—		40,000		40,000		21,470
Long-term debt		127,614			45,900		126,500		125,600		125,600
Stockholders’/partners’ equity (deficit)		(22,165	)		49,688		(12,492	)	(8,457	)	10,073

Index to Financial Statements

Summary Historical and Pro Forma Operating and Reserve Data

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


	Predecessor				Successor								Pro Forma
	Abraxas Petroleum				Abraxas Energy								Abraxas Energy
	Year Ended December 31,		January 1 - May 24,		May 25 - December 31,		Year Ended December 31,		Three Months Ended March 31,		Three Months Ended March 31,		Year Ended December 31,
	2006		2007		2007		2008		2008		2009		2008
Production:
Oil (MBbls)		200		79		78		452		96		114		484
Gas (MMcf)		6,515		2,291		2,753		5,505		1,348		1,330		5,678
Total (MMcfe)		7,718		2,765		3,219		8,218		1,922		2,012		8,581
Average daily production (Mcfepd)		21,144		19,198		14,566		22,453		21,120		22,360		23,447

Average Sales Price:
Oil ($/Bbl)	$	62.10	$	56.49	$	69.78	$	79.14	$	81.22	$	67.08	$	79.25
Gas ($/Mcf)	$	5.77	$	6.22	$	6.80	$	6.97	$	7.54	$	6.04	$	6.94
Gas equivalents ($/Mcfe)	$	6.48	$	6.77	$	7.50	$	9.02	$	9.33	$	7.78	$	9.06

Operating Expenses ($/Mcfe)	$	1.52	$	1.72	$	1.60	$	2.75	$	2.30	$	2.39	$	2.75


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

(1)

Index to Financial Statements

Non-GAAP Financial Measures

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

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

•

Net interest expense;

•

Depreciation, depletion and amortization;

•

Amortization of deferred financing fees;

•

Unrealized loss (gain) on derivative contracts;

•

Ceiling-test impairment;

•

Income tax provision;

•

(Gain) loss on sale of assets; and

•

Loss on debt extinguishment.

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

•

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

•

the ability of our assets to generate sufficient cash:

•

to fund maintenance capital expenditures; and

•

to pay cash distributions to our unitholders.

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

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

Index to Financial Statements

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


	Predecessor						Successor			Successor									Pro Forma
	Abraxas Petroleum						Abraxas Energy			Abraxas Energy									Abraxas Energy
																			St. Mary Acquisition			After Offering			After Offering
	Year Ended December 31,			January 1 - May 24,			May 25 - December 31,			Year Ended December 31,			Three Months Ended March 31,						Year Ended December 31,						Three Months Ended March 31,
	2006			2007			2007			2008			2008			2009			2008						2009
	(In thousands)
	(unaudited)
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	700		$	(608	)	$	(3,489	)	$	(43,327	)	$	(20,201	)	$	6,562		$	(42,198	)	$	(41,610	)	$	7,065
Add (deduct):
Net interest expense		16,738			6,371			1,774			10,181			2,431			2,436			10,704			10,116			1,933
Depreciation, depletion and amortization		14,939			5,773			7,039			20,063			4,504			3,526			20,955			20,955			3,526
Amortization of deferred financing fees		1,591			632			121			988			184			202			1,054			1,054			202
Unrealized loss (gain) on derivative contracts		(81	)		137			6,131			(37,860	)		26,958			(6,430	)		(37,860	)		(37,860	)		(6,430	)
Ceiling-test impairment		—			—			—			97,121			—			2,775			97,121			97,121			2,775
Loss on debt extinguishment		—			—			6,455			—			—			—			—			—			—

Adjusted EBITDA	$	33,887		$	12,305		$	18,031		$	47,166		$	13,876		$	9,071		$	49,776		$	49,776		$	9,071

Reconciliation of net cash provided by operations to Adjusted EBITDA:
Net cash provided by operations	$	15,561		$	10,150		$	5,466		$	30,474		$	13,473		$	5,925
Add (deduct):
Cash interest expense and other financing costs, net		16,605			6,394			1,675			9,715			2,586			2,510
Equity-based compensation		(998	)		(276	)		—			(242	)		—			47
Changes in working capital		2,892			3,918			(4,428	)		2,816			5,300			(404	)
Unrealized loss (gain) on derivative contracts		(81	)		137			6,131			(37,860	)		26,958			(6,430	)
Ceiling-test impairment		—			—			—			97,121			—			2,775
Other		(92	)		(8,018	)		9,187			(54,858	)		(34,441	)		4,648

Adjusted EBITDA	$	33,887		$	12,305		$	18,031		$	47,166		$	13,876		$	9,071

Index to Financial Statements

RISK FACTORS

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

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

Risks Related to Our Business

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

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

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

•

the amount of oil and gas we produce;

•

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

•

the effectiveness of our commodity price 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;

Index to Financial Statements

•

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.”

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

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

•

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;

Index to Financial Statements

•

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 Activities.”

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

Approximately 11% of our production during the year ended December 31, 2008 and approximately 13% during the three months ended March 31, 2009 was from the La Escalera 1AH well in our Oates SW area of the Permian Basin and the Henson 3H well in the Edwards trend of the Gulf Coast region. These wells represented approximately 3% of our estimated proved developed reserves as of December 31, 2008 principally because the La Escalera 1AH well is expected to be depleted in 2011. Like all gas wells, the rate of production from these wells will decline over time and the estimated future reserves associated with these wells will also decrease. If production from these wells declines more rapidly than we anticipate, it would have a material adverse effect on our ability to make distributions at the level we anticipate.

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

After giving effect to the use of proceeds from this offering, we expect to have approximately $125.6 million outstanding under our credit facility and approximately $22.0 million outstanding under our subordinated credit facility. Following this offering, we will have the ability to incur debt, including under our credit facility, subject to borrowing base limitations. At May 8, 2009, our borrowing base was $130.0 million. 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.

Index to Financial Statements

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Approximately 92% of the estimated ultimate recovery of our estimated proved developed reserves as of December 31, 2008 had been produced. Based on the reserve information set forth in our reserve reports at December 31, 2008, our average annual estimated decline rate for our net proved developed producing reserves is 10% during the first five years, 8% in the next five years and approximately 8% thereafter. This rate of decline is an estimate, and actual production declines could be materially higher. Our decline rate may change when we drill additional wells, make acquisitions and under other circumstances. Our future cash flow from operations and our ability to maintain distributions to unitholders are highly dependent on our success in efficiently exploiting and developing our current reserves. Our ability to increase distributions will be highly dependent on our ability to economically find or acquire additional recoverable reserves. We may not be able to exploit, develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

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

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

During 2008, we experienced differentials of $7.31 per Bbl of oil and $1.36 per Mcf of gas and during the three months ended March 31, 2009, we experienced differentials of $8.24 per Bbl of oil and $1.05 per Mcf of gas. Approximately 43% of our production during 2008 and 49% during the three months ended March 31, 2009 was from our properties located in the Rocky Mountain and Mid-Continent regions of the United States. Historically, these regions have experienced wider differentials than the Permian Basin and Gulf Coast. If the percentage of our production from these regions increases, we would expect that our price differentials would also increase. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our cash flow from operations and could affect our ability to pay cash distributions to you. For more information regarding our expected differentials for the twelve months ending June 30, 2010, please read “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Operations and Revenue—Prices.”

Index to Financial Statements

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

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

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

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

•

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.

Index to Financial Statements

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

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

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

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

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

•

make distributions to unitholders or repurchase units;

•

incur indebtedness;

Index to Financial Statements

•

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. The lenders can unilaterally adjust the borrowing base, and the borrowings permitted to be outstanding under our credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and gas properties as additional collateral. We do not currently have any substantial unpledged properties and we may not have the financial resources in the future to make mandatory principal repayments required under our credit facility. Please read “Cash Distribution Policy and Restrictions on Distributions—Our Cash Distribution Policy—General,” “—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy,” “—Our Initial Distribution Rate” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.” Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of our cash flow from operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants or ratios in our credit facility or exceed our borrowing base, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be limited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

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

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

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

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

Index to Financial Statements

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

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

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

•

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.

Index to Financial Statements

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

To achieve more predictable cash flow and reduce our exposure to fluctuations in the prices of oil and gas and to comply with the requirements under our credit facility, we have and expect to continue to enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized losses. At May 8, 2009, we had NYMEX-based fixed price commodity swaps on approximately 80% (85% for 2009-2011 and 60% for 2012) of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2012. We have elected out of hedge accounting as prescribed by applicable accounting rules. For more information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives.”

The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity price hedging activities. For example, the prices utilized in our derivative contracts are NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where oil and gas are produced. The prices that we receive for our oil and gas production are typically lower than the relevant benchmark prices that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. As a result, our cash flow could be adversely affected if the basis differentials widen more than we anticipate. For more information, see “—An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations and could affect our ability to pay cash distributions to you.” We currently do not have any basis differential hedging arrangements in place. Our cash flow could also be affected based upon the levels of our production. If production is higher than we estimate, we will have greater commodity price exposure than we intended. If production is lower than the nominal amount that is subject to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction in cash flows. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk—Hedging Activities and Sensitivity” for more information.

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

At May 8, 2009, we had NYMEX-based fixed price commodity swaps on approximately 80% (85% for 2009-2011 and 60% for 2012) of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2012. The volume weighted average prices in our derivative contracts are $81.08 per barrel of oil and $8.14 per MMbtu of gas. The contract prices for oil and gas are significantly higher than the NYMEX futures price on May 8, 2009 of $58.63 per barrel and $4.31 per MMbtu. When our contract prices are higher than prevailing market prices, we will sustain realized and unrealized gains on our derivative contracts. Conversely, when our contract prices are less than prevailing market prices, we will sustain realized and unrealized losses on our derivative contracts. For the year ended December 31, 2008, we recognized a realized loss of ($9.3) million and an unrealized gain of $37.9 million. The realized loss resulted in a decrease in cash flow from operations and negatively affected our cash available for distribution. We expect to continue to enter into similar hedging arrangements in the future to reduce cash flow volatility.

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

As of March 31, 2009, the mark-to-market value of our commodity derivative contracts was $46.1 million which entitles us to future payments from our counterparty. The worldwide financial and credit crisis may adversely affect the ability of our counterparty to fulfill its obligations to us. If our counterparty is unable or unwilling to make the required payments to us, it could have a material adverse effect on our cash flows, results of operations and our ability to pay cash distributions.

Index to Financial Statements

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

We have currently hedged a significant portion of our estimated oil and gas production from our net proved developed producing reserves with NYMEX-based fixed price commodity swaps through December 2012. As our derivative contracts expire, more of our future production will be sold at market prices unless we enter into further hedging arrangements. Our commodity price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under any future obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these arrangements, which may be substantially higher or lower than current oil and gas prices. Accordingly, our commodity price hedging strategy may not protect us from significant declines in oil and gas prices received for our future production. Conversely, our commodity price hedging strategy has limited and may in the future limit our ability to realize increased cash flow from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared to the next few years, which would result in our oil and gas revenues becoming more sensitive to commodity price changes.

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

Lower oil or gas prices may not only decrease our revenues, but also reduce the amount of oil or gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of exploitation and development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and gas properties for impairments. This is known as a ceiling-test impairment. At December 31, 2008 and at March 31, 2009, the net capitalized costs of our oil and gas properties exceeded the present value of our estimated proved reserves by $97.1 million and $2.8 million, respectively, resulting in a ceiling-test impairment of $97.1 million and $2.8 million, respectively. 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.

Index to Financial Statements

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

Our business activities are subject to operational risks, including:

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

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facility or equipment malfunctions;

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pipeline ruptures or spills;

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fires, blowouts, craterings and explosions; and

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uncontrollable flows of oil or gas or well fluids.

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

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

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

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

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

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

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

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

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

Index to Financial Statements

for plugging and abandoning wells and environmental liabilities relating to our properties” and “Business—Environmental Matters” for more information on the laws and regulations that affect us, the operation of our properties and certain related risks and potential liabilities.

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

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

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the operations of our properties. While the cost of compliance with these laws has not been material to the operations of our properties in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders could be adversely affected. Please read “Business—Environmental Matters” and “Business—Regulation of Oil and Gas Activities” for more information.

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

We are responsible for all plugging and abandonment costs relating to our properties. As of March 31, 2009, we have estimated these costs to be approximately $9.2 million. In addition, under the terms of our omnibus agreement with Abraxas Petroleum, we have agreed to be responsible for all environmental liabilities relating to the properties contributed to us in the Formation Transactions except to the extent we are indemnified by Abraxas Petroleum. Abraxas Petroleum has agreed to indemnify us through May 24, 2010 against certain potential environmental claims. Abraxas Petroleum’s maximum liability for these indemnification obligations will not exceed $5 million and Abraxas Petroleum will not have any obligation under this indemnification until our aggregate losses exceed $500,000. Abraxas Petroleum will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after May 25, 2007. We have agreed to indemnify Abraxas Petroleum against environmental liabilities related to our assets to the extent Abraxas Petroleum is not required to indemnify us. We also agreed to indemnify St. Mary against all environmental liabilities related to the properties acquired in the St. Mary Acquisition.

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

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

Index to Financial Statements

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

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

Risks Inherent in an Investment in Us

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

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

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

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

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

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

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

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

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

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

Index to Financial Statements

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

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

Please read “Conflicts of Interest and Fiduciary Duties.”

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

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

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

Pursuant to our omnibus agreement, we currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and administrative expenses, subject to annual adjustments for inflation and acquisitions or other expansion adjustments. This fee includes an adjustment made in January 2008 for the St. Mary property acquisition of $1.1 million. Thereafter, our payment obligations to Abraxas Petroleum for general and administrative services provided on our behalf are not fixed. In addition, pursuant to our operating agreements we are required to reimburse Abraxas Petroleum for all of our operating expenses, which are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Operating expenses do not include general and administrative expenses. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Omnibus Agreement” and “—Operating Agreement.”

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

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

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

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

Index to Financial Statements

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

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

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

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provides that in resolving conflicts of interest, it will be presumed that in making its determination as to whether the terms are “no less favorable” or “fair and reasonable” to us, the general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

Holders of our common units are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent the removal of our general partner. The vote of the holders of at least 66²/3% of all outstanding common units voting together as a single class is required to remove our general partner. Upon consummation of this offering, our general partner and its affiliates will own approximately 34.9% of our common units and approximately 33.6% of our common units if the underwriters exercise their over-allotment option to purchase additional common units and redeemable warrants in full. If Abraxas Petroleum purchases all of the common units it has agreed to purchase in this offering, our general partner and its affiliates will own approximately 38.8% of our common units and approximately 37.4% of our common units if the underwriters exercise their over-allotment option to purchase additional common units and redeemable warrants 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.

Index to Financial Statements

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 $4.59 in tangible net book value per common unit.

The assumed initial public offering price of $5.00 per unit exceeds our pro forma net tangible book value of $(0.90) per unit before this offering. Based on the assumed initial public offering price of $5.00 per unit, you will incur immediate and substantial dilution of $4.59 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.”

You will not be able to exercise your redeemable warrants if we do not have an effective registration statement in place when you desire to do so.

No redeemable warrants will be exercisable, and we will not be obligated to issue common units upon exercise of redeemable warrants by a holder unless, at the time of such exercise, we have a registration statement under the Securities Act of 1933, as amended, in effect covering the common units issuable upon exercise of the redeemable warrants and a current prospectus or another registration statement and current prospectus relating to such common units or an exemption from registration is available. The registration statement of which this prospectus is a part includes the sale or transfer of the common units that you would receive upon exercise of the redeemable warrants and we have agreed to use our best efforts to keep this registration statement in effect covering common units issuable upon exercise of the redeemable warrants and to maintain a current prospectus relating to the common units until the redeemable warrants expire or are redeemed. However, we cannot assure you that we will be able to do so. The redeemable warrants may be deprived of any value, the market for the redeemable warrants may be limited and the holders of redeemable warrants may not be able to sell the common units they receive upon exercise of their redeemable warrants if there is no registration statement in effect covering common units issuable upon the exercise of the redeemable warrants or the prospectus relating to the common units issuable upon the exercise of the redeemable warrants is not current.

We may choose to redeem our redeemable warrants at a time that is disadvantageous to our warrant holders.

Subject to there being an effective registration statement with respect to the common units issuable upon exercise of the redeemable warrants, we may redeem the redeemable warrants at any time after the redeemable warrants become exercisable in whole and not in part, at a price of $0.01 per warrant, upon a minimum of 30 days prior written notice of redemption and if the last sales price of our common units equals or exceeds $[ ] per share for any 20 trading days within a 30-trading-day period ending three business days before we deliver a notice of redemption. Redemption of the warrants could force the warrant holders to (i) exercise the warrants and pay the exercise price at a time when it may be disadvantageous for the holders to do so, (ii) sell the warrants at the then current market price when they might otherwise wish to hold the warrants, or (iii) accept the $0.01 redemption price which, at the time the warrants are called for redemption, is likely to be substantially less than the market value of the warrants.

Our redeemable warrants may adversely affect the market price of our common units.

The exercise of the redeemable warrants will increase the number of issued and outstanding common units and reduce the value of our common units. If and to the extent these redeemable warrants are exercised, you may experience dilution to your holdings.

Index to Financial Statements

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 the redeemable warrants being exercised for common units, of future sales of our common units, or the availability of common units for future sales, on the market price of or the liquidity of the market for our common units. Sales of substantial amounts of common units, or the perception that such sales could occur, could adversely affect the prevailing market price of our common units. Such sales, or the possibility of such sales, could also make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. In addition, if no active trading market develops for our common units, sales of common units or the possibility of such sales could have a greater adverse effect on the market price of our common units than would be the case if an active market existed.

Upon completion of this offering, the Private Investors and their affiliates will own approximately 6,059,651 common units, representing approximately 38.4% of our outstanding units. The Private Investors will generally be eligible to sell their common units into the market beginning 60 days after the date of this prospectus. Please read “Certain Relationships and Related Party Transactions—Summary of Formation Transaction Documents—Registration Rights Agreement,” “Underwriting—Lock-Up Agreements” and “Units Eligible For Future Sale” for additional information.

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

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

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

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our unitholders’ proportionate ownership interest in us will decrease;

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

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the ratio of taxable income to distributions may increase;

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

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

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the market price of our common units may decline.

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

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

Index to Financial Statements

current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Upon completion of this offering, Abraxas Investments, an affiliate of our general partner, will own approximately 34.6% of our outstanding common units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants and that Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering. Please read “The Partnership Agreement—Limited Call Right.”

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

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

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

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

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

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

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

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

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

Index to Financial Statements

Holders may have limited liquidity for their common units and redeemable warrants, a trading market may not develop for our common units or the redeemable warrants, 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 or our redeemable warrants. After this offering, there will be 4,000,000 publicly traded common units, or 4,600,000 publicly traded common units if the underwriters exercise their over-allotment option to purchase additional common units and redeemable warrants in full. In addition, the Private Investors and their affiliates will generally be able to sell all 6,059,651 common units owned by them into the market beginning 60 days after the date of this prospectus. Please read “—Units eligible for future sale may have adverse effects on our unit price and the liquidity of the market for our common units.” We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.

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

Tax Risks to Common Unit Holders and Redeemable Warrant Holders

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

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

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

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

Additionally, any income we receive as a result of the expiration of the redeemable warrants or a redemption of such redeemable warrants appears likely to be treated as income other than “qualifying income,” as further discussed in “Material Tax Consequences—Partnership Status.” If such income is not qualifying

Index to Financial Statements

income, and if it equals or exceeds 10% of our gross income in any one year, we would thereafter be treated as a corporation for federal income tax purposes. Based on the terms of the redeemable warrants, however, we do not expect such income to rise to a level that would cause us to be taxed as a corporation for federal income tax purposes; provided, further, that such expectation is based on the primary assumptions that (i) in the year in which such income is recognized, our gross income will be close to its current level and (ii) that we have properly valued the redeemable warrant interest.

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

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

As a common unitholder 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.

You may have to recognize income in the future as a result of the exercise of your redeemable warrant.

Upon the exercise of a redeemable warrant, to the extent the value of the common unit you receive exceeds the sum of (i) your allocated purchase price of the redeemable warrant and (ii) the redeemable warrant exercise price, we will allocate unrealized income to you, to the extent available, that you must recognize at the time of the disposition of our assets, or, in the event we do not have unrealized income to allocate to you, we will allocate future items of income to you until such time as the sum of such allocated income, the redeemable warrant purchase price and the redeemable warrant exercise price, equals the value of the common unit you receive upon exercise. Please read “Material Tax Consequences—Tax Consequences of an Investment in the Redeemable Warrants—Exercise of a Redeemable Warrant.”

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

If our unitholders or warrant holders sell any of their units or redeemable warrants, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those units or redeemable warrants. Additionally, upon the redemption or expiration of a redeemable warrant, you would recognize a loss to the extent your purchase price of the redeemable warrant, as discussed in “Material Tax Consequences—

Index to Financial Statements

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

You may not recognize capital gain or loss on the disposition of a redeemable warrant.

Although a sale of a capital interest generally results in a capital gain or loss, the proposed Regulations do not make it clear that a redeemable warrant for a partnership interest is a capital asset, and therefore it is possible that any gain or loss recognized with respect to the disposition of a redeemable warrant will be treated as ordinary gain or loss to you. Please Read “Material Tax Consequences—Tax Consequences of an Investment in the Redeemable Warrants—Sale, Exchange, Redemption or Expiration of a Redeemable Warrant.”

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.

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

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

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

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

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the

Index to Financial Statements

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

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

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

Index to Financial Statements

USE OF PROCEEDS

We expect the estimated net proceeds from this offering and the proportionate capital contribution from our general partner of $0.4 million to be $18.5 million, after deducting the underwriting discount of $1.0 million and offering expenses of approximately $0.9 million to be paid with proceeds from this offering, based on an assumed offering price of $5.00 per unit. We intend to use the net proceeds of this offering, together with our general partner’s proportionate capital contribution of approximately $0.4 million, to partially repay indebtedness outstanding under our subordinated credit facility. Our general partner’s proportionate capital contribution of $0.4 million will result in the issuance of an additional 89,385 general partner units, for a total of 316,617 general partner units, and maintenance of its 2% general partner interest. We have previously paid approximately $1.8 million in offering expenses out of available cash.

At May 8, 2009, we had borrowings of $40.0 million outstanding under our subordinated credit facility. We used the borrowings under our subordinated credit facility to partially finance the St. Mary Acquisition. Outstanding amounts under our subordinated credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR, plus in each case (b) 9.0% or, if we elect, at the greater of (a) 2.0% and (b) LIBOR, in each case, plus 10.0%. At May 8, 2009, the interest rate on our subordinated credit facility was approximately 12.0%. The maturity date of our subordinated credit facility is July 1, 2009. We intend to partially repay indebtedness outstanding under our subordinated credit facility with proceeds from this offering. We also intend to re-finance the indebtedness outstanding under our subordinated credit facility prior to its scheduled maturity date; however, there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial adviser to assist us in this re-financing. An increase or decrease in the initial public offering price of $1.00 per common unit, together with the proportionate capital contribution from our general partner, would cause the net proceeds from the offering, after deducting the underwriting discount and all estimated offering expenses payable by us, to increase or decrease by approximately $3.8 million.

Index to Financial Statements

CAPITALIZATION

The following table shows:

•

our historical cash and capitalization as of March 31, 2009; and

•

our cash and capitalization as of March 31, 2009, as adjusted to reflect the sale of 4,000,000 units in this offering at an assumed offering price of $5.00 per unit less the underwriting discount and estimated offering expenses, our general partner’s proportionate capital contribution of approximately $0.4 million and the application of the net proceeds we expect to receive as described under “Use of Proceeds.”

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


	Abraxas Energy
	As of March 31, 2009
	Historical			As Adjusted for this Offering(1)
	(In thousands)
Cash and cash equivalents	$	613		$	613

Current maturities of long-term debt		40,000			21,470
Long-term debt		125,600			125,600
Total partners’ capital (deficit)		(8,457	)		10,073

Total capitalization	$	157,143		$	157,143

(1)

A $1.00 increase or decrease in the assumed public offering price per common unit, together with the proportionate capital contribution from our general partner, would increase or decrease our total partners’ capital by $3.8 million, assuming 4,000,000 common units offered by us and after deducting the underwriting discount and all estimated offering expenses payable by us.

Index to Financial Statements

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 $5.00 per common unit, as of March 31, 2009, 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 $6.4 million, or $0.41 per common unit. Purchasers of 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				$5.00
Net tangible book value per common unit before this offering(1)	$	(0.90	)
Increase in net tangible book value per common unit attributable to purchasers in this offering		1.31

Less: net tangible book value per common unit after this offering(2)					(0.41	)

Immediate dilution in net tangible book value per common unit to new investors(3)				$	4.59

(1)

Determined by dividing the net tangible book value of our assets as of March 31, 2009 by the number of units (11,252,610 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 (15,462,249 common units and 316,617 general partner units, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants and that Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering), into our net tangible book value, after giving effect to the application of the expected net proceeds of this offering.

(3)

If the initial public offering price were to increase by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $5.35. 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 $3.84.

The analysis set forth above excludes the redeemable warrants to be issued in this offering, as well as the common units underlying the redeemable warrants. To the extent any redeemable warrants are exercised, our unitholders will experience further dilution.

The following table sets forth the number of units that have been issued and the total consideration contributed to us by the Private Investors, our general partner and its affiliates with respect to their units and by the purchasers of common units in this offering assuming the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants and that Abraxas Petroleum does not purchase any common units and redeemable warrants 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)	11,779	74.6	%	$	31,797	61.4	%
New investors(3)	4,000	25.4	%		20,000	38.6	%

Total(3)	15,779	100.0	%	$	51,797	100.0	%

(1)

The Private Investors currently own 6,059,651 common units, representing a 38.4% interest in us after this offering. Our general partner will own 316,617 general partner units, representing a 2% interest in us after this offering, its affiliate, Abraxas Investments owns 5,350,598 common units, representing a 33.9% interest

Index to Financial Statements

in us, and the restricted unitholders own 52,000 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 the Private Investors, our general partner and its affiliates is equal to the net tangible book value of such assets as of March 31, 2009.

(3)	Does not include common units underlying the redeemable warrants.

Index to Financial Statements

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

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

All information in this section refers to Abraxas Energy and our properties. For additional information regarding our historical and pro forma operating results, you should refer to the unaudited pro forma consolidated financial statements and the notes thereto of Abraxas Energy for the year ended December 31, 2008 and the three months ended March 31, 2009, the audited consolidated financial statements and the notes thereto of Abraxas Petroleum for the year ended December 31, 2006 and for the period from January 1 to May 24, 2007, the audited consolidated financial statements and the notes thereto of Abraxas Energy for the period from May 25 to December 31, 2007 and for the year ended December 31, 2008 and the unaudited consolidated financial statements and the notes thereto of Abraxas Energy for the three months ended March 31, 2009, included elsewhere in this prospectus.

Our Cash Distribution Policy

General

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

•

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

•

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

•

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

We intend to fund our capital expenditures with cash flow from operations, borrowings under our credit facility, and sales of debt or equity securities. We may also borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused cash available from operations to be insufficient to pay the distribution at the current level. Our credit facility restricts our ability to incur additional indebtedness and further restricts our ability to pay cash distributions under certain circumstances. Under the terms of our credit facility, we may make cash distributions if, after giving effect to such distributions, we are not in default under our credit facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under our credit facility is greater than or equal to 10% of the lesser of our borrowing base (which at May 8, 2009 was $130.0 million) or the total commitment amount of our credit facility (which is $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under our credit facility after giving effect to such distribution exceeds $20.0 million, or (ii) our subordinated credit facility shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while our subordinated credit facility is outstanding. Under the credit facility, the amount of the cash distribution to be made by the Partnership on or about May 14, 2009 attributable to the first quarter of 2009 was to be deposited into an escrow account established with one of the lenders. Rather than paying the funds into an escrow account, the board of directors of the general partner elected to defer the declaration of the cash distribution attributable to the first quarter of 2009 until the distribution may be paid under the terms of our credit facility. We expect to declare and pay this distribution upon the repayment of the indebtedness outstanding under

Index to Financial Statements

our subordinated credit facility. Additionally, while our subordinated credit facility is outstanding, our capital expenditures are limited to $12.5 million. We are not currently a party to any other agreement which restricts our ability to pay cash distributions, and our partnership agreement does not restrict our ability to borrow to pay distributions.

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. However, the amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our operations and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.

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

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

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

•

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

•

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

•

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

•

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

Index to Financial Statements

•

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

•

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

•

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

•

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

•

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

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

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

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

Our Initial Distribution Rate

The board of directors of our general partner has adopted a cash distribution policy pursuant to which, after completion of this offering, we will pay an initial quarterly distribution of $0.25 per unit, or $1.00 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 $3.9 million per quarter, or approximately $15.8 million per year, based on the units outstanding immediately after completion of this offering (assuming that none of the redeemable warrants are exercised). If the underwriters fully exercise their over-allotment option to purchase 600,000 additional

Index to Financial Statements

common units, then the aggregate cash distribution would increase to approximately $4.1 million per quarter, or approximately $16.4 million per year (assuming that none of the redeemable warrants are exercised). Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy,” and by the terms of our credit facility. Under the terms of our credit facility, we may make cash distributions if, after giving effect to such distributions, we are not in default under our credit facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under our credit facility is greater than or equal to 10% of the lesser of our borrowing base (which at May 8, 2009 was $130.0 million) or the total commitment amount of our credit facility (which is $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under our credit facility after giving effect to such distribution exceeds $20.0 million, or (ii) our subordinated credit facility shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while our subordinated credit facility is outstanding. Under the credit facility, the amount of the cash distribution to be made by the Partnership on or about May 14, 2009 attributable to the first quarter of 2009 was to be deposited into an escrow account established with one of the lenders. Rather than paying the funds into an escrow account, the board of directors of the general partner elected to defer the declaration of the cash distribution attributable to the first quarter of 2009 until the distribution may be paid under the terms of our credit facility. We expect to declare and pay this distribution upon the repayment of the indebtedness outstanding under our subordinated credit facility. Additionally, while our subordinated credit facility is outstanding, our capital expenditures are limited to $12.5 million.

The following table sets forth the number of outstanding units (assuming no exercise and full exercise of the underwriters’ over-allotment option to purchase additional common units and redeemable warrants) 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 $0.25 per unit per quarter ($1.00 per unit on an annualized basis) assuming that Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering:


	No Exercise of the Underwriters’ Over-Allotment Option to Purchase Additional Common Units					Full Exercise of the Underwriters’ Over-Allotment Option to Purchase Additional Common Units
		Distributions					Distributions
	Number of Units	One Quarter		Four Quarters		Number of Units	One Quarter		Four Quarters
Public common units(1)	4,000,000	$	1,000,000	$	4,000,000	4,600,000	$	1,150,000	$	4,600,000
Private Investor common units	6,059,651		1,514,913		6,059,651	6,059,651		1,514,913		6,059,651
Common units held by Abraxas Petroleum and its affiliates(1)	5,350,598		1,337,650		5,350,598	5,350,598		1,337,650		5,350,598
General partner units	316,617		79,153		316,617	328,862		82,214		328,862
Restricted units	52,000		13,000		52,000	52,000		13,000		52,000

Total	15,778,866	$	3,944,716	$	15,778,866	16,391,111	$	4,097,777	$	16,391,111

(1)	Does not include common units underlying the redeemable warrants.

Index to Financial Statements

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


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

Under the credit facility, the amount of the cash distribution to be made by the Partnership on or about May 14, 2009 attributable to the first quarter of 2009 was to be deposited into an escrow account established with one of the lenders. Rather than paying the funds into an escrow account, the board of directors of the general partner elected to defer the declaration of the cash distribution attributable to the first quarter of 2009 until the distribution may be paid under the terms of our credit facility. We expect to declare and pay this distribution upon the repayment of the indebtedness outstanding under our subordinated credit facility.

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

Pro Forma Financial Information and Estimated Cash Available for Distributions

In the sections that follow, we present the basis for our belief that we will be able to fully fund our initial quarterly distribution rate of $0.25 per unit for the twelve months ending June 30, 2010. In those sections we present two tables, including:

•

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

•

Our “Unaudited Pro Forma Consolidated Available Cash,” in which we present the amount of cash we would have had available for distribution with respect to the year ended December 31, 2008 and the twelve months ended March 31, 2009 derived from our unaudited pro forma consolidated financial statements that are included in this prospectus. The unaudited pro forma consolidated financial statements are based on the audited historical consolidated financial statements of Abraxas Energy for the year ended December 31, 2008 and the unaudited historical condensed consolidated financial statements of Abraxas Energy for the three months ended March 31, 2009, as adjusted to reflect the sale of common units in this offering and the application of the net proceeds therefrom as described in “Use of Proceeds.” Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

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

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

Index to Financial Statements

We believe that we will be able to generate the estimated cash available for distribution and pay distributions to all of our unitholders at the initial quarterly distribution rate for the twelve months ending June 30, 2010. In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this belief. We have also assumed that the prices at which we have hedged the majority of our production will be significantly greater than the estimated average NYMEX prices for the twelve months ending June 30, 2010 which results in a realized gain of approximately $19.3 million and that our counter-party will continue to perform as obligated under these hedging arrangements. In the event our counter-party does not perform as obligated or in the absence of derivative contracts which provide for commodity prices which are higher than current market prices, our cash flow from operations will not be sufficient to pay the initial quarterly distributions on our units if commodity prices do not drastically improve. We have currently hedged a significant portion of our estimated oil and gas production from our net proved developed producing reserves with NYMEX-based fixed price commodity swaps through December 31, 2012 which we believe should enable us to pay the initial quarterly distributions on our units for several years after this offering. During periods when our contract prices are higher than current market prices, we realize gains on our derivative contracts which, in turn, are used to support our cash available for distribution. If we were unable to realize these gains on our derivative contracts during such periods, our cash flow from operations would not be sufficient to pay the initial quarterly distribution on our units. For example, during the three months ended March 31, 2009, our revenues less direct cash expenses were $583,000 and would have been insufficient to pay the initial quarterly distribution on our units; however, during the three months ended March 31, 2009, we realized $7.0 million in gains from our derivative contracts. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these arrangements, which may be substantially higher or lower than current oil and gas prices. If the prices at which we hedge future production are significantly lower than our current contract prices, we may not be able to pay the initial quarterly distributions on our units in the future if commodity prices remain at depressed levels. Accordingly, our commodity price hedging strategy may not protect us from significant declines in oil and gas prices received for our future production. We cannot assure you that our assumptions will be realized or that we will generate the estimated cash available for distribution, in which event we may not be able to pay the initial quarterly distributions on our units (absent borrowings under our credit facility, to the extent permitted). When considering how we calculate estimated cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus which discuss factors that could cause cash available for distribution to vary significantly from our estimates.

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

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

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

Index to Financial Statements

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

Abraxas Energy

Statement of Estimated Cash Available for Distribution


	Twelve Months Ending June 30, 2010
	Assuming no exercise of underwriters’ over-allotment option			Assuming exercise of underwriters’ over- allotment option
	(In thousands, except per unit amounts)
Operating revenues	$	45,074		$	45,074
Operating expenses
Lease operating expenses		13,639			13,639
Production taxes		4,282			4,282
General and administrative		3,566			3,566

Total operating expenses		21,487			21,487
Depreciation, depletion and amortization		15,213			15,213
Amortization of deferred financing fees		808			808
Loss (gain) on derivative contracts(a)		(19,290	)		(19,290	)
Equity-based compensation		200			200
Net interest expense(b)		13,377			13,197

Net income		13,279			13,459
Adjustments to reconcile net income to Adjusted EBITDA:
Plus:
Depreciation, depletion and amortization		15,213			15,213
Amortization of deferred financing fees		808			808
Net interest expense(b)		13,377			13,197	(c)

Estimated Adjusted EBITDA(d)		42,677			42,677
Adjustments to reconcile Estimated Adjusted EBITDA to Estimated Cash Available for Distribution:
Less:
Cash interest expense		12,777			12,597
Equity-based compensation		(200	)		(200	)
Cash payment on phantom units(e)		—			—
Maintenance capital expenditures(f)		10,719			10,719
Growth capital expenditures		—			—

Estimated Cash Available for Distribution	$	19,381		$	19,561

Distributions:
Distribution per unit	$	1.00		$	1.00
Distributions to:
General partner	$	317		$	329
Public common unitholders(g)		4,000			4,600
Private Investors		6,060			6,060
Restricted unitholders		52			52
Abraxas Petroleum and its affiliates		5,350			5,350

Total cash distributions	$	15,779		$	16,391

Excess of Estimated Cash Available for Distribution over Total cash distributions	$	3,602		$	3,170

(a)

We have assumed that the prices at which we have hedged the majority of our production will be significantly greater than the estimated average NYMEX prices for the twelve months ending June 30, 2010 which results in a realized gain of approximately $19.3 million and that our counter-party will continue to perform as obligated under our hedging arrangements. In the event our counter-party does not

Index to Financial Statements

perform as obligated or in the absence of derivative contracts which provide for commodity prices which are higher than current market prices, our cash flow from operations will not be sufficient to pay the initial quarterly distributions on our units if commodity prices do not drastically improve.

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

(c)	We have assumed that the net proceeds from the exercise in full of the underwriters’ over-allotment option would be used to further reduce indebtedness outstanding under our subordinated credit facility which would reduce interest expense by $0.2 million.

(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.”

(e)

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

(f)

For purposes of this table, we have assumed that we will fund all of our maintenance capital expenditures for the twelve months ending June 30, 2010 with cash flow from operations. We believe that we would have sufficient cash to pay the full initial quarterly distribution for four quarters on all of our units with maintenance capital expenditures of up to approximately $14.0 million for the twelve months ending June 30, 2010.

(g)	Does not include common units underlying the redeemable warrants.

Unaudited Pro Forma Consolidated Available Cash for the Year Ended December 31, 2008 and the Twelve Months Ended March 31, 2009

If we had completed this offering on January 1, 2008, our pro forma available cash for the year ended December 31, 2008 and the twelve months ended March 31, 2009 would have been approximately $26.8 million and $19.9 million, respectively. These amounts would have been sufficient by approximately $11.0 million and $4.1 million, respectively, to pay the full initial distribution amount on all of our units for the year ended December 31, 2008 and the twelve months ended March 31, 2009 (assuming that none of the redeemable warrants are exercised).

We believe that we will have sufficient cash available for distribution to pay the full quarterly distributions at the initial distribution rate of $0.25 per unit on all of our outstanding units for each quarter during the twelve months ending June 30, 2010. See “—Assumptions and Considerations” below for the specific assumptions underlying this belief.

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

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

The following table illustrates, on a pro forma basis, for the year ended December 31, 2008 and the twelve months ended March 31, 2009, the amount of cash we would have had available for distributions to our unitholders, assuming in each case that this offering had been consummated at the beginning of the period presented.

Index to Financial Statements

Abraxas Energy

Unaudited Pro Forma Consolidated Available Cash


	Year Ended December 31, 2008						Twelve Months Ended March 31, 2009
	Assuming no exercise of the underwriters’ over-allotment option			Assuming exercise of the underwriters’ over-allotment option			Assuming no exercise of the underwriters’ over-allotment option			Assuming exercise of the underwriters’ over-allotment option
	(In thousands, except per unit data)
Pro Forma Net Loss(a)	$	(40,888	)	$	(40,709	)	$	(15,275	)	$	(15,096	)
Plus:
Depreciation, depletion and amortization		20,955			20,955			19,085			19,085
Amortization of deferred financing fees		1,054			1,054			1,006			1,006
Net interest expense(b)		9,396			9,217	(c)		8,897			8,718
Unrealized loss (gain) on derivative contracts		(37,860	)		(37,860	)		(70,365	)		(70,365	)
Ceiling-test impairment(d)		97,121			97,121			99,897			99,897

Adjusted EBITDA(e)	$	49,778		$	49,778		$	43,245		$	43,245

Less:
Cash interest expense(f)		8,889			8,710			8,366			8,187
Cash payment on phantom units(g)		267			267			267			267
Capital expenditures(h)		13,400			13,400			14,651			14,651
Incremental expenses(i)		800			800			800			800
Financing fees(j)		(359	)		(359	)		(720	)		(720	)

Pro Forma Available Cash	$	26,781		$	26,960		$	19,881		$	20,060

Distributions per unit	$	1.00		$	1.00		$	1.00		$	1.00

Pro Forma Cash Distributions:
Distributions to:
General partner	$	317		$	329		$	317		$	329
Public common unitholders(k)		4,000			4,600			4,000			4,600
Private Investors		6,060			6,060			6,060			6,060
Restricted unitholders		52			52			52			52
Abraxas Petroleum and its affiliates		5,350			5,350			5,350			5,350

Total cash distributions	$	15,779		$	16,391		$	15,779		$	16,391

Excess	$	11,002		$	10,569		$	4,102		$	3,669

(a)

Reflects net loss of Abraxas Energy derived from its audited historical consolidated financial statements for the year ended December 31, 2008 and the unaudited historical condensed consolidated financial statements for the three months ended March 31, 2009 and 2008, giving pro forma effect to this offering.

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

(c)	We have assumed that the net proceeds from the exercise in full of the underwriters’ over-allotment option would be used to further reduce indebtedness outstanding under our subordinated credit facility which would reduce interest expense by $0.2 million.

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

(e)

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

(g)

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

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

Index to Financial Statements

(i)

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

(j)	Reflects an in-kind payment to the Private Investors of $0.0625 per unit for the fourth quarter of 2008 and the first quarter of 2009 pursuant to amendment no. 1 of the exchange and registration rights agreement.

(k)	Does not include common units underlying the redeemable warrants.

Assumptions and Considerations

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

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

Operations and Revenue

Production. The following table sets forth information regarding net production of oil and gas for the year ended December 31, 2008 and the twelve months ended March 31, 2009, and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008	Twelve Months Ended March 31, 2009	Estimated Twelve Months Ending June 30, 2010
Production:
Oil (MBbl)	452	465	451
Gas (MMcf)	5,505	5,487	5,299
Gas equivalents (MMcfe)	8,218	8,308	8,007
Daily Production:
Oil (Bopd)	1,235	1,288	1,236
Gas (Mcfpd)	15,040	15,032	14,518
Gas equivalents (Mcfepd)	22,453	22,762	21,936

We estimate that our production for the twelve months ending June 30, 2010 will be 8.0 MMcfe, which represents a decline of 2% as compared to the year ended December 31, 2008 and a 4% decline as compared to the twelve months ended March 31, 2009. Our estimated production for the twelve months ending June 30, 2010 reflects natural field declines offset by production that we believe will be generated by our maintenance capital expenditures. Over the long-term we expect service costs and commodity prices to be more balanced and we intend to set aside sufficient cash reserves or make sufficient capital expenditures to maintain our current

Index to Financial Statements

production level. At times, factors may cause us to reduce our capital expenditures, such as times of low commodity prices when service costs remain at relatively high levels. During these times, we intend to plan our development drilling to minimize the decline rate from our current production levels.

We define maintenance capital expenditures as those expenditures necessary to replace our reserves and maintain our current level of production. Growth capital expenditures are those expenditures necessary to increase our production and grow our asset base. We estimate that 86% of our production for the twelve months ending June 30, 2010 will be produced from wells producing on December 31, 2008 and that the remaining 14% will be produced from new wells and recompletion/workover projects, including production from wells that are currently classified as proved undeveloped. Historically, on the properties contributed to us by Abraxas Petroleum, we have added 1.0 Mcfepd of production for every $3,300 of capital expended. During the twelve months ending June 30, 2010, we estimate that we will spend $10.7 million on maintenance capital expenditures, which includes new wells and recompletion/workover projects on our properties. We believe that we would have sufficient cash to pay the full initial quarterly distribution for four quarters on all of our units with maintenance capital expenditures of up to approximately $14.0 million for the twelve months ending June 30, 2010. We have not included any growth capital expenditures in our estimates for increasing our production or growing our asset base. We have assumed that we will be successful in finding oil and gas in commercial quantities based on our past drilling results. For the five years ended December 31, 2007, Abraxas Petroleum drilled 13 gross (10.2 net) wells on the properties contributed to us, of which 100% resulted in commercially productive wells. For the year ended December 31, 2008, Abraxas Petroleum and other operators drilled 40 gross (1.6 net) wells on our properties, of which 100% resulted in commercially productive wells.

Prices. The table below illustrates the relationship between realized prices and NYMEX prices for the year ended December 31, 2008 and the twelve months ended March 31, 2009 as compared to our estimate for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Twelve Months Ended March 31, 2009		Estimated Twelve Months Ending June 30, 2010
Oil ($/Bbl):
Average NYMEX price	$	100.21	$	86.72	$	60.00
Realized price		92.89		78.68		53.50

Differential to NYMEX	$	7.31	$	8.04	$	6.50

Gas ($/Mcf):
Average NYMEX price	$	8.88	$	7.90	$	5.25
Realized price		7.52		6.60		3.95

Differential to NYMEX	$	1.36	$	1.30	$	1.30

Gas Equivalents ($/Mcfe):
Realized price	$	10.15	$	8.81	$	5.63

We have estimated average NYMEX oil and gas prices of $60.00 per barrel and $5.25 per Mcf, respectively, for the twelve months ending June 30, 2010 based on NYMEX futures prices on May 8, 2009 that averaged $63.73 per barrel for oil and $5.61 per Mcf for gas for the twelve months ending June 30, 2010. For the year ended December 31, 2008, average NYMEX oil and gas prices were $100.21 per barrel and $8.88 per Mcf, respectively, and for the twelve months ended March 31, 2009, average NYMEX oil and gas prices were $86.72 per barrel and $7.90 per Mcf, respectively. We have applied differentials to the NYMEX prices which reflect our historical averages and result in estimated realized prices for the twelve months ending June 30, 2010. For the year ended December 31, 2008, the average NYMEX price reflects the average daily spot (or cash) price for WTI (West Texas Intermediate) oil and Henry Hub gas.

Our oil price differential to the average NYMEX price is expected to average $6.50 for the twelve months ending June 30, 2010 as compared to $8.04 for the twelve months ended March 31, 2009. Our gas price differential to the average NYMEX price is expected to average $1.30 for the twelve months ending June 30,

Index to Financial Statements

2010 as compared to $1.30 for the twelve months ended March 31, 2009. We expect that our differentials will be lower for the twelve months ending June 30, 2010 due to lower NYMEX oil and gas prices as compared to the twelve months ended March 31, 2009 as the majority of our marketing agreements are based on a percentage of the prevailing market price.

Hedging. The following table summarizes our realized oil and gas prices for the year ended December 31, 2008 and the twelve months ended March 31, 2009, and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Twelve Months Ended March 31, 2009		Estimated Twelve Months Ending June 30, 2010
Oil ($/Bbl):
Realized price	$	92.89	$	78.68	$	53.50
Realized loss (gain) on derivative contracts		13.75		2.88		(18.05	)

Combined realized oil price	$	79.14	$	75.80	$	71.55

Gas ($/Mcf):
Realized price	$	7.52	$	6.60	$	3.95
Realized loss (gain) on derivative contracts		0.55		—		(2.10	)

Combined realized gas price	$	6.97	$	6.60	$	6.05

Gas Equivalents ($/Mcfe):
Combined realized price	$	9.02	$	8.65	$	8.04

We estimate a realized gain or loss on derivative contracts for the twelve months ending June 30, 2010 based upon the derivative contracts, which we sometimes refer to as hedging arrangements, that we have entered into, as detailed below. For the twelve months ending June 30, 2010, we have hedging arrangements covering an average 948 barrels of oil per day at a weighted average price of $83.55 per barrel and 9,869 Mcf of gas per day at a weighted average price of $8.34 per MMbtu, or 71% of our total estimated daily production. These hedging arrangements result in a realized gain of $23.55 per barrel and a realized gain of $3.09 per Mcf for the volumes subject to the derivative contracts and a realized gain of $18.05 per barrel and a realized gain of $2.10 per Mcf when applied to our total estimated production for the twelve months ending June 30, 2010. We have elected out of hedge accounting as prescribed by applicable accounting rules. For more information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Accounting for Derivatives.” Gas, including NYMEX futures, spot prices and hedging arrangements, is priced in MMbtu; however, gas volumes are typically reported in Mcf (1 MMbtu equals 1 Mcf of gas with a heating value of 1,000 Btu). We have presented gas prices in Mcf, unless the prices are directly related to a hedging arrangement. For the year ended December 31, 2008, we realized a loss of $13.75 per barrel of oil and a loss of $0.55 per Mcf of gas on our derivative contracts and for the twelve months ended March 31, 2009, we realized a loss of $2.88 per barrel of oil.

The following table summarizes our oil derivative contracts at May 8, 2009:


	NYMEX-based Fixed Price Swaps
	Barrels per day	Price ($/Bbl)
Year 2009	1,000	$	83.80
Year 2010	895	$	83.26
Year 2011	810	$	86.45
Year 2012	670	$	67.60

Index to Financial Statements

The following table summarizes our gas derivative contracts at May 8, 2009:


	NYMEX-based Fixed Price Swaps
	MMbtu per day	Price ($/MMbtu)
Year 2009	10,595	$	8.45
Year 2010	9,130	$	8.22
Year 2011	8,010	$	8.10
Year 2012	3,000	$	6.88

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

Oil and Gas Revenues. The following table illustrates the primary components of our oil and gas revenues and our realized loss (gain) on derivative contracts for the year ended December 31, 2008 and the twelve months ended March 31, 2009, and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Twelve Months Ended March 31, 2009			Estimated Twelve Months Ending June 30, 2010
	(In thousands)
Oil revenues	$	42,003	$	36,998		$	24,142
Gas revenues		41,388		36,207			20,932

Total oil and gas revenues	$	83,391	$	73,205		$	45,074

Realized loss (gain) on oil derivative contracts	$	6,220	$	1,356		$	(8,147	)
Realized loss (gain) on gas derivative contracts		3,047		(1	)		(11,143	)

Total realized loss (gain) on derivative contracts	$	9,267	$	1,355		$	(19,290	)

We estimate oil and gas revenues for the twelve months ending June 30, 2010 based upon our estimated production multiplied by the estimated average NYMEX price less the estimated differential. Realized loss (gain) on derivative contracts is based upon our hedging arrangements and reflect the difference between the estimated NYMEX price and the weighted average price in our derivative contracts for the production volumes subject to our derivative contracts for the twelve months ending June 30, 2010. At May 8, 2009 and continuing through December 2012, we had NYMEX-based fixed price commodity swaps covering approximately 80% (85% for 2009-2011 and 60% for 2012) of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $81.08 per barrel of oil and $8.14 per MMbtu of gas. For the year ended December 31, 2008 and the twelve months ended March 31, 2009, our oil and gas revenues were $83.4 million and $73.2 million, respectively.

Gas comprises 66% and oil comprises 34% of our total estimated production for the twelve months ending June 30, 2010. As a consequence, our revenues are more sensitive to changes in gas prices than to changes in oil prices. The following tables show estimated Adjusted EBITDA sensitivities under various assumed NYMEX gas and oil prices for the twelve months ending June 30, 2010. The estimated Adjusted EBITDA amounts shown below are based on realized gas prices that take into account our average NYMEX gas price differential assumption of $1.30 and realized oil prices that take into account our average NYMEX oil price differential assumption of $6.50 and also include realized gains and losses on derivative contracts based on our current hedging arrangements. We have assumed no changes in our production based on changes in prices and that our swap counter-party will perform as expected.

Index to Financial Statements


Gas Price Sensitivities:	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data and percentages)
NYMEX gas price ($/Mcf)	$	4.25		$	5.25		$	6.25		$	7.25
NYMEX oil price ($/Bbl)	$	60.00		$	60.00		$	60.00		$	60.00
Equivalent daily production (Mcfepd)		21,936			21,936			21,936			21,936
Percentage gas		66	%		66	%		66	%		66	%
Total revenues	$	39,707		$	45,074		$	50,460		$	55,868
Lease operating expenses		13,639			13,639			13,639			13,639
Production taxes		3,772			4,282			4,794			5,307
General and administrative		3,566			3,566			3,566			3,566
Equity-based compensation		200			200			200			200
Realized loss (gain) on derivative contracts		(22,892	)		(19,290	)		(15,688	)		(12,086	)

Adjusted EBITDA	$	41,422		$	42,677		$	43,949		$	45,242


Oil Price Sensitivities:	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data and percentages)
NYMEX oil price ($/Bbl)	$	40.00		$	50.00		$	60.00		$	70.00
NYMEX gas price ($/Mcf)	$	5.25		$	5.25		$	5.25		$	5.25
Equivalent daily production (Boepd)		3,656			3,656			3,656			3,656
Percentage oil		34	%		34	%		34	%		34	%
Total revenues	$	35,989		$	40,528		$	45,074		$	49,626
Lease operating expenses		13,639			13,639			13,639			13,639
Production taxes		3,419			3,850			4,282			4,714
General and administrative		3,566			3,566			3,566			3,566
Equity-based compensation		200			200			200			200
Realized loss (gain) on derivative contracts		(26,210	)		(22,750	)		(19,290	)		(15,830	)

Adjusted EBITDA	$	41,375		$	42,023		$	42,677		$	43,337

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

For the year ended December 31, 2008 and the three months ended March 31, 2009, approximately 43% and 49%, respectively, of our production was produced from our properties located in the Rocky Mountain and Mid-Continent regions of the United States. Historically, production from these regions has experienced times of widening differentials from NYMEX. Approximately 45% of our total estimated production for the twelve months ending June 30, 2010 is estimated to be produced from our properties located in the Rocky Mountain and Mid-Continent regions of the United States. The following table shows estimated Adjusted EBITDA sensitivities under various assumed differentials to NYMEX for the twelve months ending June 30, 2010. The estimated Adjusted EBITDA amounts shown below are based on estimated average NYMEX prices of $60.00 per barrel of oil and $5.25 per Mcf of gas for the twelve months ending June 30, 2010 for the volumes not subject to our

Index to Financial Statements

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


	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data)
NYMEX oil price ($/Bbl)	$	60.00		$	60.00		$	60.00		$	60.00
Oil price differential ($/Bbl)	$	5.00		$	6.50		$	7.50		$	10.00
NYMEX gas price ($/Mcf)	$	5.25		$	5.25		$	5.25		$	5.25
Gas price differential ($/Mcf)	$	1.00		$	1.30		$	1.50		$	2.00
Equivalent daily production (Mcfepd)		21,936			21,936			21,936			21,936
Total revenues	$	47,510		$	45,074		$	43,459		$	39,455
Lease operating expenses		13,639			13,639			13,639			13,639
Production taxes		4,513			4,282			4,129			3,748
General and administrative		3,566			3,566			3,566			3,566
Equity-based compensation		200			200			200			200
Realized loss (gain) on derivative contracts		(19,290	)		(19,290	)		(19,290	)		(19,290	)

Adjusted EBITDA	$	44,882		$	42,677		$	41,215		$	37,592

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

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


	Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data and percentages)
Percentage of estimated production		95	%		100	%		105	%
NYMEX oil price ($/Bbl)	$	60.00		$	60.00		$	60.00
NYMEX gas price ($/Mcf)	$	5.25		$	5.25		$	5.25
Equivalent daily production (Mcfepd)		20,839			21,936			23,033
Total revenues	$	42,820		$	45,074		$	47,327
Lease operating expenses		12,957			13,639			14,321
Production taxes		4,068			4,282			4,496
General and administrative		3,566			3,566			3,566
Equity-based compensation		200			200			200
Realized loss (gain) on derivative contracts		(19,290	)		(19,290	)		(19,290	)

Adjusted EBITDA	$	41,319		$	42,677		$	44,034

Index to Financial Statements

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

Capital Expenditures and Expenses

Capital Expenditures. We estimate that our cash capital expenditures for the twelve months ending June 30, 2010 will be approximately $10.7 million as compared to $26.2 million, $12.3 million and $131.9 million, respectively, on a pro forma basis for the years ended December 31, 2006, 2007 and 2008. For the twelve months ended March 31, 2009, our capital expenditures were $14.7 million. The historical amounts reflect the actual capital expenditures spent on our properties, including capital expenditures of $118.5 million for property acquisitions for the year ended December 31, 2008. The $10.7 million of capital expenditures for the twelve months ending June 30, 2010, which we refer to as maintenance capital expenditures, are expected to consist of new wells and a number of recompletion and workover projects on our existing properties. We believe that we would have sufficient cash to pay the full initial quarterly distribution for four quarters on all of our units with maintenance capital expenditures of up to approximately $14.0 million for the twelve months ending June 30, 2010. For the twelve months ending June 30, 2010, we have planned our development drilling to minimize the decline rate from our current production levels due to the current economic environment of low commodity prices and relatively high service costs. Over the long-term we expect service costs and commodity prices to be more balanced and we intend to set aside sufficient cash reserves or make sufficient capital expenditures to maintain our current production levels. Historically, on the properties contributed to us by Abraxas Petroleum, we have added 1.0 Mcfepd of production for every $3,300 of capital expended. We have used this historical average in our production estimate for the twelve months ending June 30, 2010 because we anticipate that most of our capital spending will be made on the properties contributed to us by Abraxas Petroleum. We expect to finance these maintenance capital expenditures out of cash flow from operations. We intend to fund growth capital with a combination of cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities. We cannot assure you that any of these sources of capital will be available to us either in the amounts necessary or on terms acceptable to us.

Lease Operating Expenses. The following table summarizes lease operating expenses on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2008 and the twelve months ended March 31, 2009, and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008		Twelve Months Ended March 31, 2009		Estimated Twelve Months Ending June 30, 2010
	(In thousands, except per unit data)
Lease operating expenses	$	14,608	$	15,566	$	13,639
Lease operating expenses ($/Mcfe)	$	1.78	$	1.87	$	1.70

We estimate that our lease operating expenses for the twelve months ending June 30, 2010 will be approximately $13.6 million as compared to $15.6 million for the twelve months ended March 31, 2009.

Production Taxes. The following table summarizes production taxes, which include ad valorem taxes, on an aggregate basis and as a percentage of oil and gas revenues for the year ended December 31, 2008 and the twelve months ended March 31, 2009, and on an estimated basis for the twelve months ending June 30, 2010:


	Year Ended December 31, 2008			Twelve Months Ended March 31, 2009			Estimated Twelve Months Ending June 30, 2010
	(In thousands, except percentages)
Oil and gas revenues	$	83,391		$	73,205		$	45,074
Production taxes	$	7,968		$	7,389		$	4,282
Production taxes as a percentage		9.6	%		10.0	%		9.5	%

Index to Financial Statements

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

General and Administrative Expenses. We estimate that our general and administrative expenses for the twelve months ending June 30, 2010 will be approximately $3.6 million, which includes $0.8 million of incremental expenses that we expect to incur as a result of being a publicly traded partnership. We expect our incremental expenses will include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, and director, accounting, reservoir engineering and legal fees. Pursuant to our omnibus agreement, we currently pay Abraxas Petroleum $2.6 million per year, and will continue to pay this amount until the second anniversary of the closing of this offering, for general and administrative expenses, subject to annual adjustments for inflation and acquisition or other expansion adjustments. For more information, please read “Certain Relationships and Related Party Transactions—Omnibus Agreement.”

Interest Expense. We intend to use the net proceeds from this offering, together with our general partner’s proportionate capital contribution, to partially repay the indebtedness outstanding under our subordinated credit facility. We have estimated $10.3 million of net cash interest expense for the twelve months ending June 30, 2010. In addition, we have also estimated that we will fund our maintenance capital expenditures for the twelve months ending June 30, 2010 of $10.7 million out of cash flow from operations.

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

•

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

•

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

•

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

Distributions

Distributions on our units for the twelve months ending June 30, 2010 are expected to be $15.8 million in the aggregate (assuming no exercise of the over-allotment option). Quarterly distributions will be paid within 45 days after the close of each quarter.

How We Make Cash Distributions

Distributions of Available Cash

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

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

•

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

•

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

•

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

Index to Financial Statements

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.

Index to Financial Statements

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

The following table shows selected historical consolidated financial data of Abraxas Petroleum and our historical and pro forma consolidated financial data for the periods and as of the dates indicated. The selected consolidated historical financial data as of and for the years ended December 31, 2004, 2005 and 2006, and the periods from January 1 to May 24, 2007 and from May 25 to December 31, 2007, and as of and for the year ended December 31, 2008 are derived from Abraxas Petroleum’s and our audited consolidated financial statements. The selected condensed consolidated historical financial data as of March 31, 2009 and for the three months ended March 31, 2008 and 2009 are derived from our unaudited condensed consolidated financial statements. The financial condition and results of operations of Abraxas Petroleum for the periods up to May 24, 2007 are referred to in this prospectus as “Predecessor,” and the financial condition and results of operations for periods subsequent to May 24, 2007 are referred to as “Successor” and represent only those of Abraxas Energy. The selected pro forma consolidated financial data for the year ended December 31, 2008 and the three months ended March 31, 2009 are derived from our unaudited pro forma consolidated financial statements included in this prospectus beginning on page F-2 and give effect to the St. Mary Acquisition and the completion of this offering and the use of proceeds from this offering as described in “Use of Proceeds.”

The unaudited pro forma consolidated statement of operations data for the year ended December 31, 2008 assume that the St. Mary Acquisition and this offering occurred on January 1, 2008. The unaudited pro forma consolidated statement of operations data for the three months ended March 31, 2009 assume this offering occurred on January 1, 2008 and the unaudited pro forma consolidated balance sheet data as of March 31, 2009 assume this offering occurred on March 31, 2009.

Index to Financial Statements


	Predecessor											Successor
	Abraxas Petroleum											Abraxas Energy
	Year Ended December 31,								January 1 - May 24,			May 25 - December 31,			Year Ended December 31,			Three Months Ended March 31, (unaudited)			Three Months Ended March 31, (unaudited)
	2004			2005		2006			2007			2007			2008			2008			2009
	(In thousands, except per share/unit data)
Consolidated Statements of Operations Data:
Operating revenue:
Oil and gas production revenues	$	33,073		$	47,905	$	49,448		$	18,791		$	22,148		$	83,391		$	18,816		$	8,630
Other(1)		781			1,311		1,629			514			—			—			—			—

Total operating revenue		33,854			49,216		51,077			19,305			22,148			83,391			18,816			8,630
Operating costs and expenses:
Lease operating and production taxes		8,567			11,094		11,776			4,757			5,136			22,577			4,426			4,804
Depreciation, depletion and amortization		7,213			8,914		14,939			5,773			7,039			20,063			4,504			3,526
Ceiling-test impairment		—			—		—			—			—			97,121			—			2,775
General and administrative		5,238			5,757		5,160			1,867			987			2,657			514			807
Other		671			756		819			295			—			—			—			—

Total operating expenses		21,689			26,521		32,694			12,692			13,162			142,418			9,444			11,912

Operating income (loss)		12,165			22,695		18,383			6,613			8,986			(59,027	)		9,372			(3,282	)
Net interest expense		17,857			13,970		16,738			6,371			1,774			10,181			2,431			2,436
Amortization of deferred financing fees		1,848			1,589		1,591			632			121			988			184			202
Financing fees		1,657			—		—			—			—			359			—			362
(Gain) on debt redemption		(12,561	)		—		—			—			—			—			—			—
Loss (gain) on derivative contracts		—			591		(646	)		218			4,125			(28,333	)		26,958			(12,865	)
Loss on debt extinguishment		—			—		—			—			6,455			—			—			—
Other expense		387			274		—			—			—			1,105			—			21

Income (loss) from continuing operations before income tax		2,977			6,271		700			(608	)		(3,489	)		(43,327	)		29,573			(9,844	)
Income tax (benefit)		(6,060	)		—		—			—			—			—			—			—

Income (loss) from continuing operations(3)	$	9,037		$	6,271	$	700		$	(608	)	$	(3,489	)	$	(43,327	)	$	(20,201	)	$	6,562

Income (loss) per common share/unit from continuing operations—diluted	$	0.23		$	0.15	$	0.02		$	(0.01	)	$	(0.31	)	$	(3.81	)	$	(1.78	)	$	0.58

Weighted average common shares/units outstanding—diluted(2)		38,895			41,164		43,862			42,795			11,362			11,360			11,362			11,411

(1)	Includes rig and other revenue.

(2)

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

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

Index to Financial Statements


	Pro Forma						Pro Forma
	Abraxas Energy						Abraxas Energy
	St. Mary Acquisition			After Offering			After Offering
	Year Ended December 31,						Three Months Ended March 31,
	2008						2009
	(In thousands, except per unit data)
Unaudited Consolidated Statements of Operations Data:
Oil and gas production revenue	$	87,045		$	87,045		$	8,630
Lease operating and production taxes		23,621			23,621			4,804
Depreciation, depletion and amortization		20,955			20,955			3,526
General and administrative		2,657			2,657			807
Net interest expense		10,704			9,396			1,933
Amortization of deferred financing fees		1,054			1,054			202
Financing Fees		359			359			362
Loss (gain) on derivative contracts		(28,333	)		(28,333	)		(12,865	)
Ceiling-test impairment		97,121			97,121			2,775
Other		1,105			1,105			21

Net income (loss)	$	(42,198	)	$	(40,888	)	$	7,065

Net income (loss) per common unit-basic	$	(3.71	)	$	(2.59	)	$	0.45

Common units outstanding-basic		11,360			15,779			15,779


															Successor
															Pro Forma After Offering
	Predecessor									Successor					(unaudited)
	Abraxas Petroleum									Abraxas Energy					Abraxas Energy
	At December 31,									At December 31,		At December 31,			At March 31,
	2004			2005			2006			2007		2008			2009
	(In thousands)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	(4,592	)	$	(4,880	)	$	(3,719	)	$	3,740	$	(14,595	)	$	(11,983	)	$	6,547
Total assets		152,685			121,866			116,940			105,703		169,240			169,991			169,991
Current maturities of long-term debt		—			—			—			—		40,000			40,000			21,470
Long-term debt		126,425			129,527			127,614			45,900		125,600			125,600			125,600
Stockholders’/partners’ equity (deficit)		(53,464	)		(23,701	)		(22,165	)		49,688		(12,492	)		(8,457	)		10,073
Other Data:
Capital expenditures for the period	$	9,269		$	35,350		$	26,346		$	20,708	$	131,900		$	2,295		$	2,295

Index to Financial Statements

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

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

Overview

General

We are a holding company, and our operating assets are owned directly or indirectly by our operating subsidiary, Abraxas Operating. Our general partner is a wholly-owned subsidiary of Abraxas Petroleum, and has sole responsibility for conducting our business and managing our operations. Upon the completion of this offering, Abraxas Petroleum will continue to beneficially own a 2% general partner and a 33.9% limited partner interest in us, assuming the underwriters do not exercise their over-allotment option to purchase additional common units and redeemable warrants and that Abraxas Petroleum does not purchase any common units and redeemable warrants in this offering.

Basis of Presentation

Because we were not formed until May 2007, our historical financial statements as well as the discussion of the results of operations and period-to-period comparisons covering these historical results include the historical financial statements of Abraxas Petroleum for periods up to May 24, 2007 and our historical financial statements for the period from May 25 to December 31, 2007, the year ended December 31, 2008 and the three months ended March 31, 2008 and 2009. Because the 2007 historical results of Abraxas Petroleum include combined information for the properties retained by Abraxas Petroleum as well as our oil and gas properties, these historical results of operations and period-to-period comparisons are not indicative of our future results. Please see “Selected Historical and Pro Forma Consolidated Financial and Operating Data” and our Unaudited Historical Pro Forma Consolidated Financial Statements for financial information relating to us, as of the dates and for the periods indicated.

Formation Transactions

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

•

Abraxas Petroleum contributed properties to Abraxas Operating;

•

Index to Financial Statements

•

we borrowed $35.0 million under our credit facility; and

•

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

•

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

•

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

•

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

•

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

St. Mary Acquisition

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

How We Evaluate Our Operations

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

•

the oil and gas volumes we produce;

•

the sales price of our oil and gas production and the effect of our hedging activities;

•

the level of our operating and general and administrative expenses;

•

the availability of capital;

•

the level of and interest rates on borrowings; and

•

the level and success of exploitation and development activity.

Production Volumes. Because our proved reserves will decline as oil and gas are produced, unless we conduct successful exploitation and development activities, or acquire additional properties containing proved reserves, our reserves and production will decrease. Approximately 92% of the estimated ultimate recovery of our proved developed reserves as of December 31, 2008 had been produced. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploitation and development projects.

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

Index to Financial Statements

The following table presents historical net production volumes for the years ended December 31, 2006, 2007 and 2008 and the three months ended March 31, 2009:


	Year Ended December 31,			Three Months Ended March 31,
	2006	2007	2008	2009
Total production (MMcfe)	7,718	5,984	8,218	2,012
Average daily production (Mcfepd)	21,144	16,394	22,453	22,360

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

Substantially all of our oil and gas sales are made in the spot market, or pursuant to contracts based on spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices we receive for our oil and gas are dependent upon numerous factors beyond our control. Significant declines in commodity prices could have a material adverse effect on our financial condition, results of operations, quantities of reserves recoverable on an economic basis, and the distributions we can make to our unitholders. Recently, oil and gas prices have been volatile. Supply and geopolitical uncertainties resulted in significant price volatility during 2008 with oil prices rising during the first half of the year to record levels before falling by approximately 70% during the second half of the year. Commodity prices, particularly gas prices, continued to decline during the first quarter of 2009. Spot prices for West Texas Intermediate (WTI) oil averaged $100.21 per barrel during 2008, with a low price of $33.87 per barrel in December 2008 and a high price of $145.28 per barrel in July 2008. During 2008, the gas market continued to be driven by high storage inventories and mild weather conditions across much of the country. Spot prices for Henry Hub gas averaged $8.88 per MMbtu for the year, with a low price of $5.40 per MMbtu in December 2008 and a high price of $13.28 per MMbtu in July 2008. Spot prices for WTI oil averaged $43.19 per barrel and Henry Hub gas averaged $4.55 per MMbtu during the first quarter of 2009. The NYMEX futures prices for oil and gas were $44.60 per barrel and $5.62 per MMbtu at December 31, 2008 and $58.63 per barrel and $4.31 per MMbtu at May 8, 2009. The current global recession has had a significant impact on commodity prices and our operations. If commodity prices remain depressed, our revenues, profitability and cash flow from operations will decrease which could cause us to alter our business plan including reducing our drilling activity and the level of cash distributions to our unitholders.

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

•

basis differentials which are dependent on actual delivery location;

•

adjustments for quality and Btu content; and

•

gathering, processing and transportation costs.

During 2008, our differentials averaged $7.31 per barrel of oil and $1.36 per Mcf of gas and during the first quarter of 2009, our differentials averaged $8.24 per barrel of oil and $1.05 per Mcf of gas. We expect these differentials will decrease as a result of lower commodity prices because the majority of our marketing agreements are based on a percentage of the prevailing market price. On a pro forma basis during 2008, our differentials would have averaged $8.11 per barrel of oil and $1.40 per Mcf of gas before any impact from our derivative contracts.

Our credit facility required us to enter into hedging arrangements for specified volumes, which equated to approximately 85% of our estimated oil and gas production through 2011 and approximately 60% of our estimated oil and gas production for 2012. At May 8, 2009 and continuing through December 2012, we had NYMEX-based fixed price commodity swaps covering approximately 80% of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $81.08 per barrel of oil and $8.14 per MMbtu of gas. We intend to enter into derivative contracts, which we

Index to Financial Statements

sometimes refer to as hedging arrangements, in the future to reduce the impact of oil and gas price volatility on our cash flow. By removing a significant portion of price volatility of our future oil and gas production, we believe we have mitigated, but not eliminated, the potential effects of changing oil and gas prices on our cash flow from operations for those periods; however, any prolonged decrease in commodity prices will reduce our cash available for distribution. We have sustained and in the future we will sustain realized and unrealized losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when our contract prices are higher than prevailing market prices, we will sustain realized and unrealized gains on our derivative contracts. If the prices at which we hedge future production are significantly lower than our current contract prices, we may not be able to pay the initial quarterly distributions on our units in the future if commodity prices remain at depressed levels.

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

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

At May 8, 2009, we had the following derivative contracts in place:


Period Covered	Product	Volume (Production per Day)	Fixed Price
Year 2009	Gas	10,595 MMbtu	$	8.45
Year 2009	Oil	1,000 Bbl	$	83.80
Year 2010	Gas	9,130 MMbtu	$	8.22
Year 2010	Oil	895 Bbl	$	83.26
Year 2011	Gas	8,010 MMbtu	$	8.10
Year 2011	Oil	810 Bbl	$	86.45
Year 2012	Gas	3,000 MMbtu	$	6.88
Year 2012	Oil	670 Bbl	$	67.60

Operating and General and Administrative Expenses

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

Operating Expenses. Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Operating expenses do not include G&A expenses. A majority of our operating cost components are variable and increase or decrease as the level of production increases or decreases. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed and do not fluctuate with changes in production volumes, but can fluctuate depending on activities performed during a specific period. Abraxas Petroleum and Abraxas Operating have entered into an operating agreement, under which Abraxas Petroleum will operate our oil and gas properties that are not subject to operating agreements with other parties. Abraxas Petroleum will continue to operate our properties that are subject to operating agreements, to the extent Abraxas Petroleum is the operator of record. We

Index to Financial Statements

will reimburse Abraxas Petroleum for its costs in performing the services on our behalf under the operating agreements, plus related expenses. Our operating expenses on a per unit basis increased in 2008 as a result of the St. Mary Acquisition because the producing properties we acquired from St. Mary are primarily pumping oil wells which cost more to operate than the producing properties contributed to us from Abraxas Petroleum which are primarily flowing gas wells.

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

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

Availability of Capital. As described more fully under “—Liquidity and Capital Resources” below, our sources of capital going forward will primarily be cash flow from operations, borrowings under our credit facility and proceeds from the sale of debt or equity securities. At May 8, 2009, we had $4.4 million of availability under our credit facility and after giving effect to the application of the net proceeds of this offering, we will have availability of $4.4 million from the current amount of our borrowing base of $130.0 million. For a description of our credit facility, please see “—Liquidity and Capital Resources—Credit Facility.”

Borrowings and Interest. At May 8, 2009, we had outstanding indebtedness of $165.6 million, of which $40.0 million was outstanding under our subordinated credit facility and $125.6 million was outstanding under our credit facility. In 2008, our cash interest expense for a full year would have been $10.2 million on a pro forma basis giving effect to the St. Mary Acquisition as if it had occurred on January 1, 2008. If our cash interest expense increases as a result of higher interest rates or increased borrowings under our credit facility, more cash flow from operations would be used to meet our debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our numerous drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, as amended in February 2009, to fix our floating LIBOR based debt. Our 2-year interest rate swap arrangement for $100.0 million is at a fixed rate of 2.95%. The arrangement expires on August 12, 2010.

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

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire, exploit and develop additional reserves. The rate of production from our properties and our proved reserves will decline as our reserves are produced unless we conduct successful development and exploitation activities, acquire additional properties containing proved reserves, or, through engineering studies that identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploitation and

Index to Financial Statements

development activities will result in increases in our proved reserves. If our proved reserves continue to decline in the future, our production will also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility will also decline, and we may be unable to pay distributions to our unitholders. In addition, approximately 39% of our total estimated proved reserves at December 31, 2008 were undeveloped. By their nature, estimates of undeveloped reserves are less certain than proved developed reserves. Recovery of such reserves will require significant capital expenditures and successful drilling operations. For a more complete discussion of these risks please see “Risk Factors—Risks Related to Our Business—The estimated proved reserves we present are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Outlook

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

•

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

•

the level of consumer product demand;

•

weather conditions;

•

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

•

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

•

technological advances affecting energy consumption and supply;

•

domestic and foreign governmental regulations and taxation;

•

the impact of energy conservation efforts;

•

the price and availability of alternative fuels.

A substantial portion of our estimated production is currently hedged through December 2012, and we intend to continue to enter into derivative contracts in the future, to help mitigate the impact of price volatility on our cash flow. At May 8, 2009 and continuing through December 2012, we had NYMEX-based fixed price commodity swaps covering approximately 80% of our estimated oil and gas production from our estimated net proved developed producing reserves at volume weighted average prices of $81.08 per barrel of oil and $8.14 per MMbtu of gas which are significantly higher than market prices on May 8, 2009 of $58.63 per barrel of oil and $4.31 per MMbtu of gas. While these derivative contracts will protect us when market prices are below our contract prices, they also prevent us from realizing an increase in cash flow when market prices are higher than our contract prices. We will sustain realized and unrealized losses to the extent our contract prices are lower than market prices and conversely, we will sustain realized and unrealized gains to the extent our contract prices are higher than market prices. If the prices at which we hedge future production are significantly lower than our current contract prices, we may not be able to pay the initial quarterly distributions on our units in the future if commodity prices remain at depressed levels.

During the first half of 2008, the increase in commodity prices resulted in increased drilling activity and demand for drilling rigs, equipment and crews. However, during the second half of 2008, commodity prices declined approximately 70% which resulted in reduced drilling activity. Commodity prices, particularly gas prices, continued to decline during the first quarter of 2009. Due to the low commodity price environment, we anticipate drilling service and labor costs, as well as costs of equipment and raw materials, to decline from recent

Index to Financial Statements

historically high levels. Our operating expenses increased in 2008 as a result of the St. Mary Acquisition because the producing properties we acquired from St. Mary were primarily pumping oil wells which cost more to operate than the producing properties contributed to us from Abraxas Petroleum which are primarily flowing gas wells.

We expect to fund our capital expenditures with cash flow from operations, borrowings under our credit facility and the sale of debt or equity securities. We estimate that we will have sufficient cash flow from operations after funding maintenance capital expenditures to enable us to pay the initial quarterly distribution of $0.25 per unit to unitholders for each quarter for the twelve months ending June 30, 2010. Please read “—Liquidity and Capital Resources” and “Cash Distribution Policy and Restrictions on Distributions” for more information.

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

Factors Affecting Comparability of Future Results

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

Historical results include properties retained by Abraxas Petroleum. Because we were not formed until May 2007, our historical financial statements as well as the discussion of the results of operations and period-to-period comparisons covering these historical results include the historical financial statements of Abraxas Petroleum for periods up to May 24, 2007 and our historical financial statements for the period from May 25 to December 31, 2007, the year ended December 31, 2008 and the three months ended March 31, 2009 in this prospectus. Because the historical results of Abraxas Petroleum include combined information for the properties retained by Abraxas Petroleum as well as our oil and gas properties, these historical results of operations and period-to-period comparisons are not indicative of our future results.

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


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

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

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

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

Index to Financial Statements

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

Increase in Outstanding Indebtedness. In order to finance the St. Mary Acquisition, we borrowed a total of $129.7 million ($79.7 million under our credit facility and $50.0 million under our subordinated credit facility), of which $10.0 million represented the deposit we made in December 2007 and was reflected in our long-term debt of $45.9 million at December 31, 2007. For the period from May 25 to December 31, 2007, we paid a total of $1.8 million in interest. Our pro forma cash interest payments for 2008 would have been $9.6 million if the St. Mary Acquisition had occurred on January 1, 2008. We plan to use the net proceeds from this offering to partially repay indebtedness outstanding under our subordinated credit facility. We expect to have approximately $125.6 million outstanding under our credit facility and approximately $21.5 million outstanding under our subordinated credit facility after completion of this offering which, based upon current interest rates and our interest rate swap arrangement, would require interest payments of $11.9 million for a 12-month period. We intend to re-finance the indebtedness outstanding under our subordinated credit facility prior to its scheduled maturity date of July 1, 2009; however there can be no assurance that we will be successful in this effort. We have engaged an exclusive financial advisor to assist us in this re-financing.

We will experience realized and unrealized losses and gains on our derivative contracts. At May 8, 2009 and continuing through December 2012, we had NYMEX-based fixed price commodity swaps covering approximately 80% (85% for 2009-2011 and 60% for 2012) of our estimated net proved developed producing reserves at volume weighed average prices of $81.08 per barrel of oil and $8.14 per MMbtu of gas. At May 8, 2009, NYMEX futures prices were $58.63 per barrel of oil and $4.31 per MMbtu of gas. Because these derivative contracts, which we sometimes refer to as hedging arrangements, have at times been less and greater than then-current market prices, we have sustained both realized and unrealized losses and gains on our derivative contracts. In the future, we will sustain losses if market prices are higher than our contract prices and, conversely, we will sustain gains if market prices are lower than our contract prices. During the year ended December 31, 2008, we realized prices of $92.89 per barrel of oil and $7.52 per Mcf of gas before any impact from our derivative contracts and we recognized a realized loss of $(9.3) million and an unrealized gain of $40.5 million on our commodity derivative contracts. During the three months ended March 31, 2009, we realized prices of $34.95 per barrel of oil and $3.50 per Mcf of gas before any impact from our derivative contracts resulting in revenues less direct cash expenses of $583,000 and we recognized a realized gain of $7.0 million and an unrealized gain of $6.3 million on our commodity derivative contracts. If the disparity between our contract prices and market prices continues, we will continue to sustain realized and unrealized gains and losses on our derivative contracts. While unrealized gains and losses do not impact our cash flow from operations or cash available for distribution, realized gains and losses impact both. In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than our current contract prices, we may not be able to pay the initial quarterly distributions on our units in the future if commodity prices remain at depressed levels.

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

Index to Financial Statements

Results of Operations

Comparison of Three Months Ended March 31, 2008 and 2009

The following table illustrates the primary components of revenue for the three months ended March 31, 2008 and 2009, as well as oil and gas sales volumes and average realized prices (net of impact from derivative contracts) for such periods.


	Three Months Ended March 31,
	2008		2009
	(In thousands, except per unit data)
Operating revenue:
Oil sales	$	8,979	$	3,975
Gas sales		9,837		4,655
Total operating revenue		18,816		8,630
Operating income (loss)(1)		9,372		(3,282	)
Volumes:
Oil (MBbls)		96		114
Gas (MMcf)		1,348		1,330
Gas equivalents (MMcfe)		1,922		2,012
Realized oil price ($/Bbl)	$	81.22	$	67.08
Realized gas price ($/Mcf)	$	7.54	$	6.04

(1)	Operating loss in the three months ended March 31, 2009 includes $2.8 million ceiling-test impairment.

The following table summarizes our expenses for the three months ended March 31, 2008 and 2009.


	Three Months Ended March 31,
	2008		2009
	(In thousands)
Direct operating expenses:
Lease operating expenses	$	2,775	$	3,733
Production and other taxes		1,651		1,071
Total direct operating expenses	$	4,426	$	4,804

Revenues

Operating Revenue

Operating revenue decreased by $10.2 million from $18.8 million in the three months ended March 31, 2008 to $8.6 million in the same period of 2009. The decrease was primarily due to significant decreases in commodity prices during the three months ended March 31, 2009 compared to the same period of 2008. Excluding the realized gains or losses on our derivative contracts, our realized prices for the three months ended March 31, 2009 were $34.95 per barrel of oil and $3.50 per Mcf of gas compared to $93.88 per barrel of oil and $7.30 per Mcf of gas in the same period of 2008. Oil volumes increased from 96 MBbls in the three months ended March 31, 2008 to 114 MBbls in the same period of 2009 and gas volumes were 1.3 Bcf during both periods. The increase in oil volumes was primarily due to the production attributable to the properties we acquired from St. Mary in January 2008.

Average realized prices for the three months ended March 31, 2009 (net of realized gain on derivative contracts) were $67.08 per barrel of oil and $6.04 per Mcf of gas and average realized prices in the same period of 2008 (net of realized loss on derivative contracts) were $81.22 per barrel of oil and $7.54 per Mcf of gas.

Index to Financial Statements

Expenses

Direct Operating Expenses

Direct operating expenses increased from $4.4 million in the three months ended March 31, 2008 to $4.8 million in the same period of 2009. Direct operating expenses on a per Mcfe basis for the three months ended March 31, 2008 were $2.30 per Mcfe compared to $2.39 per Mcfe in the same period of 2009. The increase in direct operating expenses was primarily attributable to the producing properties we acquired from St. Mary in January 2008 which were predominately pumping oil wells which cost more to operate than the producing properties contributed to us by Abraxas Petroleum which were predominately flowing gas wells.

General and Administrative (“G&A”)

G&A, excluding equity-based compensation, increased from $0.5 million in the three months ended March 31, 2008 to $0.8 million in the same period of 2009. G&A on a per Mcfe basis increased from $0.28 in the three months ended March 31, 2008 to $0.38 in the same period of 2009. The increase in G&A was primarily a result of additional staff hired to manage the producing properties we acquired from St. Mary in January 2008.

Equity-Based Compensation

The Black-Scholes option pricing model is used to measure the fair value of restricted units granted to employees and directors. Restricted units granted to employees and directors are valued at the date of grant and expense is recognized over the vesting period. For the three months ended March 31, 2009 and 2008, equity-based compensation expense was $47,000 and $0, respectively.

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

DD&A decreased by $1.0 million from $4.5 million in the three months ended March 31, 2008 to $3.5 million in the same period of 2009. DD&A on a per Mcfe basis for the three months ended March 31, 2008 was $2.34 per Mcfe as compared to $1.75 per Mcfe in the same period of 2009. The decrease in DD&A was primarily the result of a reduction in the depletion base as a result of the proved property impairment recorded for the year ended December 31, 2008 and the three months ended March 31, 2009.

Interest Expense

Interest expense was $2.4 million for the three months ended March 31, 2009 and 2008.

Income (loss) from derivative contracts

Accounting for gains and losses on our derivative contracts is based on realized and unrealized amounts. The realized gains and losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark-to-market valuation of our current derivative contracts. Our derivative contracts do not qualify for hedge accounting as prescribed by SFAS 133; therefore, fluctuations in the market value of these contracts are recognized in earnings during the current period. We have entered into a series of NYMEX-based fixed price commodity swaps, and as of March 31, 2009, the estimated unearned value of these contracts was an asset of approximately $46.1 million. For the three months ended March 31, 2009, we recognized a realized gain of $7.0 million and an unrealized gain of $6.3 million on these derivative contracts compared to a realized loss of ($0.9) million and an unrealized loss of $(26.1) million for the three months ended March 31, 2008.

For the three months ended March 31, 2009, we recognized a realized loss of approximately $(0.6) million and an unrealized gain of $81,000 on this derivative contract. As of March 31, 2009, the estimated unearned value of this contract was a liability of approximately $3.0 million.

Index to Financial Statements

Ceiling-Test Impairment

We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our partners’ equity. The cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production, using commodity prices on the last day of the quarter, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the our financial statements. As of March 31, 2009, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $32.4 million. These amounts were calculated utilizing NYMEX prices on March 31, 2009. Subsequent to March 31, 2009, oil and gas prices increased such that our net capitalized costs only exceeded the present value of our estimated proved reserves by $2.8 million as determined using NYMEX prices on May 7, 2009 of $58.32 per barrel of oil and $4.00 per Mcf of gas.

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

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

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


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

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

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

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

Index to Financial Statements

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


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

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

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

Revenues

Operating Revenue

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

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

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

Expenses

Direct Operating Expenses

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

General and Administrative (“G&A”)

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

Equity-Based Compensation

The Black-Scholes option pricing model is used to measure the fair value of stock/unit options granted to employees and directors. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. For the year ended December 31, 2007, equity-based compensation expense was $393,000. On January 31, 2008, we awarded phantom units with distribution equivalency rights under our long-term incentive plan. For the year ended December 31, 2008, we incurred equity-based compensation expense of $242,000 relating to these phantom units.

Index to Financial Statements

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

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

Interest Expense

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

Income (loss) from derivative contracts

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

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

Ceiling-Test Impairment

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

Index to Financial Statements

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

Revenues

Operating Revenue

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

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

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

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

Expenses

Direct Operating Expenses

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

General and Administrative (“G&A”)

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

Index to Financial Statements

Equity-Based Compensation

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

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

Interest Expense

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

Liquidity and Capital Resources

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

•

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 our continued operations, are summarized in the following table and discussed in further detail below:


	Year Ended December 31,									Three Months Ended March 31,
	2006			2007			2008			2009
		(In thousands)
Net cash provided by operating activities	$	15,561		$	15,616		$	30,474		$	5,925
Net cash used in investing activities		(14,102	)		(20,708	)		(131,900	)		(2,293	)
Net cash (used in) provided by financing activities		(1,458	)		8,637			101,591			(4,943	)

Total	$	1		$	3,545		$	165		$	(1,311	)

Index to Financial Statements

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

Operating activities for the year ended December 31, 2007 provided Abraxas Petroleum and Abraxas Energy with $15.6 million of cash. Net income plus non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $8.6 million during 2007. Investing activities used $20.7 million during 2007 including $10.7 million for the development of existing properties and a $10.0 million deposit paid in December 2007 for the properties acquired from St. Mary in January 2008.

Operating activities for the year ended December 31, 2008 provided Abraxas Energy with $30.5 million of cash. Financing activities provided $101.6 million during the year ended December 31, 2008 to fund the St. Mary Acquisition. Investing activities used $131.9 million during the year ended December 31, 2008 predominately to acquire the properties from St. Mary, and for the development of our oil and gas properties.

Operating activities for the three months ended March 31, 2009 provided Abraxas Energy with $5.9 million of cash including a $7.0 million realized gain on our derivative contracts. Financing activities used $4.9 million during the three months ended March 31, 2009, of which $4.3 million was used to pay cash distributions. Investing activities used $2.3 million during the three months ended March 31, 2009 for the development of our oil and gas properties.

Capital Expenditures. Capital expenditures made by Abraxas Petroleum and us related to the properties contributed to us by Abraxas Petroleum were $14.4 million and $7.0 million in 2006 and 2007, respectively. During 2006 and 2007, capital expenditures were primarily for development and exploitation activities on our properties. For the year ended December 31, 2008, our cash capital expenditures excluding the St. Mary Acquisition were $13.4 million. We anticipate making capital expenditures of $12.0 million during 2009 for the exploitation and development of our properties, of which $2.3 million was spent during the three months ended March 31, 2009. Our capital expenditures could also include expenditures for acquisition of producing properties if such opportunities arise, but we currently have no agreements, arrangements or undertakings regarding any material acquisitions. We have no material long-term capital commitments and are consequently able to adjust the level of our capital expenditures as circumstances dictate. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of oil and gas continue to decline and if our costs of operations increase or if our production volumes decrease, our cash flow will decrease which may result in a reduction of our budgeted capital expenditures and could also lead to a decrease in cash distributions. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production volume decreases caused by natural field declines.

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

Our cash flow from operations depends heavily on the prevailing prices of oil and gas and our production volumes. Although we have hedged approximately 80% of our estimated oil and gas production from our estimated net proved developed producing reserves through 2012 and intend to continue this practice in the future, declines in oil and gas prices would have a material adverse effect on our overall results, and therefore, our liquidity. Falling oil and gas prices could also negatively affect our ability to raise capital on terms favorable to us or at all.

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

Index to Financial Statements

We plan to make substantial capital expenditures in the future for the acquisition, exploitation and development of oil and gas properties. In estimating the amount of cash that we must generate to pay our initial quarterly distribution to our unitholders for the twelve months ending June 30, 2010, we have estimated that our maintenance capital expenditures for such twelve-month period will be approximately $10.7 million. Maintenance capital expenditures are capital expenditures necessary to replace our reserves and maintain our current level of production. We intend to finance these capital expenditures with cash flow from operations. Growth capital expenditures are capital expenditures necessary to increase our production and grow our asset base. We intend to finance these capital expenditures with a combination of cash flow from operations, borrowings under our credit facility and sales of debt or equity securities.

If cash flow from operations does not meet our expectations, we may fund a portion of our capital expenditures using borrowings under our credit facility, or from other sources, or we may reduce the expected level of capital expenditures or reduce our distributions to unitholders. At May 8, 2009, we had $4.4 million of availability under our credit facility. The current global recession has had a significant impact on commodity prices and our operations. If commodity prices remain depressed, our revenues, profitability and cash flow from operations will decrease which could cause us to alter our business plan including reducing our drilling activity and the level of cash distributions to our unitholders. In addition, the current state of the equity and debt markets has had a significant impact on our ability to access the debt and equity markets on terms as favorable as those which existed prior to the current crisis. If these markets do not improve over time, we may be caused to alter our business plan including reducing our drilling activity and the level of cash distributions to our unitholders.

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

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

Credit Facility. On May 25, 2007, we entered into a senior secured revolving credit facility with Société Générale, as administrative agent and issuing lender, and the lenders signatory thereto, which was amended and restated on January 31, 2008 and further amended on January 16, 2009, April 30, 2009 and May 7, 2009, which we refer to as our credit facility. Our credit facility has a maximum commitment of $300.0 million. Availability under our credit facility is subject to a borrowing base. The borrowing base under our credit facility, which at May 8, 2009 was $130.0 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

Index to Financial Statements

redeterminations and we may also request one redetermination during any six-month period between scheduled redeterminations. The lenders may also make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our current borrowing base. Our borrowing base of $130.0 million was determined based upon our reserve report dated December 31, 2008. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under our credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.5% - 2.5%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (a) 2.0% and (b) LIBOR plus, in each case, 2.5% - 3.5% depending on the utilization of the borrowing base. At May 8, 2009, the interest rate on the facility was 5.5%. Principal payments under our credit facility must be made on or before May 14, 2009 in an amount, which we refer to as the May 14, 2009 Payment Amount, equal to the lesser of the amount of cash distributed to Abraxas Investments, on or about February 14, 2009 and $2.25 million, with the balance due on the maturity date. A principal payment of approximately $1.9 million was due on May 14, 2009 under our credit facility. Abraxas Petroleum, on behalf of Abraxas Investments, repaid the $1.9 million distribution attributable to the fourth quarter of 2008 to us and we, in turn, made the principal payment utilizing these funds. As previously approved by our audit and conflicts committee, in consideration of the return of this distribution, we issued 209,639 common units to Abraxas Investments on May 14, 2009. The number of common units issued was determined by dividing $1.9 million by 110% of the average trading yields of comparable upstream master limited partnerships based on the closing market price on May 14, 2009 multiplied by the most recent quarterly distribution paid or declared by us times four. Subject to earlier termination rights and events of default, the stated maturity date of our credit facility is January 31, 2012. 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 as of the last day of each quarter, of not less than 2.50 to 1.00. Under the terms of our credit facility, the current ratio is the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but exclude any cash deposited with or at the request of a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of SFAS 133 (which relates to derivative instruments and hedging activities) and SFAS 143 (which relates to asset retirement obligations) and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of SFAS 133 and SFAS 143. The interest coverage ratio is the ratio of consolidated EBITDA to consolidated interest expense. For the purposes of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of SFAS 123R (which relates to stock-based compensation), SFAS 133 and SFAS 143 minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. As of March 31, 2009, our current ratio was 27.47 to 1.00 and our interest coverage ratio was 4.58 to 1.00. Our credit facility required us to enter into hedging arrangements for specified volumes, which equated to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2011 and approximately 60% of our estimated oil and gas production for 2012. As of May 8, 2009, we had NYMEX-based fixed price commodity swaps on approximately 80% (85% for 2009-2011 and 60% for 2012) of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2012.

Index to Financial Statements

Under the terms of our credit facility, we may make cash distributions if, after giving effect to such distributions, we are not in default under our credit facility, there is no borrowing base deficiency and provided that (a) no such distribution shall be made using the proceeds of any advance unless the unused portion of the amount then available under our credit facility is greater than or equal to 10% of the lesser of our borrowing base (which at May 8, 2009 was $130.0 million) or the total commitment amount of our credit facility (which is $300.0 million) at such time, (b) with respect to the cash distribution scheduled to be made on or about May 15, 2009 attributable to the first quarter of 2009, no such distribution shall be made unless (i) the sum of unrestricted cash and the unused portion of the amount then available under our credit facility after giving effect to such distribution exceeds $20.0 million, or (ii) our subordinated credit facility shall have terminated and (c) no cash distribution shall exceed $0.44 per unit per quarter while our subordinated credit facility is outstanding. Under the credit facility, the amount of the cash distribution to be made by the Partnership on or about May 14, 2009 attributable to the first quarter of 2009 was to be deposited into an escrow account established with one of the lenders. Rather than paying the funds into an escrow account, the board of directors of the general partner elected to defer the declaration of the cash distribution attributable to the first quarter of 2009 until the distribution may be paid under the terms of our credit facility. We expect to declare and pay this distribution upon the repayment of the indebtedness outstanding under our subordinated credit facility. In addition, if the indebtedness under our subordinated credit agreement has not been repaid on or before July 1, 2009, we are required to pay the lenders a consent fee of $2.4 million. Additionally, while our subordinated credit facility is outstanding, our capital expenditures are limited to $12.5 million.

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

•

incur or guarantee additional indebtedness;

•

transfer or sell assets;

•

create liens on assets;

•

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

•

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

•

permit a change of control.

Our credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Subordinated Credit Facility. On January 31, 2008, we entered into a subordinated credit facility which was amended on January 16, 2009, April 30, 2009 and May 7, 2009 with Société Générale, as administrative agent, The Royal Bank of Canada, as syndication agent, and the lenders signatory thereto, which we refer to as our subordinated credit facility. Our subordinated credit facility has a maximum commitment of $40.0 million. Outstanding amounts under our subordinated credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR, plus in each case (b) 9.0% or, if we elect, at the greater of (a) 2.0% and (b) LIBOR, plus in each case 10.0%. At May 8, 2009, the interest rate on the facility was 12.0%. If our subordinated credit facility is not repaid on or before July 1, 2009, the interest rate will be (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5% and (3) a rate determined by Société Générale as the daily one-month LIBOR, plus in each case (b) 12.0% or, if we elect, at the greater of (a) 2.0% and (b) LIBOR, plus in each case 13.0%. For any interest payment due on or after July 2, 2009, 3.0% per annum of the accrued interest payable shall be capitalized and added to the principal amount of the loan. The maturity date may be accelerated if any of our limited partners, other than Perlman Value Partners, exercises its right to convert its limited partner units into shares of common stock of Abraxas Petroleum pursuant to the terms of the exchange and registration rights agreement dated May 25, 2007, as amended, among Abraxas Petroleum, us and the purchasers named therein. If the initial public

Index to Financial Statements

offering has not been consummated, the date on which the limited partners may first exchange their common units for Abraxas Petroleum common stock is June 30, 2009. Subject to earlier termination rights and events of default, the stated maturity date of our subordinated credit facility is July 1, 2009. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate our subordinated credit facility, and may, from time to time, permanently reduce the lenders’ aggregate commitment under our subordinated credit facility in compliance with certain notice and dollar increment requirements.

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

Under our subordinated credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter, of not less than 2.50 to 1.00. Under the terms of our subordinated credit facility, the current ratio is the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but exclude any cash deposited with or at the request of a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of SFAS 133 (which relates to derivative instruments and hedging activities) and SFAS 143 (which relates to asset retirement obligations) and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of SFAS 133 and SFAS 143. The interest coverage ratio is the ratio of consolidated EBITDA to consolidated interest expense. For the purposes of this calculation, EBITDA is consolidated net income plus interest expense, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of SFAS 123R (which relates to stock-based compensation), SFAS 133 and SFAS 143 minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of SFAS 133 and SFAS 143. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. As of March 31, 2009, our current ratio was 27.47 to 1.00 and our interest coverage ratio was 4.58 to 1.00. Our subordinated credit facility required us to enter into hedging arrangements for specified volumes, which equated to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2011 and approximately 60% of our estimated oil and gas production for 2012 and was consistent with the hedging requirements under our credit facility. As of May 8, 2009, we had NYMEX-based fixed price commodity swaps on approximately 80% (85% of 2009-2011 and 60% for 2012) of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2012.

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

•

incur or guarantee additional indebtedness;

•

transfer or sell assets;

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create liens on assets;

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

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

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permit a change of control.

Our subordinated credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. An event of default would occur if we fail to receive $20.0 million of proceeds from an equity issuance on or before June 30, 2009. We have no intention of pursuing any other equity offerings other than this offering prior to June 30, 2009. However, we do intend to re-finance the

Index to Financial Statements

indebtedness outstanding under our subordinated credit facility prior to its scheduled maturity and we do not expect that any new subordinated or 2nd lien credit facility would contain a similar event of default. In addition, if the indebtedness under our subordinated credit agreement has not been repaid on or before July 1, 2009, we are required to issue warrants to the lenders to purchase 2.5% of the then outstanding units at an exercise price of $0.01 per unit. If the indebtedness under our subordinated credit facility is repaid on or before July 1, 2009, we are required to pay a consent fee of $200,000.

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

Intercreditor and Subordination Agreement. On January 31, 2008, we entered into an intercreditor and subordination agreement which was amended on January 16, 2009 and May 7, 2009 with Société Générale, as administrative agent for the lenders under our credit facility, and Société Générale, as administrative agent for the lenders under our subordinated credit facility, which we refer to as the intercreditor agreement. The intercreditor agreement sets forth the respective rights, obligations and remedies of each party with respect to our assets.

Hedging Activities. Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. Under the terms of our credit facility, we were required to enter into hedging arrangements for specified volumes, which equated to approximately 80% of the estimated oil and gas production through December 31, 2012 from our net proved developed producing reserves.

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

Off-Balance Sheet Arrangements. At March 31, 2009, we had no off-balance sheet arrangements, as defined under SEC regulations, that have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At March 31, 2009 we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

Critical Accounting Policies

The discussion and analysis of financial condition and results of our operations are based upon the consolidated financial statements of Abraxas Energy, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate such estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial

Index to Financial Statements

statements. Below, we have provided expanded discussion of the more significant accounting policies, estimates and judgments. After this offering, the development, selection and disclosure of each of these policies will be discussed with and reviewed by our general partner’s audit committee. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our financial statements. Please read Note 1 of the Notes to the Consolidated Financial Statements of Abraxas Energy for a discussion of additional accounting policies and estimates made by management.

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

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

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

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

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the quality and quantity of available data;

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the interpretation of that data;

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the accuracy of various mandated economic assumptions; and

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the judgment of the persons preparing the estimate.

Our proved reserve information included in this prospectus was predominantly based on evaluations prepared by independent petroleum engineers. As of December 31, 2008, DeGolyer and MacNaughton estimated reserves for approximately 93% of the standardized measure of our properties. Reserve estimates for our

Index to Financial Statements

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

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

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

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

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

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

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

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

SFAS 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. We have elected to use the “modified retrospective” method. Under the “modified retrospective” method, compensation cost is recognized in the financial statements beginning with the

Index to Financial Statements

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

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

SFAS 123R includes several modifications to the way that income taxes are recorded in the financial statements. The expense for certain types of option grants is only deductible for tax purposes at the time that the taxable event takes place, which could cause variability in Abraxas Petroleum’s effective tax rates recorded throughout the year. SFAS 123R does not allow companies to “predict” when these taxable events will take place. Furthermore, it requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flow and increase net financing cash flow in periods after the effective date of the taxable event. These future amounts cannot be estimated, because they depend on, among other things, when employees exercise stock/unit options.

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

Recent Accounting Pronouncements

Statement of Financial Accounting Standards No. 157

Fair Value Measurements (SFAS No. 157)—In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The FASB agreed to defer the effective date of Statement 157 for one year for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. There is no deferral for financial assets and financial liabilities.

Statement of Financial Accounting Standards No. 141R

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and

Index to Financial Statements

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

Statement of Financial Accounting Standards No. 161

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

Statement of Financial Accounting Standards No. 162

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

Securities and Exchange Commission Rule Changes

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

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

New disclosure requirements include:

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

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

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

Index to Financial Statements

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

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

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

Financial Accounting Standards Board ETIF 07-5

In June 2008, the FASB ratified EITF Issue No. 07-5, Determining whether an Instrument (or Embedded Feature) is indexed to an Entity’s Own Stock (“EITF 07-5”). EITF 07-5 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early application is not permitted. EITF 07-5 provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer’s own stock and thus able to qualify for the SFAS No. 133 paragraph 11(a) scope exception. The adoption of this standard has not had a significant impact on our financial position, results of operations or cash flows.

Financial Accounting Standards Board FSP FAS No. 115-2

In April 2009, the FASB issued FSP FAS No. 115-2 and No. 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” FSP SFAS No. 115-2 and SFAS No. 124-2 provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities. FSP SFAS No. 115-2 and SFAS No. 124-2 is effective for interim and annual reporting periods beginning after June 15, 2009 and is effective for us at June 30, 2009. We have not yet determined the impact, if any, that the FSP will have on our financial position, results of operations or cash flows.

Financial Accounting Standards Board FSP FAS No. 157-4

In April 2009, the FASB issued FSP FAS No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” FSP No. 157-4 provides additional authoritative guidance to assist in determining whether a market is active or inactive, and whether a transaction is distressed. FSP No. 157-4 is effective for interim and annual reporting periods beginning after June 15, 2009 and is effective for us at June 30, 2009. We have not yet determined the impact, if any, that the FSP will have on our financial position, results of operations or cash flows.

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

Index to Financial Statements

upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global political and economic conditions. Historically, prices received for oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the year ended December 31, 2008, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flow by approximately $8.3 million for the year.

Hedging Activity and Sensitivity

To achieve more predictable cash flow, we reduce our exposure to fluctuations in the prices of oil and gas. We have and may continue to enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production. Our credit facility required us to enter into hedging arrangements on specified volumes, which equated to approximately 80% of the projected oil and gas production from our net proved developed producing reserves through December 31, 2012. As of May 8, 2009, we had NYMEX-based fixed price commodity swaps on approximately 80% (85% for 2009-2011 and 60% for 2012) of our estimated oil and gas production from our estimated net proved developed producing reserves through December 31, 2012 at volume weighted average prices of $81.08 per barrel of oil and $8.14 per MMbtu of gas.

We adopted SFAS 133 as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. We record our derivative instruments using the same method, accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded in other (income) expense in the current period.

At May 8, 2009, we had the following derivative contracts in place:

Period Covered

Product

Volume

(Production per Day)

Fixed
Price

Year 2009

Gas

10,595 MMbtu

8.45

Abraxas Energy Partners LP S-1/A