UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2012

r TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of Registrant as specified in its charter)

Nevada 74-2584033

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer Identification Number)

18803 Meisner Drive

San Antonio, TX 78258

(Address of principal executive offices)

(210) 490-4788

Registrant’s telephone number, including area code

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of each class: Name of each exchange on which registered:

Common Stock, par value $.01 per share The NASDAQ Stock Market, LLC

Preferred Stock Purchase Rights The NASDAQ Stock Market, LLC

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of

1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing

requirements for the past 90 days. Yes xNo 

Indicate by check mark if the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required

to be submitted and posted pursuant to Rule 405 of Regulation S-T ( §232.405 of this chapter) during the preceding 12 months (or for such shorter period that

the registrant was required to submit and post such files). Yes xNo 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained,

to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to

this Form 10-K. Yes ⊠No 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company.

See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer Accelerated filer x

Non-accelerated filer (Do not check if a smaller reporting company) Smaller reporting company 

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

As of June 30, 2012, the last day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the common stock

held by non-affiliates of the registrant was $274,945,685 based on the closing sale price as reported on The NASDAQ Stock Market.

As of March 12, 2013, there were 92,733,448 shares of common stock outstanding.

Documents Incorporated by Reference :

Document Parts Into Which Incorporated

Portions of the registrant’s Proxy Statement relating to the 2013 Annual

Meeting of Stockholders to be held on May 14, 2013.

Part III
ABRAXAS PETROLEUM CORPORATION

FORM 10-K

TABLE OF CONTENTS

Page

Part I

Item 1. Business 5

Item 1A. Risk Factors 15

Item 1B. Unresolved Staff Comments 29

Item 2. Properties 29

Item 3. Legal Proceedings 37

Item 4. Mine Safety Disclosures 37

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities 38

Item 6. Selected Financial Data 40

Item 7. Management’s Discussion and Analysis of Financial Condition and Results

of Operations 40

Item 7A. Quantitative and Qualitative Disclosure about Market Risk 57

Item 8. Financial Statements and Supplementary Data 58

Item 9. Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure 58

Item 9A. Controls and Procedures 58

Item 9B. Other Information 5 9

Part III

Item 10. Directors, Executive Officers and Corporate Governance 5 9

Item 11. Executive Compensation 5 9

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 5 9

Item 13. Certain Relationships and Related Transactions, and Director Independence 60

Item 14. Principal Accountant Fees and Services 60

Part IV

Item 15. Exhibits and Financial Statement Schedules 61
FORWARD-LOOKING INFORMATION

We make forward-looking statements throughout this report. Whenever you read a statement that is not simply a statement of historical fact (such as

statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “may,” “estimate,” “could,” “potentially” or similar

expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are

reasonable. The forward-looking information contained in this report is generally located in the material set forth under the headings “Business,” “Risk

Factors,” “Properties,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations

as well. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable

estimates of future results or trends. The factors that may affect our expectations regarding our operations include, among others, the following:

· the availability of capital;

· the prices we receive for our production and the effectiveness of our hedging activities;

· our success in development, exploitation and exploration activities;

· our ability to procure services and equipment for our drilling and completion activities;

· our ability to make planned capital expenditures;

· declines in our production of oil and gas;

· our restrictive debt covenants;

· political and economic conditions in oil producing countries, especially those in the Middle East;

· price and availability of alternative fuels;

· our acquisition and divestiture activities;

· weather conditions and events;

· the proximity, capacity, cost and availability of pipelines and other transportation facilities; and

· other factors discussed elsewhere in this report.

GLOSSARY OF TERMS

Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60

degrees Fahrenheit. Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this report.

Terms used to describe quantities of oil and gas:

“Bbl” – barrel or barrels.

“Bcf” – billion cubic feet of gas.

“Bcfe” – billion cubic feet of gas equivalent.

“Boe” – barrels of oil equivalent.

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“MBbl” – thousand barrels.

“MBoe” – thousand barrels of oil equivalent.

“Mcf” – thousand cubic feet of gas.

“Mcfe” – thousand cubic feet of gas equivalent.

“MMBbl” – million barrels.

“MMBoe” – million barrels of oil equivalent.

“MMBtu” – million British Thermal Units of gas.

“MMcf” – million cubic feet of gas.

“MMcfe” – million cubic feet of gas equivalent.

“NGL” – natural gas liquids measured in barrels.

Terms used to describe our interests in wells and acreage:

“Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells.

“Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer or

formation) noted to be productive for the purpose of extracting reserves.

“Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify

completion.

“Exploratory well” is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be

producing in another reservoir, or to extend a known reservoir.

“Gross acres” are the number of acres in which we own a working interest.

“Gross well” is a well in which we own an interest.

“Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross

acres is equivalent to 160 net acres).

“Net well” is the sum of fractional ownership working interests in gross wells.

“Productive well” is an exploratory or a development well that is not a dry hole.

“Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production

of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

Terms used to assign a present value to or to classify our reserves:

“Proved reserves” are those quantities of oil and gas reserves, which, by analysis of geoscience and engineering data, can be estimated with

reasonable certainty to be commercially recoverable - from a given date forward, from known reservoirs, and under defined economic

conditions, operating methods, and government regulations.

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“Proved developed reserves” are those quantities of oil and gas reserves that can be expected to be recovered through existing wells with existing

equipment and operating methods. Additional reserves expected to be obtained through the application of fluid injection or other improved

recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only

after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery

will be achieved.

“Proved developed non-producing reserves” are those quantities of oil and gas reserves that are developed behind pipe in an existing well

bore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, or when

the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the

estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable

of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional

completion work or future recompletion prior to the start of production.

“Proved undeveloped reserves” or “PUDs” are those quantities of oil and gas reserves that are expected to be recovered from new wells on

undrilled acreage or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are

limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other

undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing

productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or

other improved recovery technique is contemplated, unless such techniques have been proven effective by actual tests in the area and in the same

reservoir.

“Probable reserves” are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than

proved reserves but more certain to be recovered than possible reserves.

“Possible reserves” are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than

probable reserves.

“PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or

de-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”).

“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 or de-escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, “Disclosures About Oil and

Gas Producing Activities.”.

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Part I

Information contained in this report represents the operations of Abraxas Petroleum Corporation. The terms “Abraxas,” “we,” “us,”

“our,” or the “Company,” refer to Abraxas Petroleum Corporation, together with its consolidated subsidiaries including Raven Drilling, LLC which

is a wholly owned subsidiary that owns a drilling rig.

Item 1. Business

General

We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United States

and Canada. At December 31, 2012, our estimated net proved reserves were 30.1MMBoe, of which 51% were classified as proved developed, 66% were oil

and NGL’s and 81% of which (on a PV-10 basis) are operated by us. Our daily net production for the year ended December 31, 2012 was 3,937 Boepd, of

which 52.5% was oil or liquids.

Our oil and gas assets are located in four operating regions in the United States, the Rocky Mountain, Mid-Continent, Permian Basin and onshore Gulf

Coast, and in the province of Alberta, Canada. The following table sets forth certain information related to our properties as of and for the year ended

December 31, 2012:

Estimated Net Proved Reserves

Net

Production

Gross

Producing

Wells

Average

Working

Interest

Total Net

Acres (MBoe)

%

Oil/NGL (MBoe)

%

Oil/NGL

Rocky Mountain 1,065 10.26% 60,016 14,980.4 81.6% 560.0 76.1%

Mid-Continent 147 22.53% 5,820 392.7 37.1% 53.3 16.8%

Permian Basin 220 74.81% 42,093 7,130.1 39.2% 472.1 41.5%

Onshore Gulf Coast 64 87.52% 11,468 7,264.7 63.2% 297.7 29.6%

Total United

States 1,496 24.26% 119,397 29,767.9 66.4% 1,383.1 52.0%

Alberta, Canada (1) 8 100.00% 29,440 385.9 53.1% 54.0 64.6%

Total 1,504 24.67% 148,837 30,153.8 66.2% 1,437.1 52.5%

(1) Excludes approximately 22,000 acres subject to a farmout agreement.

Our properties in the Rocky Mountain region are located in the Williston Basin of North Dakota and Montana and in the Green River, Powder River and

Unita Basins of Wyoming and Utah. In this region, our wells produce oil and gas from various reservoirs, including the Niobrara, Turner, Bakken and

Three Forks formations. Well depths range from 7,000 feet down to 14,000 feet.

Our properties in the Mid-Continent region are primarily located in the Arkoma Basin and principally produce gas from the Hartshorne coals at 3,000 feet.

Our properties in the Permian Basin region are primarily located in two sub-basins, the Delaware Basin and the Eastern Shelf. In the Delaware Basin,

our wells are located in Pecos, Reeves, and Ward Counties, Texas and produce oil and gas from multiple stacked formations from the Bell Canyon at 5,000

feet down to the Ellenburger at 16,000 feet. In the Eastern Shelf, our wells are principally located in Coke, Scurry, Midland, Mitchell and Nolan Counties,

Texas and produce oil and gas from the Strawn Reef formation at 5,000 to 7,500 feet and oil from the shallower Clearfork formation at depths ranging from

2,300 to 3,300 feet.

Our properties in the onshore Gulf Coast region are located along the Edwards trend in DeWitt and Lavaca Counties, Texas and in the Portilla field in San

Patricio County, Texas. In the Edwards trend, our wells produce gas from the Edwards formation at a depth of 14,000 feet and in the Portilla field, our wells

produce oil and gas from the Frio sands and the deeper Vicksburg from depths of approximately 7,000 to 9,000 feet. In addition, as the result of the

dissolution of Blue Eagle Energy, LLC, or Blue Eagle, a joint venture targeting the Eagle Ford formation in South Texas, we own a 100 percent interest in

Yoakum, DeWitt County (1,868 net acres), a 18.75 percent interest in WyCross, McMullen County (1,035 net acres) and a 100 percent interest to the base of

the Buda formation in Jourdanton, Atascosa County (4,401 net acres).

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Our properties in the province of Alberta, Canada are located in the Pekisko fairway and the Nordegg/Tomahawk area of Central Alberta in addition to the

Duvernay Shale in central Alberta.

Strategy

Our business strategy is to focus our capital and resources on our core operated basins, maintain financial flexibility and profitably grow production and

reserves. Key elements of our business strategy include:

Focusing our capital and resources on our core operated basins. Our core basins consist of the Williston Basin (Bakken/Three Forks), onshore

Gulf Coast (Eagle Ford shale), Permian Basin and Powder River Basin. Given the current disparity between oil and gas prices, the economics of drilling oil

wells is currently far superior to drilling gas wells. Thus, 95% of our 2013 estimated capital expenditures will be spent in our two primary oil basins drilling

Bakken, Three Forks and Eagle Ford oil wells. The remainder of our capital will be spent drilling two Yates oil wells in the Permian Basin, oil recompletions

in the Gulf Coast and one vertical pressure test in the Duvernay shale in the province of Alberta, Canada. Furthermore, as part of our efforts to focus our

property portfolio, we are continually marketing assets we have deemed non-core. This includes assets with a low working interest, assets that are nonoperated and/or assets that fall outside of our four core basins. Any proceeds from these asset sales will be used to reduce our indebtedness and/or redeployed

into our core operating basins.

Maintaining financial flexibility. Our primary sources of capital are availability under our credit facility and cash flow from operations. We seek to

reduce the volatility of our cash flow from operations by maintaining a significant hedging profile. We plan on deploying our available capital in a costeffective manner. For example, we exclusively utilize PAD development drilling with our drilling rig in the Williston Basin. At December 31, 2012 we had

approximately $37.0 million of availability under our credit facility and for the year ended December 31, 2012, we generated approximately $51.4 million of

cash flow from operations.

Profitably grow production and reserves. We have a substantial low-decline legacy production base as evidenced by our over 21 year reserve life as of

year-end 2012. Our capital is currently being deployed largely into unconventional oil assets with relatively predictable production profiles, yet steep initial

decline rates. Therefore, the economics of these oil wells are highly dependent on both near term commodity prices and strong operational cost control. Our rig

in the Williston Basin, and heightened focus on cost control in all of our operated positions both contribute to our history of adding low cost barrels to our

production base. As evidence of production growth not being an objective, but the outcome of sound investment decisions, we achieved 65% liquids growth

since the first quarter of 2010 despite relatively stagnant absolute volume growth.

2013 Budget and Drilling Activities

We have a substantial inventory of acreage in several basins, or plays, exposing us to significant resource potential which will be the focus of our

development plans in 2013. Our acreage in the unconventional plays includes the Williston Basin focused on the Bakken and Three Forks formations, the

onshore Gulf Coast Basin focused on the Eagle Ford Shale, the Powder River Basin focused on the Turner formation and the Duvernay Shale in Central

Alberta. Our acreage in the conventional plays includes the Alberta Basin focused on the Pekisko formation and several oil plays in Texas focused on the

Strawn, Frio and Yates formations.

Our capital expenditure budget for 2013 is $70 million. Approximately 68% of the 2013 budget will be spent on unconventional horizontal oil wells in the

Bakken/Three Forks in the Rocky Mountain region, approximately 27% in the Eagle Ford Shale play in South Texas with the remainder targeting

conventional oil plays in the Permian Basin region and in the province of Alberta, Canada. The 2013 capital expenditure budget is subject to change

depending upon a number of factors, including the availability of sufficient capital resources, the availability and costs of drilling and service equipment and

crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the results of our exploitation efforts, and our

ability to obtain permits for drilling locations.

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Markets and Customers

The revenue generated by our operations is highly dependent upon the prices we receive for our oil and gas. Historically, the markets for oil and gas

have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and

depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector),

foreign imports, political conditions in other petroleum producing countries, the actions of the Organization of Petroleum Exporting Countries, domestic

regulation, legislation and policies. Decreases in the prices we receive for our oil and gas have had, and could have in the future, an adverse effect on the

carrying value of our proved reserves, our revenue, profitability and cash flow from operations. You should read the discussion under “Risk Factors – Risks

Relating to Our Industry — Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash

flows, profitability and growth” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting

Policies” for more information relating to the effects of decreases in oil and gas prices on us. To help mitigate the impact of commodity price volatility, we

hedge a portion of our production through the use of fixed price swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of

Operations – General – Commodity Prices and Hedging Arrangements” and Note 14 of the notes to our consolidated financial statements for more information

regarding our derivative activities.

Substantially all of our oil and gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year

ended December 31, 2012, three purchasers accounted for approximately 39% of our oil and gas sales, and a single purchaser accounted for 16% of our oil

and gas sales. We believe that there are numerous other purchasers available to buy our oil and gas and that the loss of any of these purchasers would not

materially affect our ability to sell our oil and gas.

Regulation of Oil and Gas Activities

The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our properties are

affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, oil and gas

production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental and

other laws relating to the petroleum industry, and by changes in such laws and by periodically changing administrative regulations.

Federal, state, provincial and local laws and regulations govern oil and gas activities. Operators of oil and gas properties are required to have a number

of permits in order to operate such properties, including operator permits and permits to dispose of salt water. We possess all material requisite permits

required by the states, provinces and other local authorities in which we operate properties. In addition, under federal and provincial law, operators of oil and

gas properties are required to possess certain certificates and permits in order to operate such properties such as hazardous materials certificates, which we

have obtained.

Development and Production

The operations of our properties are subject to various types of regulation at the federal, provincial, state and local levels. These types of regulation

include requiring the operator of oil and gas properties to possess permits for the drilling and development of wells, post bonds in connection with various

types of activities, and file reports concerning operations. Most provinces, states, and some counties and municipalities in which we operate, regulate one or

more of the following:

· the location of wells;

· the method of drilling and casing wells;

· the method of completing and fracture stimulating wells;

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

· the plugging and abandoning of wells; and

· the notice to surface owners and other third parties.

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Some provinces and states regulate the size and shape of development and spacing units or proration units for oil and gas properties. Some provinces

and states allow forced pooling or unitization of tracts to facilitate exploration while other states/provinces rely on voluntary pooling of lands and leases. In

some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition,

provincial and state conservation laws establish maximum allowable rates of production from oil and gas wells, generally prohibit the venting or flaring of gas

and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells

or limit the number of wells or the locations at which our wells can be drilled. Moreover, each province and state generally imposes a production or severance

tax with respect to the production and sale of oil, gas and NGLs within its jurisdiction.

Operations on Federal, Provincial or Indian oil and gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various

federal agencies, including the Bureau of Land Management and the Office of Natural Resources Revenue, which we refer to as ONRR, (formerly Minerals

Management Service). ONRR establishes the basis for royalty payments due under federal oil and gas leases through regulations issued under applicable

statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases. The basis for royalty

payments established by ONRR and the state regulatory authorities is generally applicable to all federal and state oil and gas leases. Accordingly, we believe

that the impact of royalty regulation on the operations of our properties should generally be the same as the impact on our competitors. We believe that the

operations of our properties are in material compliance with all applicable regulations as they pertain to Federal or Indian oil and gas leases.

The failure to comply with these rules and regulations can result in substantial penalties, including lease suspension or termination in the case of

federal or provincial leases. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability.

Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect us.

Regulation of Transportation and Sale of Natural Gas in the United States

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as

amended, which we refer to as NGA, the Natural Gas Policy Act of 1978, as amended, which we refer to as NGPA, and regulations promulgated thereunder

by the Federal Energy Regulatory Commission, which we refer to as FERC, and its predecessors. In the past, the federal government has regulated the prices at

which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural

Gas Wellhead Decontrol Act, as amended, which we refer to as the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls

affecting wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas can currently be made at unregulated market prices,

Congress could reenact price controls in the future.

Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline

industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other

things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series

of related orders, which we refer to, collectively, as Order No. 636, to implement its open access policies. As a result of the Order No. 636 program, the

marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated

and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas.

FERC continues to regulate the rates that interstate pipelines may charge for such transportation and storage services. Although FERC’s orders do not directly

regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which we refer to, collectively, as Order No. 637, which imposed a number of additional

reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to

scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been

upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into

effect.

The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding market

manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civil

and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In

addition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which makes it unlawful for any entity, in connection with

the purchase or sale of natural gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, or omit a material fact or

engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty

authority to provide increased oversight of the natural gas marketplace.

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The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach

currently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it

affects other natural gas producers, gatherers and marketers.

Generally, intrastate natural gas transportation is subject to regulation by state regulatory agencies, although FERC does regulate the rates, terms, and

conditions of service provided by intrastate pipelines that transport natural gas subject to FERC’s NGA jurisdiction pursuant to Section 311 of the NGPA.

The basis for state regulation of intrastate natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline

rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the

state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship

natural gas on an intrastate basis will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our

competitors.

Natural Gas Gathering in the United States

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which

facilities constitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt for FERC’s NGA

jurisdiction. From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. FERC has also permitted jurisdictional pipelines to “spin

down” exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in

which such a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been

“spun down.” We cannot predict the effect that FERC’s activities in this regard may have on the operations of our properties, but we do not expect these

activities to affect the operations in any way that is materially different from the effect thereof on our competitors.

State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or service

requirements, but does not generally entail rate regulation. In the United States, gas gathering has received greater regulatory scrutiny at both the state and

federal levels in the wake of the interstate pipeline restructuring under FERC Order 636. For example, the Texas Railroad Commission enacted a Natural Gas

Transportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated with

the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating

in favor of their affiliates.

Regulation of Transportation of Oil in the United States

Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common

carrier pipelines is subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate

oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain

circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil

that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by FERC in 2000 was successfully

challenged on appeal by an association of oil pipelines. On remand, FERC, in February 2003, increased the index slightly, effective July 2001. Intrastate oil

pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of

regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally

applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way that is

materially different from the effect of such regulation on our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard,

common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity,

access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation

services generally will be available to us to the same extent as to our competitors.

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Environmental Matters

Oil and gas operations are subject to numerous federal, provincial, state and local laws and regulations controlling the generation, use, storage and

discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may:

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

· restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling,

production, and natural gas processing activities;

· suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, areas inhabited by threatened

or endangered species and other protected areas;

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

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

· impose substantial penalties for pollution resulting from our operations.

Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuing

authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil

fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that

we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and

regulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unable to

predict the ultimate cost and effects of future changes in environmental laws and regulations.

We are not currently involved in any administrative, judicial or legal proceedings arising under federal, state, provincial, or local environmental

protection laws and regulations, or under federal, provincial or state common law, which would have a material adverse effect on our respective financial

positions or results of operations. Moreover, we maintain insurance against the costs of clean-up operations, but we are not fully insured against all such

risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

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

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and

Liability Act, also known as Superfund, and which we refer to as CERCLA, and comparable state statutes impose strict, joint, and several liability, without

regard to fault or legality of conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the

environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or

arranged for the disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the

costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain

health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and

to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring land owners and other third

parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the

environment.

In the course of our ordinary operations, certain wastes may be generated that may fall within CERCLA’s definition of a “hazardous substance.” We

may be liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.

Although CERCLA currently contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations impose

cleanup liability relating to petroleum and petroleum related products, including oil cleanups.

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We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and

production of oil and gas. Although we have utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have

been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In

addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under

our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA (as defined below), and analogous state laws. Under these

laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean up

contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

Oil Pollution Act of 1990. Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare and

implement spill response plans relating to the potential discharge of oil into surface waters. The Federal Oil Pollution Act, which we refer to as OPA, contains

numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup

programs with respect to contaminated soil. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject

a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we

believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our financial position or

results of operations.

Resource Conservation Recovery Act. The Resource Conservation and Recovery Act, which we refer to as RCRA, is the principal federal statute

governing the treatment, storage and disposal of hazardous and non-hazardous solid wastes. RCRA imposes stringent operating requirements and liability for

failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous

waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and gas exploration and production wastes

to be classified and regulated as non-hazardous wastes. A similar exemption is contained in many of the state counterparts to RCRA. At various times in the

past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and gas exploration and production wastes from regulation as

hazardous wastes. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in

applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose and would cause us to incur increased

operating expenses. Also, in the ordinary course of our operations, we generate small amounts of ordinary industrial wastes, such as paint wastes, waste

solvents and waste oils that may be regulated as hazardous wastes.

Naturally Occurring Radioactive Materials, which we refer to as NORM, are materials not covered by the Atomic Energy Act, whose radioactivity is

enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and gas industry.

NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been

developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the

release of NORM contaminated land for unrestricted use. We believe that the operations of our properties are in material compliance with all applicable NORM

standards established by the various states in which we operate wells.

Clean Water Act. The Clean Water Act, which we refer to as the CWA, and analogous state laws, impose restrictions and controls on the discharge

of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is

prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and

natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample

storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands

and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the

CWA require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a petroleum

hydrocarbon tank spill, rupture or leak. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized

discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage

caused by the release and for natural resource damages resulting from the release. We believe that the operations of our properties comply in all material

respects with the requirements of the CWA and state statutes enacted to control water pollution.

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Safe Drinking Water Act. Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by

the Safe Drinking Water Act, which we refer to as the SDWA, and analogous state and local laws. Underground injection is the subsurface placement of fluid

through a well, such as the reinjection of brine produced and separated from oil and gas production. The main goal of the SDWA is the protection of usable

aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration

of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain

wastes, absent an exemption, cannot be injected into underground injection control wells. In most states, no underground injection may take place except as

authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by our permits could subject us to civil

and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection

control programs and our permits.

Clean Air Act. The Clean Air Act, which we refer to as the CAA, and state air pollution laws and regulations provide a framework for national, state

and local efforts to protect air quality. The operations of our properties utilize equipment that emits air pollutants which may be subject to federal and state air

pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality

standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In the past few years, EPA has

adopted new more restrictive regulations governing air emissions from oil and gas operations, including regulations which impose new restrictions on volatile

organic compounds, sulfur dioxide and hazardous air pollutants. Certain of these regulations will become effective in 2015 and will impose new restrictions

on air emissions arising from hydraulic fracturing operations.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional

non-attainment areas may require oil and natural gas exploration and production operators to incur future capital expenditures in connection with the addition

or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories

of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a

regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and natural gas exploration and

production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and

maintaining operating permits and approvals for air emissions. We believe that we are in compliance in all material respects with the requirements of applicable

federal and state air pollution control laws.

Hydraulic Fracturing. Most of our current operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This

technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well as sand,

or other proppants, into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Many of our

newer wells would not be economical without the use of hydraulic fracturing to stimulate the formation to enhance production from the well. Hydraulic

fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills such as the Fracturing

Responsibility and Awareness of Chemicals (FRAC) Act have been introduced in Congress to subject hydraulic fracturing to federal regulation under laws

such as the Safe Drinking Water Act. If adopted, these bills could result in additional chemical disclosure and permitting requirements for hydraulic

fracturing operations as well as various restrictions on those operations. These requirements and restrictions could result in delays in operations at existing

and new well sites as well as increased costs to make our wells productive. Moreover, these bills would require the public disclosure of information regarding

the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing

operations. If enacted, these laws could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water

wells in the vicinity of an oil or gas well or other alleged environmental problems. The EPA has finalized its Plan to Study the Potential Impacts of Hydraulic

Fracturing on Drinking Water Resources, which is expected to result in a final report on the subject with recommendations in 2014. Also, the U.S. Department

of the Interior has announced that it intends to propose regulations governing hydraulic fracturing which occurs on federal lands, including requiring chemical

disclosure. In addition to these federal legislative and regulatory proposals, some states and local governments have considered imposing, or have adopted

various conditions and restrictions on hydraulic fracturing operations, including but not limited to requirements regarding chemical disclosure, casing and

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water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may

be used in hydraulic fracturing operations. If these types of conditions are widely adopted, we could be subject to increased costs and possibly limits on the

productivity of certain wells. Some states in which we operate have implemented disclosure requirements for chemicals used in hydraulic fracturing.

Climate change legislation and greenhouse gas regulation. Studies over recent years have indicated that emissions of certain gases may be

contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs”

pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and

carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto

Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of

greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and

demand for our products. As a result of the Supreme Court decision in Massachusetts, et al. v. EPA, on December 7, 2009, the EPA issued a finding that

serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the

Clean Air Act, even without Congressional action. As part of this array of new regulations, the EPA has issued a GHG monitoring and reporting rule that

requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon

dioxide, to the EPA. These regulations may apply to our operations. The EPA has adopted other rules that would regulate GHGs, one of which would regulate

GHGs from stationary sources, and may affect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA’s

finding, the greenhouse gas reporting rule, and the rules to regulate the emissions of greenhouse gases may affect the cost of our operations and also affect the

outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.

Although various climate change legislative measures have been under consideration by the U.S. Congress, it is not possible at this time to predict

when, or if, Congress will act on climate change legislation, although any major initiatives in this area to be unlikely to become law in the near future due to

opposition in the U.S. House of Representatives. Finally, some states, either individually or through multi-state regional initiatives, already have begun

implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional greenhouse gas cap

and trade programs. Depending on the particular jurisdiction of our operations, we could be required to purchase and surrender allowances for GHG emissions

resulting from our operations. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our

business, financial condition, and results of operations.

National Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National Environmental

Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the

potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the

potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that

may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those

activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of

oil and gas projects.

Endangered Species Act. The Endangered Species Act, which we refer to as the ESA, restricts activities that may affect endangered or threatened

species or their habitats. While some of our properties may be located in areas that may be designated as habitat for endangered or threatened species, we

believe that we are in substantial compliance with the ESA. Looking forward, we expect more listings of such species to occur, in light of consent decrees

involving the U.S. Fish and Wildlife Service which require the agency to decide whether or not to list, as endangered or threatened, approximately 251

candidate species by 2016. Included in this group are a number of terrestrial species, such as the lesser prairie chicken which, if listed, could include habitat

in areas where we operate or plan to operate. Such listing of additional species, or the discovery of previously unidentified endangered or threatened species,

could cause us to incur additional costs or become subject to operating restrictions, construction delays, or bans on operating in the affected areas.

Abandonment Costs. All of our oil and gas wells will require proper plugging and abandonment at some time in the future. We have posted bonds

with most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation of the

surface site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no

longer producing.

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Title to Properties

As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and gas leases at the time we acquire them.

However, before drilling commences, we make a thorough title search, and any material defects in title are remedied prior to the time actual drilling of a well

begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically obligated

to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling

operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our properties, some of which

are subject to immaterial encumbrances, easements and restrictions. The oil and gas properties we own are also typically subject to royalty and other similar

non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use

of our properties.

Competition

We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leasehold

prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment and services to explore for such reserves and knowledgeable

personnel to conduct all phases of oil and gas operations. We must compete for such resources with both major oil and gas companies and independent

operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and

financial resources are adequate to preclude any significant disruption of our near term operations; however we cannot assure you that such materials and

resources will be available to us in the future.

Employees

As of March 12, 2013, we had 101 full-time employees. We retain independent geological, land and engineering consultants from time to time and

expect to continue to do so in the future.

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Available Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You

may read and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Please

call the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet web site that contains annual, quarterly and

current reports, proxy statements and other information that issuers (including Abraxas) file electronically with the SEC. The SEC’s web site is www.sec.gov.

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments filed with the

SEC are available free of charge on our web site at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports are

filed. Information on our web site is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that

we make with the SEC.

Item 1A. Risk Factors

Risks Related to Our Business

We have substantial indebtedness which may adversely affect our cash flow and business operations .

At December 31, 2012, we had a total of $113.0 million of indebtedness under our credit facility. Our indebtedness could have important consequences to

us, including:

· effecting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes which

may be impaired or not available on favorable terms;

· covenants contained in our credit facility 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 future business 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 and future business opportunities; and

· our level of indebtedness will make us more vulnerable to competitive pressures if there is a downturn in our business or the economy in general,

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 or delaying capital expenditures, acquisitions and/or

selling assets, restructuring or refinancing our indebtedness or seeking additional debt or equity capital or bankruptcy protection. We may not be able to affect

any of these remedies on satisfactory terms or at all.

A breach of the terms and conditions of our credit facility, including the inability to comply with the required financial covenants, could result in an event

of default. If an event of default occurs (after any applicable notice and cure periods), the lenders would be entitled to terminate any commitment to make

further extensions of credit under our credit facility and to accelerate the repayment of amounts outstanding (including accrued and unpaid interest and

fees). Upon a default under our credit facility, the lenders could also foreclose against any collateral securing such obligations, which may be all or

substantially all of our assets. If that occurred, we may not be able to continue to operate as a going concern.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing

conditions and engage in other business activities that may be in our best interests.

Our credit facility contains a number of significant covenants that, among other things, limit our ability to:

· incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock;

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· transfer or sell assets;

· create liens on assets;

· pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring

capital stock or subordinated debt or making certain investments or acquisitions;

· engage in transactions with affiliates;

· guarantee other indebtedness;

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

· permit a change of control; or

· consolidate, merge or transfer all or substantially all of our assets.

In addition, our credit facility requires us to maintain compliance with specified financial covenants. Our ability to comply with these covenants may be

adversely affected by events beyond our control, and we cannot assure you that we can maintain compliance with these covenants. These financial covenants

could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general

or otherwise conduct necessary or desirable business activities.

A breach of any of these covenants could result in a default under our credit facility. A default, if not cured or waived, could result in all of our

indebtedness becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance

it. Even if new financing were then available, it may not be on terms acceptable or favorable to us. For example, at December 31, 2011 and March 31, 2012,

we were not in compliance with the financial ratio that we maintain a current ratio, as of the last day of each quarter, of not less than 1.00 to 1.00. We received

waivers from our bank group for this covenant breach. The current ratio is defined as 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 excludes any cash deposited

with a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 “Derivatives and

Hedges” and ASC 410-20 “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 ASC 815 and ASC 410-20.

We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capital expenditures

primarily with cash flow from operations, borrowings under credit facilities, sales of producing properties, and sales of debt and equity securities and we

expect to continue to do so in the future. We cannot assure you that we will have sufficient capital resources in the future to finance all of our planned capital

expenditures.

Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or

lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements,

including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of planned capital

expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital

expenditures would, by necessity, be decreased.

The borrowing base under our credit facility is determined from time to time by the lenders. Reductions in estimates of oil and gas reserves could result in

a reduction in the borrowing base, which would reduce the amount of financial resources available under our credit facility to meet our capital

requirements. Such a reduction could be the result of lower commodity prices and/or production, an inability to drill or unfavorable drilling results, changes

in oil and gas reserve engineering, the lenders’ inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation

of reserves.

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If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be

adversely affected. As a result, our ability to replace production may be limited. In addition, if the borrowing base under our credit facility is reduced, we

could be required to reduce borrowings under our credit facility so that such borrowings do not exceed the borrowing base. This could further reduce the cash

available to us for capital spending and, if we did not have sufficient capital to reduce our borrowing level, we may be in default under the credit facility.

We have sold producing properties to provide us with liquidity and capital resources in the past and we may continue to do so in the future. After any

such sale, we would expect to utilize the proceeds to reduce our indebtedness and to drill new wells on our remaining properties. If we cannot replace the

properties sold with production from our remaining properties, our cash flow from operations will likely decrease, which in turn, could decrease the amount of

cash available for additional capital spending.

We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely

affected.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that

are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced. Unless we

acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify

additional behind-pipe zones or secondary recovery reserves, we cannot assure you that our exploration and development activities will result in increases in

our proved reserves. Based on the reserve information set forth in our reserve report as of December 31, 2012, our average annual estimated decline rate for

our net proved developed producing reserves is 13% during the first five years, 8% in the next five years, and approximately 7% thereafter. These rates of

decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing

additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and prior property sales. As our

proved reserves and consequently our production decline, our cash flow from operations, and the amount that we are able to borrow under our credit facility

could also decline. In addition, approximately 49% of our total estimated proved reserves at December 31, 2012 were classified as undeveloped. By their

nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling

operations. Even if we are successful in our development efforts, it could take several years for a significant portion of these undeveloped reserves to generate

positive cash flow.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

· the availability and costs of drilling and service equipment and crews;

· economic and industry conditions at the time of drilling;

· prevailing and anticipated prices for oil and gas;

· the availability of sufficient capital resources;

· the results of our exploitation efforts;

· the acquisition, review and interpretation of seismic data;

· our ability to obtain permits for drilling locations; and

· lease expirations and continuing development obligations.

Although we have identified or budgeted for numerous drilling locations, we may not be able to drill those locations within our expected time frame or at

all. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

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We may not find any commercially productive oil and gas reservoirs.

Drilling involves numerous risks, including the risk that the new wells we drill will be unproductive or that we will not recover all or any portion of our

capital investment. Drilling for oil and gas may be unprofitable. Dry wells that are productive but do not produce sufficient net revenues after drilling,

operating and other costs are unprofitable. The inherent risk of not finding commercially productive reservoirs is compounded by the fact that 49% of our

total estimated proved reserves as of December 31, 2012 were classified as undeveloped. By their nature, estimates of undeveloped reserves are less

certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. In addition, our properties may be

susceptible to drainage from production by other operations on adjacent properties. If the volume of oil and gas we produce decreases, our cash flow from

operations may decrease.

The results of our drilling in unconventional formations, principally in emerging plays with limited drilling and production history using long

laterals and modern completion techniques, are subject to more uncertainties than our drilling program in the more established plays and may not

meet our expectations for reserves or production.

We drill wells in unconventional formations in several emerging plays. Part of our drilling strategy to maximize recoveries from these formations involves

the drilling of long horizontal laterals and the use of modern completion techniques of multi-stage fracture stimulations that have proven to be successful in

other basins. Our experience with horizontal drilling and multi-stage fracture stimulations of these formations to date, as well as the industry’s drilling and

production history in these formations, is relatively limited. The ultimate success of these drilling and completion strategies and techniques will be better

evaluated over time as more wells are drilled and longer term production profiles are established. In addition, based on reported decline rates in these emerging

plays as well as the industry’s experience in these formations, we estimate that the average monthly rates of production may decline as much as 70% during

the first twelve months of production. Actual decline rates may differ significantly. Accordingly, the results of our drilling in these unconventional formations

are more uncertain than drilling results in other more established plays with longer reserve and production histories .

We cannot control the activities on the properties we do not operate and are unable to ensure their proper operation and profitability.

We currently do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over and control the

risks associated with operation of these properties. The failure of an operator to adequately perform operations, an operator’s breach of the applicable

agreements or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of our drilling and

development activities on properties operated by others therefore depends upon a number of factors outside of our control, including:

· the operator could refuse to initiate exploitation or development projects and if we proceed with any of those projects, we may not receive any

funding from the operator with respect to that project;

· the operator may initiate exploitation or development projects on a different schedule than we would prefer;

· the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project

than we have funds for, which may mean that we cannot participate in those projects and thus, not participate in the associated revenue stream;

and

· the operator may not have sufficient expertise or resources.

Any of these events could significantly and adversely affect our anticipated exploitation and development activities.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston Basin, Powder River Basin

and in Canada, drilling and other oil and gas activities cannot be conducted as effectively during the winter and spring months. Winter and severe weather

conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could

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delay or temporarily halt our oil and gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our

business, financial condition and results of operations.

The lack of availability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to

execute our exploitation and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, oil field services or qualified personnel. During

these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified

drilling rig crews rise as the number of active rigs in service increases. During times and in areas of increased activity, the demand for oilfield services will

also likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of

drilling rigs, equipment, supplies, oil field services or qualified personnel were particularly severe in any of our areas of operation, we could be materially and

adversely affected. Delays could also have an adverse effect on our results of operations, including the timing of the initiation of production from new wells.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control.

Our drilling operations are subject to a number of risks, including:

· unexpected drilling conditions;

· facility or equipment failure or accidents;

· adverse weather conditions;

· title problems;

· unusual or unexpected geological formations;

· fires, blowouts and explosions; and

· uncontrollable flows of oil or gas or well fluids.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage

to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension

of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

We do not insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for,

uninsured or underinsured risks related to our oil and gas operations.

We do not insure against all risks. Our oil and gas exploitation and production activities are subject to hazards and risks associated with drilling for,

producing and transporting oil and gas, and any of these risks can cause substantial losses resulting from:

· environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment,

including groundwater, shoreline contamination, underground migration and surface spills or mishandling of fracturing fluids, including

chemical additives;

· abnormally pressured formations;

· mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

· leaks of gas, oil, condensate, natural gas liquids and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling

and completion operations, including hydraulic fracturing, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines,

measurement equipment or processing or other facilities in the Company’s operations or at delivery points to third parties;

· fires and explosions;

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· personal injuries and death;

· regulatory investigations and penalties; and

· natural disasters.

We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution

and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of

existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, has recently come under increased scrutiny

and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is the primary completion method used to extract reserves located in many of the unconventional oil and gas plays in the United

States and Canada. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure, usually down casing that is cemented in the

wellbore, into prospective rock formations at depth to stimulate oil and gas production. We use this completion technique on substantially all of our wells.

Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, state and/or provincial levels, exploration,

exploitation and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Some states in

which we operate, including Texas, have recently implemented disclosure requirements of chemicals used in hydraulic fracturing, and the U.S. Department of

the Interior has announced that it intends to propose regulations governing hydraulic fracturing on federal lands, including requiring chemical

disclosure. Individually or collectively, such existing and new legislation or regulation could lead to operational delays or increased operating costs and could

result in additional burdens that could increase the costs and delay the development of unconventional oil and gas resources from formations which are not

commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.

Hydraulic fracturing is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulic

fracturing involving diesel fuels under the Underground Injection Control Program established under the Safe Drinking Water Act, or SDWA, and published

draft permitting guidance in May 2012 addressing the performance of such activities. In November 2011, the Environmental Protection Agency, or EPA,

announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the

chemicals used in hydraulic fracturing, and the agency currently project to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek

public input on the design and scope of such disclosure regulations. In August 2012, the EPA published final rules under the CAA, which became effective

October 15, 2012, that, among other things, require producers to reduce volatile organic compound emissions from certain subcategories of fractured and

refractured gas wells for which well completion operations are being conducted by routing flowback emissions to a gathering line or capturing and combusting

flowback emissions using a combustion device, such as a flare, until January 1, 2015 or performing reduced emission completions, also known as “green

completions,” with or without combustion devices, on or after January 1, 2015. In addition, the U.S. Congress, from time to time, has considered adopting

legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing

process. In the event that a new federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we currently or in the

future plan to operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, become subject to additional

permitting requirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.

Certain states in which we operate, including Texas, have adopted, and other states are considering adopting, regulations that could impose new or more

stringent permitting, disclosures, and well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011

requiring disclosure to the Texas Railroad Commission and the public of certain information regarding the components used in the hydraulic-fracturing

process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in

particular. We believe that we follow applicable standard industry practices

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and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas

where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be

significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded

in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White

House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a

study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress released by the agency on

December 21, 2012 and a final report expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent

limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other

governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic

fracturing. These studies, or future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further

regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. See “Item 1. Business – Environmental Matters – Hydraulic Fracturing ”

above for additional discussion related to environmental risks associated with our hydraulic fracturing activities.

The marketability of our production depends largely upon the availability, proximity and capacity of oil and gas gathering systems, pipelines and

processing facilities.

The marketability of our production depends in part upon processing and transportation facilities. Transportation space on such gathering systems and

pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by

other companies with priority transportation agreements. Our access to transportation options can also be affected by U.S. Federal and state, as well as

Canadian provincial, regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. These factors

and the availability of markets are beyond our control. If our access to these transportation options dramatically changes, the financial impact on us could be

substantial and adversely affect our ability to produce and market our oil and gas.

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

flow from operations.

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for 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, product quality, 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 2012, differentials averaged ($9.05) per Bbl of oil and ($0.47) per Mcf of gas. Approximately 76% of our oil and NGL production during 2012

was from the Rocky Mountain region. Historically, this region has experienced wider differentials than our Permian Basin and Gulf Coast properties. As the

percentage of our production from the Rocky Mountain region continues to increase, we expect that our price differentials will also increase. Increases in the

differential between the benchmark prices for oil and gas and the realized price we receive could significantly reduce our revenues and our cash flow from

operations.

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

To achieve more predictable cash flow and reduce our exposure to adverse fluctuations in the prices of oil and gas, we enter into derivative contracts,

which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized

derivative contract losses. We have entered into NYMEX-based fixed price commodity swap arrangements on approximately 60% of the oil production from

our estimated net proved developed producing reserves (as of December 31, 2012) through December 31, 2013, 80% in 2014, 78% in 2015 and 81% for 2016.

Any new hedging arrangements will be priced at then-current market prices and may be significantly lower than the commodity swaps we currently have in

place. The extent of our commodity price exposure will be related largely to the effectiveness and scope of our commodity price derivative

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contracts. For example, the prices utilized in our derivative contracts are currently NYMEX-based, which may differ significantly from the actual prices we

receive for oil and gas which are based on the local markets where the oil and gas is 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, a significant portion of which is based on the delivery location which is called the basis differential. As a

result, our cash flow from operations could be affected if the basis differentials widen more than we anticipate. For more information see “—An increase in

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

currently do not have any basis differential hedging arrangements in place. Our cash flow from operations 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.

If the prices at which we hedge our oil and gas production are less than current market prices, our cash flow opportunity from operations could

be adversely affected.

When our derivative contract prices are higher than market prices, we will incur realized and unrealized gains on our derivative contracts and conversely,

when our contract prices are lower than market prices, we will incur realized and unrealized losses. For the year ended December 31, 2012, we recognized a

realized loss on oil and gas derivative contracts of $0.3 million and an unrealized gain of $2.7 million. The realized loss resulted in a decrease in cash flow

from operations. We expect to continue to enter into similar hedging arrangements in the future to reduce our cash flow volatility.

We cannot assure you that the derivative contracts that we have entered into, or will enter into, will adequately protect us from financial loss in the future

due to circumstances such as:

· highly volatile oil and gas prices;

· our production being less than expected; or

· a counterparty to one of our hedging transactions defaulting on its contractual obligations.

The counterparties to our derivative contracts may be unable to perform their obligations to us which could adversely affect our cash flow.

At times when market prices are lower than our derivative contract prices, we are entitled to cash payments from the counterparties to our derivative

contracts. Any number of factors may adversely affect the ability of our counterparties to fulfill their contractual obligations to us. If one of our counterparties

is unable or unwilling to make the required payments to us, it could adversely affect our cash flow.

Potential regulations under the Dodd-Frank Act regarding derivatives could adversely impact our ability to engage in commodity price risk

management activities.

On July 21, 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which imposes a

comprehensive regulatory scheme significantly impacting companies engaged in over-the-counter swap transactions. The Dodd-Frank Act generally applies to

“swaps” entered into by “major swap participants” and/or “swap dealers,” each as defined in the Dodd-Frank Act. A swap is very broadly defined in the

Dodd-Frank Act and includes an energy commodity swap. A swap dealer includes an entity that regularly enters into swaps with counterparties as an

“ordinary course of business for its own account.” Furthermore, a person may qualify as a major swap participant if it maintains a “substantial position” in

outstanding swaps, other than swaps used for “hedging or mitigating commercial risk” or whose positions create substantial exposure to its counterparties or

the U.S. financial system. The Dodd-Frank Act subjects swap dealers and major swap participants to substantial supervision and regulation by the

Commodity Futures Trading Commission, or the CFTC, including capital standards, margin requirements, business conduct standards, and recordkeeping

and reporting requirements. The CFTC recently promulgated regulations to set position limits for certain futures and option contracts in the major energy

markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position

limits. Position limits for spot month limits became effective on October 12,

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2012 while non-spot limits for energy-related commodities are not expected to be effective until mid-to late-2013. The CFTC also has proposed regulations to

establish minimum capital and margin requirements, as well as clearing and trade-execution requirements in connection with certain derivative activities,

although it’s not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under

Dodd Frank. In addition, the CFTC’s regulations adopted pursuant to the Dodd-Frank Act impose certain record keeping and transactional reporting

requirements that may be burdensome and costly to us and to the counterparties to our commodity derivative contracts.

The new legislation and any new regulations could significantly increase the cost of some commodity derivative contracts (including through

requirements to post collateral or provide other credit support, which could adversely affect our available liquidity), materially alter the terms of some

commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure

our existing commodity derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the

new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect

our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank

Act was intended, in part, to reduce volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity

instruments related to oil and gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of

these consequences could adversely affect our business, financial condition and results of operations.

Lower oil and gas prices increase the risk of ceiling limitation write-downs.

We use the full cost method to account for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop our oil and

gas properties. Under full cost accounting rules, the net capitalized cost of our oil and gas properties may not exceed a “ceiling limit” which is based upon the

present value of estimated future net cash flows from our proved reserves, discounted at 10%. If the 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 it does reduce our stockholders’ equity and earnings. The risk that we will be required to write-down the carrying value of our

oil and gas properties increases when oil and gas prices are low, which could be further impacted by the SEC’s modernized oil and gas reporting disclosures,

which require us to use an average price over the prior 12-month period, rather than the year-end price, when calculating the PV-10. In addition, write-downs

may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a

subsequent period even though oil and gas prices may have increased the ceiling applicable in the subsequent period.

At December 31, 2011, the net capitalized cost of our United States and Canadian oil and gas properties did not exceed the present value of our

estimated proved reserves. At December 31, 2012, the net capitalized costs of our United States oil and gas properties did not exceed the present value of our

estimated proved reserves; however, the net capitalized costs of our Canadian oil and gas properties exceeded the present value of our estimated proved reserves

by approximately $19.8 million, resulting in a write down of $19.8 million. We had write downs in the second, third and fourth quarters of 2012 of $1.3

million, $11.8 million and $6.7 million respectively.

Use of our net operating loss carryforwards may be limited.

At December 31, 2012, we had, subject to the limitation discussed below, $169.6 million of net operating loss carryforwards for U.S. tax purposes and

$15.0 million for Canadian tax purposes. The U.S. loss carryforwards will expire in varying amounts through 2032, and the Canadian carryforward will

expire in 2032, if not otherwise used.

The use of our net operating loss carryforwards may be limited if an “ownership change” of over 50 percentage points occurs during any three-year

period. Based on current estimates, we believe that we have not surpassed this threshold. It is feasible that even a modest change of ownership (including, but

not limited to, a shift in common stock ownership by one reasonably large stockholder or any offering of common stock to a limited number of investors)

during the three-year period following the merger with the Partnership, which was consummated on October 5, 2009, could trigger a significant limitation of

the amount of such net operating loss carryforwards available to offset future taxable income.

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Additionally, uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, in accordance with Financial Accounting

Standards Board (“FASB”) and ASC 740-10, we have established a valuation allowance of $89.7 million at December 31, 2012.

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We

depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling

information, and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or other

proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production

operations. In addition, computer technology controls nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary

to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the

environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle

transactions.

While we have not experienced cyber attacks, we may suffer such losses in the future. Further, as cyber attacks continue to evolve, we may be

required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to

cyber attacks.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with certain technical assistance and services. We rely upon the owners and operators of rigs and

drilling equipment, and upon providers of field services, to drill and develop our prospects to production. We also rely upon the services of other third parties

to explore and/or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the

activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or their

failure to provide quality services could materially adversely affect our business, results of operations and financial condition.

We depend on our President, CEO and Chairman of the Board and the loss of his services could have an adverse effect on our operations.

We depend to a large extent on Robert L.G. Watson, our President and Chief Executive Officer, for our management and business and financial

contacts. Mr. Watson may terminate his employment agreement with us at any time on 30 days notice, but, if he terminates without cause, he would not be

entitled to the severance benefits provided under the terms of that agreement. Mr. Watson is not precluded from working for, with or on behalf of a competitor

upon termination of his employment with us. If Mr. Watson were no longer able or willing to act as President, Chief Executive Officer and Chairman of the

Board, the loss of his services could have an adverse effect on our operations.

Our financial statements are complex and our control environment cannot completely prevent fraud or human error.

Due to the nature of our business, and accounting principles generally accepted in the United States of America, our financial statements are complex,

particularly with reference to derivative contracts, asset retirement obligations, deferred taxes and the accounting for our stock-based compensation plans. We

expect such complexity to continue and possibly increase. Because of these complexities, many of our accounting processes are done manually and are

dependent upon individual data input or review. While we continue to automate our processes and enhance our review and put in place controls to reduce the

likelihood for errors, we expect that for the foreseeable future many of our processes will remain manually intensive and thus subject to human error.

A control environment, no matter how well conceived and operated, can provide only reasonable assurance that the objectives of the control environment

are met. Because of the inherent limitations in all control environments, no evaluation of controls can provide absolute assurance that all control issues have

been detected and misstatements due to error or fraud may occur and not be detected.

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Risks Related to Our Industry

Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows, profitability

and growth.

Our revenue, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and gas. Recently low gas prices

affected us more than oil prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise

additional capital. Lower prices may also make it uneconomical for us to increase or even continue current production levels of oil and gas.

Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, market

uncertainty and a variety of other factors beyond our control, including:

· changes in foreign and domestic supply and demand for oil and gas;

· political stability and economic conditions in oil producing countries, particularly in the Middle East;

· weather conditions;

· price and level of foreign imports;

· terrorist activity;

· availability of pipeline and other secondary capacity;

· general economic conditions;

· domestic and foreign governmental regulation; and

· the price and availability of alternative fuel sources.

Estimates of proved reserves and future net revenue are inherently imprecise.

The process of estimating oil and gas reserves is complex and involves 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 our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results

of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

The estimates of our reserves as of December 31, 2012 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 PV-10 thereof for our oil and gas

properties are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices for

the year ended December 31, 2012. The average realized sales prices as of such date used for purposes of such estimates were $2.61 per Mcf of gas and

$88.26 per Bbl of oil. The December 31, 2012 estimates also assume that we will make future capital expenditures of approximately $328.6 million in the

aggregate primarily from 2013 through 2017, which are necessary to develop and realize the value of proved reserves on our properties. In addition,

approximately 49% of our total estimated proved reserves as of December 31, 2012 were classified as 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 our reserves set forth or incorporated by reference in this report.

The present value 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 and financial condition.

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As required by SEC regulations, we based the estimated discounted future net cash flows from our proved reserves as of December 31, 2012 on the

twelve month first-day-of-the-month average oil and gas prices for the year ended December 31, 2012 and costs in effect on December 31, 2012, the date of the

estimate. However, actual future net cash flows from our properties will be affected by factors such as:

· supply of and demand for our oil and gas;

· actual prices we receive for our oil and gas;

· our actual operating costs;

· the amount and timing of our capital expenditures;

· the amount and timing of our actual production; and

· changes in governmental regulations or taxation.

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 and financial condition.

Our operations are subject to the numerous risks of oil and gas drilling and production activities.

Our oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk of

fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks,

ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemical additives. In

addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively

affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result

from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatory investigation and penalties

and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We

cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium

levels that justify its purchase.

We operate in a highly competitive industry which may adversely affect our operations.

We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leasehold

prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to

conduct all phases of operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of these

competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate

to preclude any significant disruption of our operations, we cannot assure you that such resources will be available to us in the future .

Our oil and gas operations are subject to various U.S. Federal, state, local and Canadian provincial regulations that materially affect our

operations.

In the oil and gas industry, matters regulated include permits for drilling and completion operations, drilling and abandonment bonds, reports concerning

operations, the spacing of wells and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and

limitations on production. In order to conserve supplies of oil and gas, these agencies have restricted the rates of flow from oil and gas wells below actual

production capacity. U.S. Federal, state, local, and Canadian provincial laws regulate production, handling, storage, transportation and disposal of oil and

gas by-products and other substances and materials produced or used

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in connection with oil and gas operations. To date, our expenditures related to complying with these laws and for remediation of existing environmental

contamination have not been significant. We believe that we are in substantial compliance with all applicable laws and regulations. However, the requirements

of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our

operations.

Proposed federal legislation concerning tax deductions currently available with respect to oil and gas drilling may adversely affect our net

earnings.

Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would

deprive some companies involved in oil and natural gas exploration and production activities in certain U.S. federal income tax incentives and deductions

currently available to such companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas

properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic

production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether such

changes may apply retroactively. Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of any

legislation as a result of these proposals or any other similar changes to U.S. federal income tax laws could eliminate or postpone certain tax deductions that are

currently available to us, and any such change could negatively affect our financial condition and results of operations.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these

studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of

greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, gas and refined petroleum products,

are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change and the Kyoto Protocol address greenhouse

gas emissions, and several countries including the European Union have established greenhouse gas regulatory systems. In the United States, at the state level,

many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases,

primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting

greenhouse gas regulatory programs. At the federal level, in June 2009, the United States House of Representatives passed the American Clean Energy and

Security Act of 2009, also known as the Waxman-Markey Bill or ACESA. The United States Senate passed out of committee the Clean Energy Jobs and

American Power Act, also known as the Kerry-Boxer Bill. Although these bills differ in certain ways, they both contain provisions that would establish a cap

and trade system for restricting greenhouse gas emissions in the United States. Under such a system, certain sources of greenhouse gas emissions would be

required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances

issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year,

the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this federal legislative initiative remains uncertain.

In addition to pending climate legislation, the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010,

and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment

Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future

generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain

facilities. The EPA has proposed such greenhouse gas regulations and may issue final rules this year.

In the courts, several decisions have been issued that may increase the risk of claims being filed by government entities and private parties against

companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and

seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

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Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and

compliance costs, and could have an adverse effect on demand for the oil and gas that we produce and as a result, our financial condition and results of

operations could be adversely affected.

Risks Related to Our Common Stock

Future issuance of additional shares of common stock could cause dilution of ownership interests and adversely affect our stock price.

We are currently authorized to issue 200,000,000 shares of common stock with such rights as determined by our board of directors. We may in the future

issue previously authorized and unissued securities, resulting in the dilution of the ownership interests of current stockholders. The potential issuance of any

such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of

common stock or other securities that are convertible into or exercisable for common stock for capital raising or other business purposes. Future sales of

substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.

We will not pay dividends on our common stock for the foreseeable future.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash

dividends in the foreseeable future. In addition, our credit facility prohibits us from paying dividends and making other cash distributions.

Shares eligible for future sale may depress our stock price.

At December 31, 2012, we had 92,733,448 shares of common stock outstanding of which 6,417,073 shares were held by affiliates and, in addition,

4,760,910 shares of common stock were subject to outstanding options granted under stock option plans (of which 2,992,467 shares were vested at

December 31, 2012).

All of the shares of common stock held by affiliates are restricted or control securities under Rule 144 promulgated under the Securities Act. The shares

of common stock issuable upon exercise of stock options have been registered under the Securities Act. Sales of shares of common stock under Rule 144 or

another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of our common stock and

could impair our ability to raise additional capital through the sale of equity securities.

The price of our common stock has been volatile and could continue to fluctuate substantially.

Our common stock is traded on The NASDAQ Stock Market. The market price of our common stock has been volatile and could fluctuate

substantially based on a variety of factors, including the following:

· fluctuations in commodity prices;

· variations in results of operations;

· legislative or regulatory changes;

· general trends in the oil and gas industry;

· sales of common stock or other actions by our stockholders;

· additions or departures of key management personnel;

· commencement of or involvement in litigation;

· speculation in the press or investment community regarding our business;

· an inability to maintain the listing of our common stock on a national securities exchange;

· market conditions; and

· analysts’ estimates and other events in the oil and gas industry.

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We may issue shares of preferred stock with greater rights than our common stock.

Subject to the rules of The NASDAQ Stock Market, our articles of incorporation authorize our board of directors to issue one or more series of preferred

stock and set the terms of the preferred stock without seeking any further approval from holders of our common stock. Any preferred stock that is issued

may rank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common

stock. On March 16, 2010, our board of directors adopted a tax benefits preservation plan and declared a dividend of one preferred share purchase right for

each outstanding share of our common stock. These rights are only activated if the plan is triggered by any person or group acquiring 4.9% or more of our

outstanding common stock without our approval.

Anti-takeover provisions could make a third party acquisition of us difficult.

Our articles of incorporation and bylaws provide for a classified board of directors, with each member serving a three-year term, and eliminate the ability

of stockholders to call special meetings or take action by written consent. Each of the provisions in our articles of incorporation, bylaws and our tax benefits

preservation plan, could make it more difficult for a third party to acquire us without the approval of our board. In addition, the Nevada corporate statute also

contains certain provisions that could make an acquisition by a third party more difficult. On March 16, 2010, our board of directors adopted a tax benefits

preservation plan designed to preserve our substantial tax assets. In addition, the plan is intended to act as a deterrent to any person or group acquiring 4.9%

or more of our outstanding common stock without our approval.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Exploratory and Developmental Acreage

Our principal oil and gas properties consist of producing and non-producing oil and gas leases, including reserves of oil and gas in place. The

following table sets forth our developed and undeveloped acreage and fee mineral acreage as of December 31, 2012. There are no material lease expirations in

2013.

Developed

Acreage Undeveloped Acreage

Fee Mineral

Acreage (1)

Gross

Acres

Net

Acres

Gross

Acres

Net

Acres

Gross

Acres

Net

Acres

Total

Net

Acres (2)

Rocky Mountain 72,194 33,496 85,957 36,396 1,721 851 70,743

Mid-Continent 24,1080 5,524 5,878 296 — — 5,820

Permian Basin 24,408 17,441 21,430 19,379 12,007 5,272 42,092

Onshore Gulf Coast 10,652 6,181 6,824 5,287 — — 11,468

Total United States 131,362 62,642 120,089 61,358 13,728 6,123 130,123

Alberta, Canada (3) 2,240 2,240 27,200 27,200 — — 29,440

Total 133,602 64,882 147,289 88,558 13,728 6,123 159,563

_______________

(1) Fee mineral acreage represents fee simple absolute ownership of the mineral estate or fraction thereof.

(2) Includes 3,981 acres in the Permian Basin region that are included in both developed and undeveloped gross acres.

(3) Excludes approximately 22,000 acres subject to a farmout agreement.

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Productive Wells

The following table sets forth our gross and net productive wells, expressed separately for oil and gas, as of December 31, 2012:

Productive Wells

Oil Gas

Gross Net Gross Net

Rocky Mountain 558.0 93.4 507.0 15.9

Mid-Continent 6.0 3.5 141.0 29.6

Permian Basin 161.0 133.4 59.0 31.2

Onshore Gulf Coast 33.5 33.5 30.5 22.5

Total United States 758.5 263.8 737.5 99.2

Alberta, Canada 8.0 8.0 — —

Total 766.5 271.8 737.5 99.2

Reserves Information

The estimation and disclosure requirements we employ conform to the definition of proved reserves with the Modernization of Oil and Gas Reporting

rules, which were issued by the SEC at the end of 2008. This accounting standard requires that the average first-day-of-the-month price during the 12-month

period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if

those technologies have been demonstrated to result in reliable conclusions about reserves volumes.

For the year ended December 31, 2012, DeGolyer and MacNaughton, of Dallas, Texas estimated reserves for Abraxas’ properties comprising

approximately 99% of the PV-10 of our proved oil and gas reserves. Proved reserves for the remaining 1% of our properties were estimated by Abraxas

personnel because we determined that it was not practical for DeGoyler and MacNaughton to prepare reserve estimates for these properties as they are located in

a widely dispersed geographic area and have relatively low value. DeGolyer and MacNaughton’s reserve report as of December 31, 2012 for Abraxas included

a total of 575 properties and our internal report included 409 properties.

The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications,

independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information

promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and

petrophysicists. They do not own an interest in any of our properties and are not employed on a contingent fee basis. All reports by DeGolyer and

MacNaughton were developed utilizing their own geological and engineering data, supplemented by data provided by Abraxas. The report of DeGolyer and

MacNaughton dated February 26, 2013, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer and

MacNaughton as well as the qualifications of DeGolyer and MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is

attached as Exhibit 99.1 to this report.

Estimates of reserves at December 31, 2012 were based on studies performed by the engineering department of Abraxas which is directly responsible for

Abraxas’ reserve evaluation process. The Vice President of Engineering manages this department and is the primary technical person responsible for this

process. The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and is a Registered Professional Engineer in the State

of Texas; he has 34 years of experience in reserve evaluations. The operations department of Abraxas assisted in the process, and consists of three petroleum

engineers with Bachelor degrees in Petroleum Engineering, and various other technical professionals. Reserve information as well as models used to estimate

such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, include oil and gas prices, production costs, future

capital expenditures and Abraxas’ net ownership percentages which are obtained from other departments within Abraxas.

Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed by

SEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net

revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are

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variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable

certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are

those expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves were estimated in accordance with

guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no

provision for price and cost escalations or de-escalations except by contractual arrangements. For the year ended December 31, 2012, commodity prices over

the prior 12-month period and year end costs were used in estimating future net cash flows.

In addition to proved reserves, we disclose our “probable” and “possible” reserves in this report. Probable reserves are those additional reserves that

are less likely to be recovered than proved reserves. Possible reserves are those additional reserves that are less likely to be recoverable than probable

reserves. These estimates of probable and possible reserves are by their very nature more speculative than estimates of proved reserves and accordingly are

subject to substantially greater risk of being actually realized by us.

The following table sets forth certain information regarding estimates of our oil and gas reserves as of December 31, 2012. All of our reserves are

located in the United States (approximately 99%) and Canada.

Summary of Oil, NGL and Gas Reserves

As of December 31, 2012

Reserve Category

Oil

(MBbls)

NGL

(MBbls)

Gas

(MMcf)

Oil

Equivalents

(MBoe)

Proved

Developed 7,331.9 1,318.2 41,220.3 15,520.1

Undeveloped 10,009.8 1,296.5 19,964.0 14,633.7

Total Proved 17,341.7 2,614.7 61,184.3 30,153.8

Probable

Developed Producing 16.8 4.0 24.3 24.8

Developed Non-producing 66.3 0.7 369.6 128.6

Undeveloped 12,265.2 2,594.8 58,394.4 24,592.5

Total Probable 12,348.3 2,599.5 58,788.3 24,745.9

Possible

Undeveloped 10,554.9 1,176.8 17,577.6 14,661.3

Total 40,244.9 6,391.0 137,550.2 69,561.0

Our estimates of proved developed reserves, proved undeveloped reserves, and total proved reserves at December 31, 2012, 2011, and 2010, and

changes in proved reserves during the last three years are presented in the Supplemental Oil and Gas Disclosures under Item 8 of this Report. Also presented

in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves.

We have not filed information with a federal authority or agency with respect to our estimated total proved reserves at December 31, 2012. We report

gross proved reserves of operated properties in the United States to the U.S. Department of Energy on an annual basis; these reported reserves are derived from

the same data used to estimate and report proved reserves in this Report.

The process of estimating oil and gas reserves is complex and involves 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 our reserves set forth or incorporated by reference in this report. We may also adjust estimates of

reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our

control. In particular, estimates of oil and gas reserves, future net revenue from reserves and the PV-10 thereof for the oil and gas properties

31
described in this report are based on the assumption that future oil and gas prices remain the same as oil and gas prices utilized in the December 31, 2012

report. The average realized sales prices used for purposes of such estimates were $88.26 per Bbl of oil and $2.61 per Mcf of gas. It is also assumed that we

will make future capital expenditures of approximately $328.6 million in the aggregate primarily in the years 2013 through 2017, which are necessary to

develop and realize the value of proved reserves on our properties. Any significant variance in actual results from these assumptions could also materially

affect the estimated quantity and value of reserves set forth herein.

You should not assume that the present value of future net revenues referred to in this report is the current market value of our estimated oil and gas

reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves is calculated using the average first-dayof-the-month price over the prior 12-month period. Costs used in the estimated discounted future net cash flows are costs as of the end of the period. Because

we use the full cost method to account for our oil and gas operations, we are susceptible to significant non-cash charges during times of volatile commodity

prices because the full cost pool may be impaired when prices are low. This is known as a “ceiling limitation write-down.” This charge does not impact cash

flow from operating activities but does reduce our stockholders’ equity and reported earnings. We have experienced ceiling limitation write-downs in the past

and we cannot assure you that we will not experience additional ceiling limitation write-downs in the future. As of December 31, 2012, the Company’s net

capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves, however, the net capitalized

costs of oil and gas properties in Canada did exceed the present value of our estimated proved reserves by $19.8 million, resulting in a write down for the year

ended December 31, 2012.

For more information regarding the full cost method of accounting, you should read the information under “Management’s Discussion and Analysis

of Financial Condition and Results of Operations – Critical Accounting Policies.”

Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate. Any changes in consumption by gas

purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the

development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In

addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not

necessarily the most accurate discount factor. Our effective interest rate on borrowings at various times and the risks associated with us or the oil and gas

industry in general will affect the accuracy of the 10% discount factor.

Proved Undeveloped Reserves

Changes in PUDs. Significant changes to PUDs occurring during 2012 are summarized in the table below. Revisions of prior estimates reflect the

addition of new PUDs associated with current development plans, revisions to prior PUDs, revisions to infill drilling development plans, as well as the

transfer of PUDs to unproved reserve categories due to changes in development plans during the period. Our year-end development plans are consistent with

SEC guidelines for PUDs development within five years unless specific circumstances warrant a longer development time horizon.

MMBoe

PUDs at December 31, 2011 11,376

Revisions of prior estimates (313)

Extensions, discoveries, and other additions 5,968

Conversion to developed (1,030)

Sales (1,368)

PUDs at December 31, 2012 14,633

Reconciliation of Standardized Measure to PV-10

PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10%

discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is

required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to

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 evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas

companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax

measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10

on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.

The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2011 and 2012:

December 31,

(in thousands) 2011 2012

PV-10 $ 298,001 $ 316,862

Present value of future income taxes discounted at 10% (28,919) (38,717)

Standardized measure of discounted future net cash flows $ 269,082 $ 278,145

Oil and Gas Production, Sales Prices and Production Costs

The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGL and per Mcf of gas produced and

the average cost of production per Boe of production sold, for the three years ended December 31:

2010 2011 2012

Oil production (Bbls)

Rocky Mountain 286,114 310,819 402,869

Permian Basin 107,763 113,151 113,691

Onshore Gulf Coast 75,571 93,182 86,107

Other (4) 29,260 22,738 40,825

Total 498,708 539,890 643,492

Gas production (Mcf)

Rocky Mountain 570,736 474,269 802,001

Permian Basin 2,135,918 1,891,333 1,657,165

Onshore Gulf Coast 1,757,901 1,482,260 1,257,124

Other (4) 1,014,347 373,970 380,789

Total 5,478,902 4,221,832 4,097,079

NGL production (Bbls)

Rocky Mountain 4,228 11,451 23,468

Permian Basin 278 15,171 82,200

Onshore Gulf Coast 79 231 2,036

Other (4) 5,624 1,271 3,047

Total 10,209 28,124 110,751

Total production (MBoe) (1) 1,422 1,272 1,437

Average sales price per Bbl of oil (2)

Rocky Mountain $ 68.79 $ 85.73 $ 81.61

Permian Basin $ 75.94 $ 91.07 $ 87.97

Onshore Gulf Coast $ 77.32 $ 97.09 $ 100.31

Other (4) $ 76.13 $ 91.62 $ 79.66

Composite $ 71.37 $ 89.06 $ 85.11

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Average sales price per Mcf of gas (2)

Rocky Mountain $ 4.28 $ 3.77 $ 2.71

Permian Basin $ 4.00 $ 3.81 $ 2.45

Onshore Gulf Coast $ 3.62 $ 3.31 $ 2.14

Other (4) $ 4.32 $ 3.28 $ 2.00

Composite $ 3.97 $ 3.58 $ 2.36

Average sales price per Bbl of NGL

Rocky Mountain $ 42.03 $ 49.71 $ 37.27

Permian Basin $ 34.48 $ 48.27 $ 35.45

Onshore Gulf Coast $ 38.03 $ 45.75 $ 27.52

Other (4) $ 34.79 $ 75.69 $ 67.28

Composite $ 37.81 $ 50.08 $ 36.57

Average sales price per Boe (2) $ 40.82 $ 50.81 $ 47.67

Average cost of production per Boe produced (3)

Rocky Mountain $ 17.34 $ 19.58 $ 17.41

Permian Basin $ 11.88 $ 13.16 $ 13.11

Onshore Gulf Coast $ 6.06 $ 7.81 $ 8.55

Other (4) $ 9.36 $ 16.89 $ 18.90

Composite $ 13.81 $ 16.94 $ 14.27

__________________

(1) Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil.

(2) Before the impact of hedging activities.

(3) Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.

(4) Includes Canada and Mid-Continent comprising approximately 7.5% of total production.

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Drilling Activities

The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended December

31:

2010 (1) 2011 (2) 2012

Gross Net Gross Net Gross Net

Exploratory

Productive

Rocky

Mountain 1.0 1.0 2.0 1.1 — —

Permian

Basin 1.0 0.4 1.0 1.0 — —

Onshore Gulf

Coast — — — — — —

Other

(3) — — — —- — —-

Total 2.0 1.4 3.0 2.1 — —

Dry wells

Permian

Basin — — 1.0 1.0 — —

Onshore Gulf

Coast 1.0 1.0 — — — —

Total 1.0 1.0 1.0 1.0 — —

Development

Productive

Rocky

Mountain 16.0 1.8 12.0 1.2 22.0 2.6

Permian

Basin 2.0 2.0 2.0 2.0 1.0 1.0

Onshore Gulf

Coast 3.0 3.0 7.0 7.0 2.0 0.5

Other

(3) 3.0 2.0 4.0 4.0 — —

Total 24.0 8.8 25.0 14.2 25.0 4.1

__________________

(1) Excludes 1.0 gross (1.0 net) well drilled by Blue Eagle.

(2) Excludes 2.0 gross (1.4 net) wells drilled by Blue Eagle.

(3) Includes drilling activities in Canada and Mid-Continent.

In addition to the above drilling activity, as of December 31, 2012 we had 16.0 gross (2.96 net) wells that were at various stages of drilling and/or completion.

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Present Activities

As of March 12, 2013, we had eight gross operated wells and five gross non-operated wells in the process of drilling and/or completing. The

following provides an overview of our present activities by region:

Rocky Mountain – North Dakota / Montana

· In the Bakken/Three Forks play in the Williston Basin, in the fourth quarter of 2012 we completed the drilling of our first multi-well pad with our

Company owned drilling rig. The Jore Federal 02-11 3H was the first completion off this pad and was turned to sales in October 2012. We own a

76% working interest in the Jore Federal 02-11 3H. Two additional wells on this pad, the Ravin 26-35 2H and Ravin 26-35 3H, suffered third

party equipment failures during the completion process. Post remediation, the Ravin 26-35 2H and Ravin 26-35 3H were completed and turned to

sales in February 2013.

· In October 2012, we mobilized our Company owned rig to the Lillibridge East pad to commence a four well drilling program. Surface and

intermediate casing have been set on all four Lillibridge wells. We also drilled and cased the lateral on the Lillibridge 20-17 4H. The rig is currently

mobilizing to drill the lateral of the Lillibridge 20-17 3H, which will be followed by laterals of the Lillibridge 20-17 2H and Lillibridge 20-17

1H. We own an approximate 34% working interest across all four wells on the Lillibridge East pad.

· In the non-operated portion of the Company’s Bakken/Three Forks position in the Williston Basin, we have participated in 15 gross (.8 net) nonoperated wells since the fourth quarter of 2012.

South Texas – Eagle Ford

· In the WyCross area of McMullen County, Texas, we drilled and completed two gross (.44 net) wells targeting the Eagle Ford Shale during the fourth

quarter of 2012. Subsequent to the fourth quarter of 2012, we drilled and completed an additional two gross (.44 net) wells. Our sixth well at

WyCross, the Mustang 3H is currently in the latter stages of completion. Abraxas owns an approximate 18.75% working interest in the Mustang

3H. The Company recently reached total depth on our seventh well at WyCross, the Mustang 2H, in which we hold an 18.75% working

interest. We anticipate maintaining a one rig program at WyCross throughout 2013.

Permian Basin

· In Ward County, Texas, we recently drilled and cased two gross (two net) shallow Yates wells, the Wilkes No.1 and Wilkes No.2, since the fourth

quarter of 2012. Early logs on these wells have been encouraging and we expect to complete these wells in the near future.

Canada – Duvernay Shale

· In the Eastern Shale Basin of Alberta Canada, since the fourth quarter of 2012, we entered into a farmout option arrangement with a large

independent whereby we have the option to earn up to approximately 22,000 acres of land targeting the Duvernay Shale upon satisfying various

drilling commitments. This farmout arrangement is incremental to our established 20,000 net acre position in the play. We recently drilled, cored

and cased a vertical well to analyze the rock properties and determine the pressure regime of the Duvernay Shale in the Eastern Shale Basin. The

core from this well is currently under evaluation at a laboratory in Calgary, Alberta, Canada.

Office Facilities

Our executive and administrative offices are located at 18803 Meisner Drive, San Antonio, Texas 78258, and consist of approximately 21,000 square feet. We

own the building which is subject to a real estate lien note. The note bears interest at a fixed rate of 5.25%, and is payable in monthly installments of principal

and interest of $36,652 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is

secured by a first lien deed of trust on the property and improvements. As of December 31, 2012, $4.8 million was outstanding on the note. We lease office

space in Calgary, Alberta for a monthly rental of $3,836 CN. The lease expires on January 31, 2014. We lease office space in Dickinson, North Dakota for a

monthly rental of $2,170. The lease expires on August 31, 2013.

Other Properties

We own 1,769 acres of land, including an office building, workshop, warehouse and house in San Patricio County, Texas, 613 acres of land and an office

building in Scurry County, Texas, 50 acres of land in DeWitt County, Texas, 162 acres of land in Coke County, Texas, 582 acres of land in McKenzie

County, North Dakota and 12,817 acres of land in Pecos County, Texas.

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We own 22 vehicles which are used in the field by employees. We own two workover rigs, which are used for servicing our wells. Raven Drilling

owns a 2000 HP drilling rig, primarily to be used for drilling wells in the Williston Basin. We own two condominiums in Dickinson, North Dakota and a

man-camp in North Dakota to house rig crews.

Item 3. Legal Proceedings

From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31,

2012, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial

condition.

Item 4.Mine Safety Disclosures

Not applicable

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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock is traded on The NASDAQ Stock Market under the symbol "AXAS." The following table sets forth certain information as to

the high and low sales price quoted for our common stock.

Period High Low

2011

First Quarter $ 6.16 $ 4.06

Second Quarter 5.97 3.01

Third Quarter 5.18 2.50

Fourth Quarter 4.45 1.86

2012

First Quarter $ 4.39 $ 3.03

Second Quarter 3.45 2.49

Third Quarter 3.38 1.91

Fourth Quarter 2.42 1.56

2013 First Quarter (Through March 12, 2013) $ 2.37 $ 1.93

Holders

 

 As of March 12, 2013, we had 92,733,448 shares of common stock outstanding and approximately 1,146 stockholders of record.

Dividends

We have not paid any cash dividends on our common stock and it is not presently determinable when, if ever, we will pay cash dividends in the

future. In addition, our credit facility prohibits the payment of cash dividends on our common stock.

Performance Graph

Set forth below is a performance graph comparing yearly cumulative total stockholder return on our common stock with (a) the monthly index of

stocks included in the Standard and Poor’s 500 Index and (b) a market capitalization weighted Small Cap Index of onshore, North American (“NAM”)

focused, U.S. listed, oil and gas exploration and production companies with a market capitalization of less than $1.0 billion as of December 31, 2012 (the

“Comparable Companies”). The Comparable Companies are: Approach Resources, Inc. (AREX), Bill Barrett Corp. (BBG), Callon Petroleum Co. (CPE),

Carrizo Oil & Gas Inc. (CRZO), Clayton Williams Energy, Inc. (CWEI), Comstock Resources Inc (CRK), Crimson Exploration Inc. (CXPO), Double Eagle

Petroleum Co. (DBLE), Emerald Oil, Inc. (EOX), Enerjex Resources, Inc. (ENRJ), Evolution Petroleum Corp. (EPM), Forest Oil Corporation (FST), Gasco

Energy Inc. (GSX), Gastar Exploration, Ltd. (GST), GMX Resources Inc. (GMXR), Goodrich Petroleum Corp. (GDP), Magnum Hunter Resources Corp.

(MHR), Northern Oil and Gas, Inc. (NOG), Panhandle Oil and Gas Inc. (PHX), PDC Energy, Inc (PDCE), Penn Virginia Corporation (PVA), PetroQuest

Energy Inc. (PQ), Quicksilver Resources, Inc. (KWK), Rex Energy Corporation (REXX), Swift Energy Co. (SFY), Triangle Petroleum Corporation (TPLM),

US Energy Corp. (USEG), Warren Resources Inc. (WRES) and ZaZa Energy Corporation (ZAZA).

All of these cumulative total returns are computed assuming the value of the investment in our common stock and each index as $100.00 on

December 31, 2007, and the reinvestment of dividends at the frequency with which dividends were paid during the applicable years. The years compared are

2008, 2009, 2010, 2011 and 2012.

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12/31/2007 12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012

S&P 500 $ 100.00 $ 61.51 $ 75.94 $ 85.65 $ 85.65 $ 97.13

Small Cap Index $ 100.00 $ 53.57 $ 60.44 $ 92.07 $ 73.39 $ 52.50

AXAS $ 100.00 $ 18.65 $ 49.74 $ 118.39 $ 85.49 $ 56.74

The information contained above under the caption “Performance Graph” is being “furnished” to the SEC and shall not be deemed to be “soliciting

material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as

amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate it by reference into such filing.

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Item 6. Selected Financial Data

The following selected financial data is derived from our Consolidated Financial Statements as of and for the years ended December 31, 2008

through 2012. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto and other financial information included

herein. See “Financial Statements and Supplementary Data” in Item 8.

Year Ended December 31,

2008 2009 2010 2011 2012

(In thousands, except per share data)

Total revenue $ 99,100 $ 51,836 $ 58,060 $ 64,622 $ 68,573

Net income (loss) $ (52,403) (1) $ (18,780) $ 1,766 (2) $ 13,743 $ (18,791) (3) 

Net income (loss) per common share –

diluted $ (1.07) $ (0.34) $ 0.02 $ 0.15 $ (0.20)

Weighted average shares outstanding –

diluted 49,005 55,499 77,224 92,244 91,914

Total assets $ 211,839 $ 176,236 $ 182,909 $ 241,150 $ 240,607

Long-term debt, excluding current

maturities $ 130,835 $ 143,592 $ 140,940 $ 126,258 $ 124,101

Total stockholders’ equity (deficit) $ 4,658 $ (18,363) $ (14,976) $ 62,651 $ 46,700

(1) Includes proved property impairment of $116.4 million.

(2) Includes proved property impairment of $4.8 million related to our Canadian properties.

(3) Includes proved property impairment of $19.8 million related to our Canadian properties.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion excludes

the operations of Blue Eagle, except our equity share of Blue Eagle’s income (loss). The Blue Eagle joint venture was dissolved effective August 31, 2012. This

discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See “Financial Statements and Supplementary

Data” in Item 8.

General

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas in

the United States and Canada. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties,

principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D

seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In

addition, we intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our

development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves.

While we have attained positive net income in two of the last five years, there can be no assurance that operating income and net earnings will be

achieved in future periods. Our financial results depend upon many factors which significantly affect our results of operations including the following:

· commodity prices and the effectiveness of our hedging arrangements;

· the level of total sales volumes of oil and gas;

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

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· the level of and interest rates on borrowings; and

· the level and success of exploration and development activity.

Commodity Prices and Hedging Arrangements. The results of our operations are highly dependent upon the prices received for our oil and gas production.

The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts, which we

sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot

market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon

numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of

operations, cash flows and quantities of reserves recoverable on an economic basis. 

The prices of oil and gas have been volatile. During 2012, the price of oil decreased from the levels experienced in 2011. The New York Mercantile

Exchange (NYMEX) price for West Texas Intermediate crude oil (WTI) averaged $94.16 per barrel in 2012 as compared to $96.19 per barrel in 2011.

During 2012, the average price of gas decreased from an average NYMEX Henry Hub spot price of $4.16 per MMBtu in 2011 to $2.83 per MMBtu in 2012.

Prices closed on December 31, 2012 at $91.82 per Bbl of oil and $3.43 per MMBtu of gas. If commodity prices decline, our revenue and cash flow from

operations will also likely decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. If gas

prices remain depressed or oil prices decline significantly, our revenues, profitability and cash flow from operations may decrease which could cause us to

alter our business plans, including reducing our drilling activities.

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

· basis differentials which are dependent on actual delivery location;

· adjustments for BTU content; and

· gathering, processing and transportation costs.

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The following table sets forth our average differentials for the years ended December 31, 2010, 2011 and 2012:

Oil Gas

2010 2011 2012 2010 2011 2012

Average realized price $ 71.37 $ 89.06 $ 85.11 $ 3.97 $ 3.58 $ 2.36

Average NYMEX price $ 79.51 $ 95.06 $ 94.16 $ 4.38 $ 4.14 $ 2.83

Differential $ (8.14) $ (6.00) $ (9.05) $ (0.41) $ (0.56) $ (0.47)

Our hedging arrangements equate to approximately 60% of the estimated oil production from our net proved developed producing reserves (as of December

31, 2012) through December 31, 2013, 80% in 2014, 78% in 2016 and 81% for 2016. By removing a significant portion of price volatility on our future oil

and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for

those periods. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the

production that has been hedged. We have in the past and will in the future sustain realized and unrealized losses on our derivative contracts if market prices

are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains

on our commodity derivative contracts. In 2011, we incurred a realized gain of $1.7 million and an unrealized gain of $5.7 million. In 2012, we incurred a

realized loss of $0.3 million and an unrealized gain of $2.7 million. We have not designated any of these derivative contracts as a hedge as prescribed by

applicable accounting rules.

The following table sets forth the summary position of our derivative contracts at December 31, 2012:

Oil

Contract Periods

Daily Volume

(Bbl)

Swap Price

(per Bbl)

2013 1,341 $ 86.70

2014 1,100 $ 92.58

2015 933 $ 85.00

2016 883 $ 84.00

At December 31, 2012, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $6.4 million.

On March 12, 2012, we monetized our gas derivative contracts for $12.4 million.

Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containing

proved reserves or conduct successful exploration and development activities. Based on the reserve information set forth in our reserve estimates as of

December 31, 2012, our average annual estimated decline rate for net proved developed producing reserves is 13% during the first five years, 8% in the next

five years, and approximately 7% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have had

some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural

field declines and property sales. Our ability to acquire or find additional reserves in the future will be dependent, in part, upon the amount of available funds

for acquisition, exploration and development projects.

We had capital expenditures during 2012 of $68.6 million related to our exploration and development activities. We have a capital expenditure budget for

2013 of $70 million. Approximately 68% of the 2013 budget will be spent on unconventional horizontal oil wells in the Bakken/Three Forks and Niobrara

plays in the Rocky Mountain region, approximately 27% in the Eagle Ford Shale play in South Texas with the remainder targeting conventional oil plays in the

Permian Basin region and in the province of Alberta, Canada. The 2013 capital expenditure budget is subject to change depending upon a number of factors,

including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing and

anticipated prices for oil and gas, the availability of sufficient capital resources, the results of our exploitation efforts, and our ability to obtain permits for

drilling locations.

The following table presents historical net production volumes for the years ended December 31, 2010, 2011 and 2012:

Year Ended December 31,

2010 2011 2012

Total production (MBoe) 1,422 1,272 1,437

Average daily production (Boepd) 3,896 3,484 3,926

% Oil/ NGL 36% 45% 52%

Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operating

activities, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriate

opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. As

of December 31, 2012, we had approximately $37.0 million of availability under our credit facility.

Borrowings and Interest. At December 31, 2012, we had a total of $113.0 million outstanding under our credit facility. If interest expense increases as

a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we

would need to increase our cash flow from operations in order to fund the development of our drilling opportunities which, in turn, will be dependent upon

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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, to fix our floating LIBOR-based debt. The two-year interest rate swap for $100 million at a fixed rate of 3.367% originally expired on August 12,

2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November

2009, lowering our fixed rate to 2.55% and extending the term through August 12, 2012. The interest rate swap expired in August 2012.

Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects

position us for future growth. At December 31, 2012, we operated properties accounting for approximately 81% of our PV-10, giving us substantial control

over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds, the

successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31, 2012,

we drilled or participated in 146 gross (41.29 net) wells of which 99% were commercially productive.

Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that

are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we

acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify

additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in

our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and the

amount that we are able to borrow under our credit facility may also decline. In addition, approximately 49% of our estimated proved reserves at December 31,

2012 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital

expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves, in which case our results of operations and

financial condition could be adversely affected.

Results of Operations

Selected Operating Data. The following table sets forth operating data for the periods presented.

Year Ended December 31,

(In thousands, except per unit data)

2010 2011 2012

Operating revenue (1):

Oil sales $ 35,935 $ 48,080 $ 54,770

Gas sales 21,729 15,127 9,679

NGL sales 386 1,408 4,050

Total operating revenues $ 58,050 $ 64,615 $ 68,499

Operating income (loss) (2) $ 2,807 $ 11,648 $ (16,348)

Oil sales (MBbls) 498.7 539.9 643.5

Gas sales (MMcf) 5,478.9 4,221.8 4,097.1

NGL sales (MBbls) 10.2 28.1 110.8

Oil equivalents (MBoe) 1,422.1 1,271.6 1,437.1

Average oil sales price (per Bbl)(1) $ 71.37 $ 89.05 $ 85.11

Average gas sales price (per Mcf)(1) $ 3.97 $ 3.58 $ 2.36

Average NGL sales price (per Bbl) $ 37.81 $ 50.07 $ 36.57

Average oil equivalent sales price (Boe) $ 40.82 $ 50.81 $ 47.67

___________________

(1) Revenue and average sales prices are before the impact of hedging activities.

(2) Operating income includes a proved property impairment of $4.8 million and $19.8 million in 2010 and 2012, respectively related to our

Canadian properties.

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Comparison of Year Ended December 31, 2012 to Year Ended December 31, 2011

Operating Revenue. During the year ended December 31, 2012, operating revenue increased to $68.5 million from $64.6 million in 2011. The increase

in revenue was due to higher oil and NGL sales volumes in 2012 as compared to 2011, which were partially offset by lower gas sales volumes and lower

realized commodity prices. Overall BOE sales in 2012 increased approximately 12% as compared to 2011. Increased oil and NGL sales volumes contributed

$11.8 million to operating revenue while decreased gas sales volumes had a negative impact of $0.3 million. Lower commodity prices had a negative impact on

operating revenue of $7.7 million.

Oil sales volumes increased to 643.5 MBbls for the year ended December 31, 2012 from 539.9 MBbls for the same period of 2011. The increase in oil

sales volumes was due to new production brought on line in 2012. New wells brought onto production in 2012 contributed 129.2 MBbls to production for the

year ended December 31, 2012, offset by natural field declines. Gas sales volumes decreased to 4,097.1 MMcf for the year ended December 31 2012 from

4,221.8 MMcf for the year ended December 31, 2011. The decrease in gas production was due to natural field declines and the timing of new wells being

brought on line, as well as our emphasis on drilling oil wells as opposed to gas wells. New wells brought onto production during 2012 contributed 361.7

MMcf to production for the year ended December 31, 2012. Due to weak gas prices, our focus was primarily on oil projects during 2012. NGL sales

increased to 110.8 MBbls for the year ended December 31, 2012 from 28.1 MBbls for the same period of 2011. The increase in NGL sales was primarily due

to increased gas production in West Texas, Wyoming and North Dakota that has a higher NGL content than our historical gas production.

Lease Operating Expenses (“LOE”). LOE for the year ended December 31, 2012 increased to $24.8 million from $21.6 million in 2011. The

increase in LOE was primarily due to increased cost of services, and significant non-recurring LOE related to our Canadian operations. LOE per Boe for the

year ended December 31, 2012 was $17.26 compared to $16.97 for the same period of 2011. The increase in LOE per Boe was attributable to higher LOE in

2012, partially offset by higher sales volumes in 2012 as compared to 2011.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2012 increased to $6.6 million from $5.8

million in 2011. The increase was primarily due to increased production, particularly in the Rocky Mountain region where production tax rates are higher.

Production and ad valorem taxes as a percentage of oil and gas revenue increased to 10% for the year ended December 31, 2012 from 9% in 2011.

General and Administrative (“G&A”) Expense. G&A expense, excluding stock-based compensation, increased to $8.6 million for the year ended

December 31, 2012 from $7.4 million in 2011. The increase in G&A expense was primarily related to higher salaries and bonuses paid in 2012. G&A

expense per Boe was $6.00 for the year ended December 31, 2012 compared to $5.85 for the same period of 2011. The increase in G&A expense per Boe was

primarily due to higher production volumes in 2012 compared to 2011.

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options

vesting period. In addition to options, restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized over

their vesting period. Stock-based compensation for the year ended December 31, 2012 increased to $2.1 million from $2.0 million in 2011. The increase in

2012 as compared to 2011 was due to higher values of grants made during 2012 as compared to 2011, and to additional grants during the third quarter of

2012.

Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense increased to $23.0 million for the year ended December 31, 2012

from $16.2 million in 2011. Our DD&A rate increased due to higher future development cost in the 2012 year end reserve report. DD&A per Boe for 2012

was $16.02 compared to $12.73 in 2011. The increase in DD&A per BOE was due to higher future development cost offset by higher sales volumes in 2012

as compared to 2011.

Interest Expense. Interest expense increased to $5.5 million in 2012 from $4.9 million for 2011. The increase was primarily due to higher levels of debt

during 2012 as compared to 2011

Income Taxes. An income tax expense of $0.3 million was recognized in 2012 as a result of an ongoing audit of our 2009 Federal income tax return. We

do not agree with the findings of the audit and it is currently under appeal.

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Loss (Gain) on Derivative Contracts. Realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized

gains and losses are based on the periodic mark to market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our

derivative contracts as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the

current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The net estimated value of our commodity derivative contracts

was a liability of approximately $6.4 million as of December 31, 2012. When our derivative contract prices are higher than prevailing market prices, we incur

realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized

losses. For the year ended December 31, 2012, we realized a loss on our derivative contracts of approximately $0.5 million, which included a realized loss of

approximately $0.3 million on our commodity swaps and a realized loss of approximately $0.2 million on our interest rate swap. For the year-ended December

31, 2012, we incurred an unrealized gain of $2.7 million on our commodity swaps. We monetized our gas derivative contracts in March 2012 for $12.4

million. Our interest rate swap expired in August 2012. The estimated value of our derivative contracts was an asset of approximately $1.9 million as of

December 31, 2011. For the year ended December 31, 2011, we realized a loss on our derivative contracts of approximately $0.7 million, which included a

realized gain of $1.7 million on our commodity swaps and a realized loss of $2.4 million on our interest rate swap. For the year-ended December 31, 2011, we

incurred an unrealized gain of $7.5 million on our derivative contracts, which included an unrealized gain of $5.7 million on our commodity swaps and $1.8

million on our interest rate swap.

Ceiling Limitation Write-Down. 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 less related deferred taxes, 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, less related income

taxes. 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 stockholders' equity and reported earnings. As of December 31, 2011, our net capitalized costs of oil and gas properties in the United States

and Canada did not exceed the present value of our estimated proved reserves. As of December 31, 2012, the net capitalized cost of our oil and gas properties in

the United States did not exceed the present value of our estimated proved reserves, however in Canada, the net capitalized cost exceeded the present value of

our estimated proved reserves by $19.8 million, resulting in a write down of $19.8 million. There were write downs in the second, third and fourth quarters

of 2012 of $1.3 million, $11.8 million and $6.7 million respectively. The year-end amount was calculated in accordance with SEC rules utilizing the twelve

month first-day-of-the-month average oil and gas prices for the year ended 2012 which were $95.14 per Bbl for oil and $2.86 per Mcf for gas as adjusted to

reflect the expected realized prices for our oil and gas reserves.

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. 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.

Equity in (Income) Loss of Joint Venture. We accounted for Blue Eagle under the equity method of accounting. Under this method, Abraxas’ share of

net income (loss) from the joint venture was reflected as an increase (decrease) in its investment account in “Investment in joint venture” and is also recorded

as equity investment income (loss) in “Equity in loss (income) of joint venture.” For the year ended December 31, 2011, our net share of the joint venture’s

income was $2.2 million. The joint venture was dissolved on September 4, 2012, effective August 31, 2012, with the assets being distributed to the joint

venture partners. The dissolution of the joint venture was accounted for with the net investment in the joint venture being added to our full cost pool. For the

year ended December 31, 2012 (through August 31, 2012), we reported income of $2.2 million related to Blue Eagle. See Note 2 of the Notes to Consolidated

Financial Statements.

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Comparison of Year Ended December 31, 2011 to Year Ended December 31, 2010

Operating Revenue. During the year ended December 31, 2011, operating revenue increased to $64.6 million from $58.1 million in 2010. The increase

in revenue was due to higher realized oil and NGL prices in 2011 as compared to 2010 which were partially offset by decreased prices for gas. Increased oil

and NGL prices contributed $8.6 million to operating revenue while decreased gas prices had a negative impact of $2.1 million. Increased sales volumes of oil

and NGLs were offset by a decrease in gas sales. Increased oil and NGL sales contributed $4.6 million to operating revenue. Decreased gas sales had a

negative impact of $4.5 million on operating revenue.

Oil sales volumes increased to 539.9 MBbls for the year ended December 31, 2011 from 498.7 MBbls for the same period of 2010. The increase in oil

sales volumes was due to new production brought on line in 2011. New wells brought onto production in 2011 contributed 94.3 MBbls to production for the

year ended December 31, 2011, offset by sales of non-core properties during 2010 and natural field declines. The divested properties produced 29.5 MBbls

during 2010. Gas sales volumes decreased to 4,221.8 MMcf for the year ended December 31 2011 from 5,478.9 MMcf for the year ended December 31,

2010. The decrease in gas production was due to sales of non-core properties during 2010, natural field declines and the timing of new wells being brought on

line. The divested properties produced 754.9 MMcf in 2010. New wells brought onto production during 2011 contributed 148.7 MMcf to production for the

year ended December 31, 2011. Due to weak gas prices, our focus was primarily on oil projects during 2011. NGL sales increased to 28.1 MBbls in for the

year ended December 31, 2011 from 10.2 MBbls for the same period of 2010. The increase in NGL sales was primarily due to increased gas production in

West Texas and North Dakota that has a higher NGL content than our historical gas production.

Lease Operating Expenses (“LOE”). LOE for the year ended December 31, 2011 increased to $21.6 million from $19.5 million in 2010. The

increase in LOE was primarily due to increased cost of services. LOE per Boe for the year ended December 31, 2011 was $16.97 compared to $13.69 for the

same period of 2010. The increase in LOE per Boe was attributable to lower sales volumes and higher costs in 2011 as compared to 2010.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2011 decreased to $5.8 million from $5.9

million in 2010 as a result of lower gas prices, which were offset by higher oil prices. Production and ad valorem taxes as a percentage of oil and gas revenue

decreased to 9% for the year ended December 31, 2011 from 10% in 2010. In addition, total sales volumes were lower in 2011 as compared to 2010.

General and Administrative (“G&A”) Expense. G&A expense, excluding stock-based compensation, increased to $7.4 million for the year ended

December 31, 2011 from $7.3 million in 2010. The increase in G&A expense was primarily related to higher salaries in 2011. G&A expense per Boe was

$5.85 for the year ended December 31, 2011 compared to $5.14 for the same period of 2010. The increase in G&A expense per Boe was primarily due to

lower production volumes and higher costs in 2011 compared to 2010.

Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options

vesting period. In addition to options, restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized over

their vesting period. Stock-based compensation for the year ended December 31, 2011 increased to $2.0 million from $1.6 million in 2010. The increase in

2011 as compared to 2010 was due to higher values of grants made during 2011 as compared to 2010, and to additional grants during the third quarter of

2011.

Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense for the years ended December 31, 2011 and 2010 was constant at

$16.2 million in each year. Our DD&A rate increased due to higher future development cost in the 2011 year end reserve report, offset by higher reserves.

DD&A per Boe for 2011 was $12.73 compared to $11.40 in 2010. The increase in DD&A per BOE was due to lower sales volumes in 2011 as compared to

2010.

Interest Expense. Interest expense decreased to $4.9 million in 2011 from $9.1 million for 2010. The decrease in interest expense for the year ended

December 31, 2011 was primarily due to lower levels of debt as compared to 2010 and lower interest rates.

Income Taxes. An income tax benefit of $79,000 was recognized in 2010 as a result of a decrease in the $1.3 million tax basis gain on the merger of

Abraxas Energy Partners, L.P. into Abraxas. In 2011, we recognized a tax benefit of $77,000 as the result of a refund of alternative minimum tax paid in 2010.

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Loss (Gain) on Derivative Contracts. We account for derivative contract gains and losses based on realized and unrealized amounts. The realized

derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to

market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by ASC 815;

therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consist of

commodity swaps and interest rate swaps. The net estimated value of our commodity and interest rate derivative contracts was an asset of approximately $1.9

million as of December 31, 2011. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and

conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the year ended December

31, 2011, we realized a loss on our derivative contracts of $0.7 million, which included a realized gain of $1.7 million on our commodity swaps and a

realized loss of $2.4 million on our interest rate swap. For the year-ended December 31, 2011, we incurred an unrealized gain of $7.5 million on our derivative

contracts, which included an unrealized gain of approximately $5.7 million on our commodity swaps and $1.8 million on our interest rate swap. The

estimated value of our derivative contracts was a liability of approximately $5.8 million as of December 31, 2010. For the year ended December 31, 2010, we

realized a gain on our derivative contracts of approximately $0.5 million, which included a realized gain of $2.8 million on our commodity swaps and a

realized loss of $2.3 million on our interest rate swap. For the year-ended December 31, 2010, we incurred an unrealized gain of $10.3 million on our

derivative contracts, which included an unrealized gain of $11.4 million on our commodity swaps and an unrealized loss of $1.1 million on our interest rate

swap.

Ceiling Limitation Write-Down. 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 less related deferred taxes, 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, less related income

taxes. 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 stockholders' equity and reported earnings. As of December 31, 2011, our net capitalized costs of oil and gas properties in the United States

and Canada did not exceed the present value of our estimated proved reserves. As of December 31, 2010, the net capitalized cost of our oil and gas properties in

the United States did not exceed the present value of our estimated proved reserves, however, the net capitalized cost of our Canadian properties exceeded the

present value of our estimated proved reserves by $4.8 million, resulting in a write down of $4.8 million. These amounts were calculated in accordance with

SEC rules utilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2010 which were $79.43 per Bbl for oil and $4.45

per Mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves.

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. 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.

Equity in (Income) Loss of Joint Venture. We accounted for Blue Eagle under the equity method of accounting. Under this method, Abraxas’ share of

net income (loss) from the joint venture was reflected as an increase (decrease) in its investment account in “Investment in joint venture” and was also

recorded as equity investment income (loss) in “Equity in loss (income) of joint venture.” For the year ended December 31, 2011, our net share of the joint

venture’s income was $2.2 million. For the year ended December 31, 2010, our net share of the joint venture’s loss was approximately $0.5 million.

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 and to fund the following:

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

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· acquisition of interests in additional oil and gas properties; and

· production and transportation facilities.

The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly

affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of new properties.

Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties,

and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financings on terms acceptable to us, if

at all.

Working Capital (Deficit). At December 31, 2012, our current liabilities of $54.5 million exceeded our current assets of $23.0 million resulting in a

working capital deficit of $31.5 million. This compares to a working capital deficit of $14.8 million at December 31, 2011. Current assets at December 31,

2012 primarily consist of cash of $2.1 million, and accounts receivable of $20.4 million. Current liabilities at December 31, 2012 primarily consist of trade

payables of $42.4 million, revenues due third parties of $6.9 million and the current portion of derivative liabilities of $3.5 million.

Capital Expenditures. Capital expenditures in 2010, 2011 and 2012 were $36.4 million, $79.0 million and $68.6 million, respectively. The table

below sets forth the components of these capital expenditures:

Year Ended December 31,

2010 2011 2012

(In thousands)

Expenditure category:

Acquisition of producing properties $ — $ — $ 7,200

Exploration/Development 36,172 56,245 57,307

Facilities and other 276 22,767 4,045

Total $ 36,448 $ 79,012 $ 68,552

During 2010 capital expenditures were primarily for the development of our existing properties. During 2011, capital expenditures were for the

development of our existing properties, the purchase and refurbishment of a drilling rig, and the purchase of 1,769 acres of land (surface only) in our Portilla

field in San Patricio County, Texas. During 2012 our expenditures were primarily for development of our existing properties, the acquisition of producing

properties in West Texas and the completion of the refurbishment of our drilling rig.

We anticipate making capital expenditures in 2013 of $70.0 million. The 2013 capital expenditure budget is subject to change depending upon a number of

factors, including the availability and costs of drilling and service equipment and crews, economic and industry conditions at the time of drilling, prevailing

and anticipated prices for oil and gas, the availability of sufficient capital resources, and our ability to obtain permits for drilling locations. Our capital

expenditures could also include expenditures for the acquisition of producing properties, if such opportunities arise. Additionally, the level of capital

expenditures will vary during future periods depending on economic and industry conditions and commodity prices. Should the prices of oil and gas decline

and if our costs of operations increase or if our production volumes decrease, our cash flows will decrease which may result in a reduction of the capital

expenditure budget. If we decrease our capital expenditure budget, we may not be able to offset oil and gas production decreases caused by natural field

declines.

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Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following

table and discussed in further detail below: 

Year Ended December 31,

2010 2011 2012

(In thousands)

Net cash provided by operating activities $ 24,102 $ 24,495 $ 51,375

Net cash used in investing activities (15,048) (70,555) (47,003)

Net cash (used in) provided by financing activities (10,816) 45,966 (2,311)

Total $ (1,762) $ (94) $ 2,061

Operating activities for the year ended December 31, 2012 provided $51.4 million in cash. Non-cash expense items, net changes in operating assets and

liabilities, including the non-cash property impairment of $19.8 million, and the monetization of our gas derivatives accounted for most of these funds.

Investing activities used $47.0 million, primarily for the development of our oil and gas properties, acquisition of producing properties, and the completion of

the refurbishment of our drilling rig offset by the sale of producing properties. Financing activities used $2.3 million primarily for the reduction of long-term

debt.

Operating activities for the year ended December 31, 2011 provided $24.5 million in 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 $46.0 million for the year ended December 31, 2011 which

was primarily from the net proceeds from our equity offering in February 2011 of $62.3 million offset by a net reduction in our long term debt. Investing

activities used $70.6 million in 2011 for the development of our oil and gas properties, the purchase and reconditioning of a drilling rig and the purchase of

1,769 acres of land (surface only) in our Portilla field in San Patricio County, Texas.

Operating activities for the year ended December 31, 2010 provided $24.1 million in cash. Net income plus non-cash expense items and net changes in

operating assets and liabilities accounted for most of these funds, including the non-cash property impairment of $4.8 million. Financing activities used $10.8

million for the year ended December 31, 2010 which was predominately the reduction of long-term debt. Investing activities used $15.0 million in 2010 for the

development of our oil and gas properties, net of proceeds from sale of properties of $21.4 million.

Future Capital Resources. Our principal sources of capital going forward are cash flow from operations, borrowings under our credit facility, cash on

hand, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete

financing on terms acceptable to us, if at all.

Cash from operating activities is dependent upon commodity prices and production volumes. A decrease in commodity prices from current levels could

reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Unless

we otherwise expand and develop reserves, our production volumes may decline as reserves are produced. In the future we may continue to sell producing

properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of

producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify and develop

additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes;

however, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be found. If our

proved reserves 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. The risk of not finding commercially productive reservoirs will be compounded by the fact that 49% of our

total estimated proved reserves at December 31, 2012 were classified as undeveloped.

We have in the past, and may in the future, sell producing properties. Most recently, in the third quarter of 2012, we sold certain non-core assets for

combined net proceeds of approximately $21.5 million. The net proceeds were used to repay outstanding indebtedness under our credit facility and general

corporate purposes.

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We have also sold debt and equity securities in the past when the opportunity has presented itself. On February 1, 2011, we closed a public offering of

23.6 million shares of common stock (of which 8.5 million shares were sold by certain selling stockholders) at a public offering price of $4.40 per share for

total net proceeds to us of approximately $62.2 million, after fees and expenses.

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

· Long-term debt, and

· Operating leases for office facilities.

Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2012:

Payments due in twelve month periods ending:

Contractual Obligations

(In thousands) Total

December 31,

 2013

December 31,

2014-2015

December 31,

2016-2017 Thereafter

Long-term debt (1) $ 124,758 $ 657 $ 121,481 $ 2,620 $ —

Interest on long-term debt (2) 1,340 545 720 75 —

Lease obligations (3) 67 63 4 — —

Total $ 126,165 $ 1,265 $ 122,205 $ 2,695 $ —

____________

(1) These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These payments

assume that we will not borrow additional funds.

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

(3) Lease on office space in Calgary, Alberta, which expires on January 31, 2014 and office space in Dickinson, North Dakota, which expires on

August 31, 2013.

We maintain a reserve for costs associated with the retirement of tangible long-lived assets. At December 31, 2012, our reserve for these obligations

totaled $11.4 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes to Consolidated

Financial Statements.

Off-Balance Sheet Arrangements. At December 31, 2012, we had no existing off-balance sheet arrangements, as defined under SEC regulations,

that have, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity,

capital expenditures or capital resources that are material to investors.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At

December 31, 2012, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.

Other obligations. We make and will continue to make substantial capital expenditures for the acquisition, exploration, development and

production of oil and gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, borrowings under

our credit facility, cash on hand, proceeds from the sale of properties, sales of debt and equity securities and other sources. Given our high degree of operating

control, the timing and incurrence of operating and capital expenditures is largely within our discretion.

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Long-Term Indebtedness.

Long-term debt consisted of the following:

December

31,2011

December 31,

2012

(In thousands)

Credit facility $ 115,000 $ 113,000

Rig loan agreement 6,500 7,000

Real estate lien note 4,939 4,758

126,439 124,758

Less current maturities (181) (657)

$ 126,258 $ 124,101

Credit Facility

We have a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as

the credit facility. As of December 31, 2012, $113.0 million was outstanding under the credit facility.

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At December 31, 2012 we had a

borrowing base of $150.0 million. This amount will remain in effect until the next redetermination of the borrowing base which is scheduled to be completed

in April 2013. The borrowing base 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 securing the facility utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole

discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we are able to

request one redetermination during any six-month period between scheduled redeterminations. The borrowing base will be automatically reduced in connection

with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination

which could reduce the collateral value by 5% or more. Our borrowing base was increased to $150.0 million based upon our reserve report dated June 30,

2012 and did not include any of the properties held for sale. Our borrowing base can never exceed the $300.0 million maximum commitment

amount. Outstanding amounts under the 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) 1.25—2.25%,

depending on the utilization of the borrowing base, or, if we elect LIBOR plus 2.25%—3.25%, depending on the utilization of the borrowing base. At

December 31, 2012, the interest rate on the credit facility was 3.21% based on 1-month LIBOR borrowings and level of utilization.

Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2015. Interest is payable quarterly on

reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to

permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured

by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and

assets, other than Raven Drilling.

Under the 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 of not less than 2.50 to 1.00. We are also

required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 4.00 to 1.00 and liquidity (defined as the sum of our

borrowing base availability, liquid investments and unrestricted cash) of at least $7.5 million for each fiscal quarter ending on or after June 30, 2012 and on

or before March 31, 2013. The current ratio is defined as 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 excludes any cash deposited with a counter-party to a hedging

arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the

current portion of long-term debt and any liabilities representing a

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valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to

consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is consolidated net

income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash

charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the

settlement or monetization of any hedge contracts 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 ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and

expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four

fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt

associated with the office building, and obligations with respect to surety bonds and hedge arrangements.

As of December 31, 2012, the interest coverage ratio was 7.72 to 1.00, the total debt to EBITDAX ratio was 2.97 to 1.00, our current ratio was 1.19 to

1.00 and we had liquidity of $39.1 million of which $37.0 was availability under the credit facility. At December 31, 2012, we were in compliance with all of

our debt covenants.

The credit facility contains a number of covenants that, among other things, 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.

The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and

cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Rig Loan Agreement

On September 19, 2011, Raven Drilling entered into a rig loan agreement with RBS Asset Finance, Inc. to finance the costs of purchasing and

refurbishing an Oilwell 2000 HP diesel electric drilling rig (the “Collateral”). The rig loan agreement provided for interim borrowings payable to Raven Drilling

until the final amount of the loan was determined. 

On February 14, 2012, Raven Drilling finalized the note with respect to the rig loan agreement. The principal amount of the note is $7.0 million and

bears interest at 4.26%. Interest only is due for the first 18-months of the note and thereafter, the note will amortize in full over the remaining life of the

note. Interest and principal, when required, is payable monthly. Subject to earlier prepayment provisions and events of default, the stated maturity date of the

note is February 14, 2017. As of December 31, 2012, $7.0 million was outstanding under the rig loan agreement.

The Company has guaranteed Raven Drilling’s obligations under the rig loan agreement and associated note. Obligations under the rig loan agreement are

secured by a first priority perfected security interest, subject to certain permitted encumbrances, in the Collateral.

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Real Estate Lien Note

On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to

serve as its corporate headquarters. This note was refinanced in November 2008. The note bears interest at a fixed rate of 5.25% and is payable in monthly

installments of principal and interest of $36,652 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance

becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2012, $4.8 million was outstanding on

the note.

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. We have entered into commodity swaps on approximately 60%

of our estimated oil production from our net proved developed producing reserves (as of December 31, 2012) through December 31, 2013, 80% for 2014, 78%

for 2015 and 81% for 2016.

The following table sets forth the summary position of our derivative contracts as of December 31, 2012:

Oil

Contract Periods

Daily Volume

(Bbl)

Swap Price

(per Bbl)

2013 1,341 $ 86.70

2014 1,100 $ 92.58

2015 933 $ 85.00

2016 883 $ 84.00

By removing a significant portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the

potential effects of changing commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices,

we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained, and in the future will sustain, realized and

unrealized losses on our derivative contracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than

our contract prices, we will sustain realized and unrealized gains on our commodity derivative contracts. For the year ended December 31, 2012, we incurred a

realized loss of $0.3 million and an unrealized gain of $2.7 million on our commodity derivative contracts. For the year ended December 31, 2011, we

incurred a realized gain of $1.7 million and an unrealized gain of $5.7 million on our commodity derivative contracts. For the year ended December 31, 2010,

we incurred a realized gain of $2.8 million and an unrealized gain of $11.4 million on our commodity derivative contracts. If the disparity between our

contract prices and market prices continues, we will sustain realized and unrealized gains or losses on our derivative contracts. While unrealized gains and

losses do not impact our cash flow from operations, realized gains and losses do impact our cash flow from operations. 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 existing derivative contracts, our future cash flow from operations would likely be materially lower. In addition, borrowings under

our credit facility bear interest at floating rates. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from

operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the

development of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.

On March 12, 2012, we monetized our gas derivative contracts for $12.4 million.

See “—Quantitative and Qualitative Disclosures about Market Risk—Hedging Sensitivity” for further information.

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Net Operating Loss Carryforwards

At December 31, 2012, we had, subject to the limitation discussed below, $169.6 million of net operating loss carryforwards for U.S. tax purposes

and $15.0 million for Canadian tax purposes. The U.S. loss carryforwards will expire through 2032 and the Canadian carryforward will expire in 2032, if

not utilized.

Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10 “Income Taxes ”.

Therefore, we have established a valuation allowance of $89.7 million for deferred tax assets at December 31, 2012.

We account for uncertain tax positions under provisions of ASC 740-10. ASC 740-10 did not have any effect on the Company’s financial position or

results of operations for the year ended December 31, 2011 or for the year ended December 31, 2012. The Company recognizes interest and penalties related to

uncertain tax positions in income tax expense. As of December 31, 2012, the Company did not have any accrued interest or penalties related to uncertain tax

positions. The tax years from 2001 through 2011 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and

Abraxas Energy Partners, L.P., which was merged into a wholly owned subsidiary of Abraxas, have undergone an audit of their 2009 Federal income tax

returns. The audit of the Federal income tax return of Abraxas Energy Partners, L.P. was completed with no changes. The audit of Abraxas Petroleum

Corporation resulted in a notice of proposed adjustment of $619,000. The Company does not agree with the findings and intends to aggressively appeal the

proposed adjustment; however, no assurances can be made that such appeals will be successful. For the year ended December 31, 2012, the Company

accrued $310,000 in income tax expense related to the recent audit of its 2009 Federal tax return. This amount was determined by an analysis of what the

amount that is greater than 50% likely to be paid upon final settlement.

Related Party Transactions

We have adopted a policy that transactions between us and our officers, directors, principal stockholders, or affiliates of any of them, will be on

terms no less favorable to us than can be obtained on an arm’s length basis in transactions with third parties and must be approved by our audit committee.

During 2012, we purchased equipment from an officer of our wholly-owned subsidiary Raven Drilling, LLC for total consideration of $195,000. The

purchase price was based on an appraisal and was at fair market value. The transaction was approved by the audit committee.

Environmental Regulations

Various federal, provincial, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the

protection of the environment, affect our operations and costs as a result of their effect on oil and gas exploration, development and production operations.

These laws and regulations could cause us to incur remediation or other corrective action costs in connection with a release of regulated substances, including

oil, into the environment. In addition, we have acquired certain oil and gas properties from third parties whose actions with respect to the management and

disposal or release of hydrocarbons or other wastes were not under our control, and under environmental laws and regulations, we could be required to remove

or remediate wastes disposed of or released by prior owners or operators. We also could incur costs related to the clean-up of sites to which we sent regulated

substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated

substances at such sites. In addition, we could be responsible under environmental laws and regulations for oil and gas properties in which we own an interest

but are not the operator. Moreover, we are subject to the EPA’s rule requiring annual reporting of greenhouse gas (GHG) emissions.

Compliance with such laws and regulations increases our overall cost of business, but has not had, to date, a material adverse effect on our

operations, financial condition, results of operations or competitive position. It is not anticipated, based on current laws and regulations, that we will be

required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to our total exploration and

development expenditure program in order to comply with such laws and regulations, but, inasmuch as such laws and regulations are frequently changed, we

are unable to predict the ultimate cost of compliance or the effect on our operations, financial condition, results of operations and competitive position.

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We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. In

addition to the EPA's rule requiring annual reporting of GHG emissions, we are also aware of legislation proposed by United States lawmakers to reduce GHG

emissions. We are unable to predict the timing, scope and effect of any such proposed laws, regulations and treaties, but the direct and indirect costs of such

laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations, financial condition and competitive

position.

We strive to reduce GHG emissions throughout our operations which is in the best interest of the environment and a generally good business practice.

We will continue to review the risks to our business and operations associated with all environmental matters, including climate change. In addition, we will

continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact on our operations and take

appropriate actions, where necessary.

Critical Accounting Policies

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires that management apply

accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial

statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of

estimates and assumptions to describe matters that are inherently uncertain.

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 but 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, management 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. We have experienced this

situation several times over the years, most recently in the current year 2012, relating to our proved oil and gas properties in Canada. 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 impairment

testing procedures associated with the full cost method of accounting as discussed below.

Under full cost accounting rules, the net capitalized cost of oil and gas properties, less related deferred taxes, may not exceed a “ceiling limit” which

is based upon the present value of estimated future net cash flows 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 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 stockholders’ 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. In addition, write-downs may occur if we experience substantial

downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though 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.

5 5
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Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and

SEC guidelines. The accuracy of a reserve estimate is a function of:

· the quality and quantity of available data;

· the interpretation of that data;

· the accuracy of various mandated economic assumptions; and

· the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the

engineering and operations departments of Abraxas. Reserve estimates were made by our independent petroleum engineers. Estimates prepared by other third

parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from

future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing

and production after the date of an estimate may justify material revisions to the estimate.

You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance

with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on costs on the date of the estimate and for the years

ended December 31, 2010, 2011 and 2012, oil and gas prices were based on the average 12-month first-day-of-the-month pricing as compared to end of period

prices utilized in prior years. Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate.

The estimates of proved reserves materially impact 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 is 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 we amortize these

costs as a component of our depletion expense.

Accounting for Derivatives. Realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains

and losses are based on the periodic mark to market valuation of derivative contracts in place. The derivative instruments we utilize are based on index prices

that may and often do differ from the actual oil and gas prices realized in our operations. We have elected not to apply hedge accounting to our derivative

contracts as prescribed by ASC 815; as a result, fluctuations in the market value of the derivative contract are recognized in earnings during the current

period. Our derivative contracts consist of commodity swaps and interest rate swaps. 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. As of

December 31, 2011 and 2012, the net market value of our commodity derivatives was a net asset of $3.4 million and a net liability of $6.4 million,

respectively. The market value of our interest rate derivative was a liability of $3.3 million at December 31, 2011. Our interest rate derivative expired in August

2012.

Share-Based Payments. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options

granted to employees and directors. Additional information about management’s assumptions can be found in Note 6 to the consolidated financial

statements. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. Restricted

stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the

Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date and expense is recognized over

the vesting period. For the years ended December 31, 2010, 2011 and 2012, stock-based compensation was approximately $1.6 million, $2.0 million, and

$2.1 million, respectively.

5 6
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Equity Method Investment. Our investment in an unconsolidated joint venture, in which we did not have a majority interest, was accounted for

under the equity method. Under the equity method of accounting, our share of net income (loss) from our equity investment was reflected as an increase

(decrease) in our investment account “Investment in joint venture” and was also recorded as “Equity in loss (income) of joint venture” in “Other (income)

expense.” The joint venture was dissolved effective August 31, 2012.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

As an independent oil and gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and

future rate of growth are substantially dependent upon the prevailing prices of 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 our 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. Generally, if the commodity

indices fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors

beyond our control. Assuming the production levels we attained during the year ended December 31, 2012, a 10% decline in oil and gas prices would have

reduced our operating revenue and cash flow by approximately $6.8 million for the year; however, due to the derivative contracts that we have in place, it is

unlikely that a 10% decline in commodity prices from their current levels would significantly impact our operating revenue, cash flow and net income.

Derivative Instrument Sensitivity

We account for our derivative contracts in accordance with ASC 815. The derivative instruments we utilize are based on index prices that may and

often do differ from the actual oil and gas prices realized in our operations. We have elected not to apply hedge accounting to our derivative contracts as

prescribed by ASC 815; as a result, fluctuations in the market value of the derivative contract are recognized in earnings during the current period.

The following table sets forth the summary position of our derivative contracts as of December 31, 2012:

Oil

Contract Periods

Daily Volume

(Bbl)

Swap Price

(per Bbl)

2013 1,341 $ 86.70

2014 1,100 $ 92.58

2015 933 $ 85.00

2016 883 $ 84.00

In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The twoyear interest rate swap for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. The interest rate swap was amended in February

2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and extending the

term through August 12, 2012. The interest rate swap expired in August 2012.

At December 31, 2012, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $6.4 million.

For the year ended December 31, 2012, we recognized a realized loss of $0.3 million and an unrealized gain of $2.7 million on our commodity

derivative contracts and we recognized a realized loss of $0.2 million on our interest rate swap.

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Interest Rate Risk

We are subject to interest rate risk associated with borrowings under our credit facility. As of December 31, 2012, we had $113.0 million of outstanding

indebtedness under our credit facility. Outstanding amounts under the 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) 1.25%—2.25%, depending on the utilization of the borrowing base, or, if we elect, LIBOR plus 2.25%—3.25%, depending on the utilization of the

borrowing base. At December 31, 2012, the interest rate on the credit facility was 3.21%. For every percentage point that the LIBOR rate rises, our interest

expense would increase by approximately $1.1 million on an annual basis, based on our outstanding indebtedness as of December 31, 2012. In order to

mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The two-year interest

rate swap for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. The interest rate swap was amended in February 2009 lowering

our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through

August 12, 2012. The interest rate swap expired in August 2012.

Item 8. Financial Statements and Supplementary Data

For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our

Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our

Chief Financial Officer believe that the disclosure controls and procedures as of December 31, 2012 were effective to ensure that information we are required to

disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the

SEC’s rules and forms and are effective to ensure that information required to be disclosed by us is accumulated and communicated to our management,

including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial

reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by the

Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the

preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and

procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets

of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with

generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of

management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or

disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over

financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that

controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 

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Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we

conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated

Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that

our internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by BDO USA, LLP, an independent

registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Controls

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that materially affected, or are

reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None

PART III

Item10. Directors, Executive Officers and Corporate Governance

There is incorporated in this Item 10 by reference to that portion of our definitive proxy statement for the 2013 Annual Meeting of Stockholders which

appears therein under the caption “Election of Directors – Board of Directors and Executive Officers,” “– Code of Ethics” and “– Committees of the Board of

Directors.”

Audit Committee and Audit Committee Financial Expert

The Audit Committee of our board of directors consists of C. Scott. Bartlett, Jr., W. Dean Karrash, Paul A. Powell, Jr. and Brian L. Melton. The

board of directors has determined that each of the members of the Audit Committee is independent as determined in accordance with the listing standards of

The NASDAQ Stock Market and Item 407(a) of Regulation S-K. In addition, the board of directors has determined that C. Scott Bartlett, Jr., as defined by

SEC rules, is an audit committee financial expert.

Section 16(a) Compliance

Section 16(a) of the Exchange Act requires our directors and executive officers and persons who own more than 10% of a registered class of Abraxas

equity securities to file with the SEC and The NASDAQ initial reports of ownership and reports of changes in ownership of Abraxas common

stock. Officers, directors and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all such forms they file. Based

solely on a review of the copies of such reports furnished to us and written representations that no other reports were required. We believe that all our directors

and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act during 2011.

Item 11. Executive Compensation

There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2013 Annual Meeting of Stockholders which

appears therein under the captions “Election of Directors – Committees of the Board of Directors” and “Executive Compensation.”

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

There is incorporated in this Item 12 by reference that portion of our definitive proxy statement for the 2013 Annual Meeting of Stockholders which

appears therein under the caption “Securities Holdings of Principal Stockholders, Directors, Nominees and Officers.”

5 9
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Item 13. Certain Relationships and Related Transactions, and Director Independence

There is incorporated in this Item 13 by reference that portion of our definitive proxy statement for the 2013 Annual Meeting of Stockholders which

appears therein under the captions “Certain Transactions” and “Election of Directors – Director Independence.”

Item 14. Principal Accountant Fees and Services

There is incorporated in this Item 14 by reference that portion of our definitive proxy statement for the 2013 Annual Meeting of Stockholders which

appears therein under the caption “Principal Auditor Fees and Services.”

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PART IV

Item 15. Exhibits Financial Statement Schedules

(a)1. Consolidated Financial Statements

Page

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements F-2

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting F-3

Consolidated Balance Sheets at December 31, 2011 and 2012 F-4

Consolidated Statements of Operations for the years ended December 31, 2010, 2011 and 2012 F-6

Consolidated Statements of Other Comprehensive Income (Loss) for the years ended

December 31, 2010, 2011 and 2012 F-7

Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended

December 31, 2010, 2011 and 2012 F-8

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2011 and 2012 F-9

Notes to Consolidated Financial Statements F-11

(a)2. Financial Statement Schedules

All schedules have been omitted because they are not required, not applicable, or the information required is included in the Consolidated Financial

Statements or related notes thereto.

(a)3. Exhibits

The following Exhibits have previously been filed by the Registrant or are included following the Index to Exhibits.

Exhibit

Number Description

3.1 Articles of Incorporation of Abraxas dated August 30, 1990. (Filed as Exhibit 3.1 to our Registration Statement on Form S-4, No. 33-36565. (the “S4 Registration Statement”)).

3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement).

3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement).

3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on Form S3, No. 333-00398).

3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000. (Filed as Exhibit 3.5 to our Annual Report on Form

10-K filed on April 2, 2001).

3.6 Certificate of Correction dated February 24, 2011 (Filed herewith).3.7Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to our Current

Report on Form 8-K filed on November 17, 2008).

3.8 Certificate of Designation of Series 2010 Junior Participating Preferred Stock. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on March

17, 2010).

4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement).

4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our Annual Report on Form 10-K filed on March 31, 1995).

4.3 Rights Agreement, dated March 17, 2010 by and between Abraxas and American Stock Transfer and Trust Company. (Filed as Exhibit 4.1 to our

Registration Statement on Form 8-A filed on March 17, 2010).

*10.1 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-18673 filed on

December 24, 1996).

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*10.2 Abraxas Petroleum Corporation Amended and Restated 1994 Long Term Incentive Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form

S-4, No. 333-120989 filed on January 12, 2005).

*10.3 Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filed

March 14, 2007).

*10.4 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the Registration Statement on Form S-1, No. 333-

95281 filed on January 24, 2000 (the “2000 S-1 Registration Statement”)).

*10.5 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the Registration Statement on Form S-3, No. 333-127480

filed on September 16, 2005 (the “S-3 Registration Statement”)).

*10.6 Employment Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27 to the S-3 Registration Statement).

*10.7 Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as Exhibit 10.28 to the S-3 Registration Statement).

*10.8 Employment Agreement between Abraxas and G. William Krog, Jr. (Filed as Exhibit 10.9 to our Annual report on Form 10-K filed March 15, 2012).

*10.9 Employment Agreement between Abraxas and Geoffrey R. King (Filed herewith)

*10.10 Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Appendix A to our Proxy Statement filed on

April 15, 2010).

*10.11 Form of Stock Option Agreement under the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as

Exhibit 10.2 to our Current Report on Form 8-K filed June 6, 2005).

*10.12 Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed as Exhibit 10.17 to our Annual Report on Form 10-K filed

March 23, 2006).

*10.13 Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan. (Filed as Annex E to our Proxy Statement filed on September 8,

2009).

*10.14 Form of Employee Stock Option Agreement under the Abraxas 2005 Employee Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our

Current Report on Form 8-K filed August 26, 2006).

10.15 Amended and Restated Credit Agreement dated as of June 30, 2011 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société

Générale, as Administrative Agent and as Issuing Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 6, 2011).

10.16 Amendment No. 2 to Second Amended and Restated Credit Agreement dated as of June 29, 2012 among Abraxas, the guarantors named therein, the

lenders named therein and Société Générale, as administrative agent (Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q filed on August 9,

2012).

10.17 Loan Agreement dated as of September 19, 2011 between Raven Drilling, LLC, as Borrower, and RBS Asset Finance, Inc., as Lender. (Filed as

Exhibit 10.1 to our Current Report on Form 8-K filed on September 23, 2011).

14.1 Abraxas Petroleum Corporation Code of Business Conduct and Ethics. (Filed as Exhibit 14.1 to our Annual Report on Form 10-K filed March 22,

2006).

21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to our Annual Report on Form 10-K filed on March 15, 2012).

23.1 Consent of BDO USA, LLP. (Filed herewith).

23.2 Consent of DeGolyer and MacNaughton. (Filed herewith).

31.1 Certification – Chief Executive Officer. (Filed herewith).

31.2 Certification – Chief Financial Officer. (Filed herewith).

32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of

2002. (Filed herewith).

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32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of

2002. (Filed herewith).

99.1 Report of DeGolyer and MacNaughton with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).

* Management Compensatory Plan or Agreement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on

its behalf by the undersigned, thereunto duly authorized.

ABRAXAS PETROLEUM CORPORATION

By: /s/Robert L.G. Watson By: /s/Geoffrey R. King By: /s/ G. William Krog, Jr.

President and Principal Executive

Officer

Vice President and Principal Financial

Officer

Principal Accounting Officer

DATED: March 18, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the

Registrant and in the capacities and on the date indicated.

Signature Name and Title Date

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President (Principal Executive Officer) and

Director

March 18, 2013

/s/ Geoffrey R. King

Geoffrey R. King

 Vice President, CFO (Principal Financial Officer) March 18, 2013

/s/ G. William Krog, Jr.

G. William Krog, Jr.

Chief Accounting Officer (Principal Accounting Officer) March 18, 2013

/s/ C. Scott. Bartlett, Jr.

C. Scott Bartlett, Jr.

Director March 18, 2013

/s/ Harold D. Carter

Harold D. Carter

Director March 18, 2013

/s/ Ralph F. Cox

Ralph F. Cox

Director March 18, 2013

/s/ W. Dean Karrash

W. Dean Karrash

Director March 18, 2013

/s/ Dennis E. Logue

Dennis E. Logue

Director March 18, 2013

/s/ Brian L. Melton

Brian L. Melton

Director March 18, 2013

/s/ Paul A. Powell, Jr.

Paul A. Powell, Jr.

Director March 18, 2013

/s/ Edward P. Russell

Edward P. Russell

Director March 18, 2013

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page

Abraxas Petroleum Corporation and Subsidiaries 

Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements F-2

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting F-3

Consolidated Balance Sheets at December 31, 2011 and

2012 F-4

Consolidated Statements of Operations for the years ended December 31, 2010, 2011 and 2012 F-6

Consolidated Statements of Other Comprehensive Income (Loss) for the years ended December 31, 2010,

2011 and 2012 F-7

Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2010,

2011 and 2012 F-8

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2011 and 2012 F-9

Notes to Consolidated Financial Statements F-11

All schedules are omitted because they are not required, are not applicable or the information required is included in the Consolidated Financial Statements

or the related notes thereto.

F-1
Table of Contents

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Abraxas Petroleum Corporation

San Antonio, Texas

We have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation as of December 31, 2011 and 2012 and the related

consolidated statements of operations and other comprehensive income (loss), stockholders’ equity (deficit), and cash flows for each of the three years in the

period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an

opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes

examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and

significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable

basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Abraxas Petroleum

Corporation at December 31, 2011 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31,

2012, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Abraxas Petroleum Corporation's

internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the

Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 18, 2013 expressed an unqualified opinion

thereon.

/s/ BDO USA, LLP

Dallas, Texas

March 18, 2013

F-2
Table of Contents

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Abraxas Petroleum Corporation

San Antonio, Texas

We have audited Abraxas Petroleum Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal

Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Abraxas

Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness

of internal control over financial reporting, included in the accompanying Item 9A, “Management’s Report on Internal Control Over Financial Reporting”. Our

responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that

we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material

respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and

testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other

procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and

the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over

financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect

the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit

preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being

made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or

timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of

effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance

with the policies or procedures may deteriorate.

In our opinion, Abraxas Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012,

based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets

of Abraxas Petroleum Corporation as of December 31, 2011 and 2012, and the related consolidated statements of operations and other comprehensive income

(loss), stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2012 and our report dated March 18, 2013

expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Dallas, Texas

March 18, 2013

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ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31,

2011 2012

(In thousands)

Current assets:

Cash and cash equivalents $ — $ 2,061

Accounts receivable:

Joint owners 3,354 8,883

Oil and gas production sales 8,897 10,887

Other 655 661

12,906 20,431

Derivative asset 11,416 41

Other current assets 391 488

Total current assets 24,713 23,021

Property and equipment:

Oil and gas properties, full cost method of accounting:

Proved 490,908 563,317

Unproved properties excluded from depletion 1,100 2,089

Other property and equipment 33,783 37,833

Total 525,791 603,239

Less accumulated depreciation, depletion, and amortization (346,239) (390,407)

Total property and equipment, net 179,552 212,832

Investment in joint venture 26,215 —

Deferred financing fees, net 3,490 3,397

Derivative asset 6,412 594

Other assets 768 763

Total assets $ 241,150 $ 240,607

See accompanying notes to consolidated financial statements

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ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (CONTINUED)

LIABILITIES AND STOCKHOLDERS’ EQUITY

December 31,

2011 2012

(In thousands, except number

of shares)

Current liabilities:

Accounts payable $ 21,373 $ 42,387

Joint interest oil and gas production payable 5,835 6,947

Accrued interest 209 75

Other accrued expenses 284 962

Derivative liability 11,640 3,462

Current maturities of long-term debt 181 657

Total current liabilities 39,522 54,490

Long-term debt – less current maturities 126,258 124,101

Other liabilities — 367

Derivative liability 4,307 3,568

Future site restoration 8,412 11,381

Total liabilities 178,499 193,907

Commitments and contingencies (Note 8)

Stockholders’ Equity:

Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding — —

Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 92,261,057 and

92,733,448 923 927

Additional paid-in capital 248,480 250,998

Accumulated deficit (186,465) (205,256)

Accumulated other comprehensive income (loss) (287) 31

Total stockholders’ equity 62,651 46,700

Total liabilities and stockholders’ equity $ 241,150 $ 240,607

See accompanying notes to consolidated financial statements

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ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

Years Ended December 31,

2010 2011 2012

(In thousands except per share data)

Revenues:

Oil and gas production revenues $ 58,050 $ 64,615 $ 68,499

Other 10 7 74

58,060 64,622 68,573

Operating costs and expenses:

Lease operating 19,475 21,581 24,806

Production taxes 5,910 5,766 6,613

Depreciation, depletion, and amortization 16,212 16,194 23,016

Impairment 4,787 — 19,774

General and administrative (including stock-based compensation of $1,560, $1,987 and

$2,091, respectively) 8,869 9,433 10,712

55,253 52,974 84,921

Operating income (loss) 2,807 11,648 (16,348)

Other (income) expense:

Interest income (8) (7) (4)

Interest expense 9,106 4,898 5,520

Amortization of deferred financing fees 2,479 1,762 937

Gain on derivative contracts (unrealized $(10,285), $(7,476) and $(2,669)) (10,811) (6,800) (2,210)

Equity in loss (income) of joint venture 473 (2,187) (2,207)

Other (119) 316 97

1,120 (2,018) 2,133

 Income (loss) before income tax 1,687 13,666 (18,481)

Income tax benefit (expense) 79 77 (310)

Net income (loss) $ 1,766 $ 13,743 $ (18,791)

Net income (loss) - per common share - basic $ 0.02 $ 0.15 $ (0.20)

Net income (loss) - per common share - diluted $ 0.02 $ 0.15 $ (0.20)

See accompanying notes to consolidated financial statements

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 ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS)

Years Ended December 31,

2010 2011 2012

(In thousands)

Consolidated net income (loss) $ 1,766 $ 13,743 $ (18,791 )

Other comprehensive income (loss):

Change in unrealized value of investments (27 ) (76) (25 )

Foreign currency translation adjustment 70 (456) 343

Other comprehensive income (loss) 43 (532) 318

Comprehensive income (loss) $ 1,809 $ 13,211 $ (18,473

See accompanying notes to consolidated financial statements

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ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

(In thousands except number of shares)

Common Stock

Shares Amount

Additional

Paid in

Capital

Accumulated

Deficit

Accumulated

Other

Comprehensive

Income(Loss) Total

Balance at December 31, 2009 76,231,751 $ 762 $ 182,647 $ (201,974) $ 202 (18,363)

Net income — — — 1,766 — 1,766

Change in unrealized gain (loss) on fair

value of investments — — — — (27) (27)

Foreign currency translation adjustment — — — — 70 70

Stock-based compensation — — 1,560 — — 1,560

Shares issued for compensation 11,480 — 24 — — 24

Stock options exercised 163,705 2 67 — — 6 9

Warrants exercised 15,534 — — — — —

Other — — (75) — — (75)

Restricted stock issued, net of

cancellations 5,091 — — — — —

Balance December 31, 2010 76,427,561 764 184,223 (200,208) 245 (14,976)

Net income — — — 13,743 — 13,743

Change in unrealized gain (loss) on fair

value of investments — — — — (76) (76)

Foreign currency translation adjustment — — — — (456) (456)

Stock-based compensation — — 1,987 — — 1,987

Shares issuance 15,075,502 151 62,195 — — 62,346

Stock options exercised 371,632 4 79 — — 83

Restricted stock issued, net of

cancellations 386,362 4 (4) — — —

Balance December 31, 2011 92,261,057 923 248,480 (186,465) (287) 62,651

Net income — — — (18,791) — (18,791)

Change in unrealized gain (loss) on fair

value of investments — — — — (25) (25)

Foreign currency translation adjustment — — — — 343 343

Stock-based compensation — — 2,091 — — 2,091

Stock options exercised 390,957 4 427 — — 431

Restricted stock issued, net of

cancellations 81,434 — — — — —

Balance December 31, 2012 92,733,448 $ 927 $ 250,998 $ (205,256) $ 31 $ 46,700

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ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31,

2010 2011 2012

(In thousands)

Operating Activities

Net income (loss) income $ 1,766 $ 13,743 $ (18,791)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Equity in loss (income) of joint venture 473 (2,187) (2,207)

Change in derivative fair value (10,451) (7,680) (4,088)

Monetization of derivative contracts — — 12,364

Depreciation, depletion, and amortization 16,212 16,194 23,016

Impairment 4,787 — 19,774

Accretion of future site restoration 516 452 474

Amortization of deferred financing fees 2,479 1,762 937

Stock-based compensation 1,560 1,987 2,091

Other non-cash transactions 24 — —

Changes in operating assets and liabilities:

Accounts receivable (3,976) (182) (7,506)

Other assets and liabilities (113) (17) 250

Accounts payable 14,210 756 22,024

Accrued expenses (3,385) (333) 3,037

Net cash provided by operating activities 24,102 24,495 51,375

Investing Activities

Capital expenditures, including purchases

and development of properties (36,448) (79,012) (68,552)

Proceeds from the sale of oil and gas properties 21,400 8,457 21,549

Net cash used in investing activities (15,048) (70,555) (47,003)

Financing Activities

Proceeds from exercise of stock options and warrants 6 9 83 431

Proceeds from issuance of common stock, net of offering costs — 62,346 —

Proceeds from long-term borrowings 3,000 50,500 30,500

Payments on long-term borrowings (13,641) (65,153) (32,181)

Deferred financing fees (169) (1,758) (844)

Other (75) (52) (217)

Net cash (used in) provided by financing activities (10,816) 45,966 (2,311)

Effect of exchange rate changes on cash — (5) —

(Decrease) increase in cash (1,762) (99) 2,061

Cash at beginning of year 1,861 9 9 —

Cash at end of year $ 9 9 $ — $ 2,061

See accompanying notes to consolidated financial statements

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ABRAXAS PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(CONTINUED)

Years Ended December 31,

2010 2011 2012

(In thousands)

Supplemental disclosures of cash flow information:

Interest paid $ 8,876 $ 4,514 $ 5,180

Non-Cash Investing Activities:

Asset retirement obligation cost and liabilities $ (83) $ (8) $ 2,588

Non-cash transfer of investment in joint venture — — 28,531

Asset retirement obligations associated with property acquisitions and dispositions $ (2,735) $ 306 $ 324

Properties contributed to joint venture $ 24,500 $ — $ —

See accompanying notes to consolidated financial statements

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ABRAXAS PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Significant Accounting Policies

Nature of Operations

We are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in the United

States and Canada. Our oil and gas assets are located in four operating regions in the United States, the Rocky Mountain, Mid-Continent, Permian Basin and

onshore Gulf Coast, and in the province of Alberta, Canada.

The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries,

including Raven Drilling LLC (“Raven Drilling”) and its wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC (“Canadian Abraxas”). The

term “Partnership” refers only to Abraxas Energy Partners, L.P.

Canadian Abraxas’ assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average

rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of stockholders’ equity.

Rig Accounting

In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection with

properties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation is

credited to the full cost pool and recognized through lower amortization as reserves are produced.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America

(“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent

assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual

results could differ from those estimates.

Concentration of Credit Risk

Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivative

contracts. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit

evaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions from

which we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the

current overall financial condition of the counterparties.

The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the

Company to be of high credit quality.

Cash and Equivalents

Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less.

Accounts Receivable

Accounts receivable are reported net of an allowance for doubtful accounts of approximately $84,000 and $105,000 at December 31, 2011 and 2012,

respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts

are charged off when collection efforts have failed and the account is deemed uncollectible.

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Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs

associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion,

and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-ofproduction method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of

unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices

discounted at 10 percent, 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, less related income taxes. Costs in excess of the present value of estimated future net revenues are charged to proved

property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties, except in unusual circumstances. We apply the

full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. As of December 31, 2010, our net capitalized costs of oil and gas

properties in the United States did not exceed the present value of our estimated proved reserves; however, the net capitalized costs of oil and gas properties in

Canada exceeded the present value of our estimated proved reserves by $4.8 million resulting in a write down for the year ended December 31, 2010. As of

December 31, 2011, our net capitalized costs of oil and gas properties in the United States and Canada did not exceed the present value of our estimated proved

reserves. As of December 31, 2012, net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved

reserves; however, the net capitalized costs of oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $19.8 million

resulting in a write down for the year ended December 31, 2012. Write downs of $1.3 million, $11.8 million and $6.7 million were taken in the second, third

and fourth quarters of 2012 respectively.

Other Property and Equipment

Other property and equipment are recorded on the basis of cost. Depreciation of other property and equipment is provided over the estimated useful

lives using the straight-line method. Major renewals and improvements are recorded as additions to the property and equipment accounts. Repairs that do not

improve or extend the useful lives of assets are expensed.

Estimates of Proved Oil and Gas Reserves

 Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve

estimate is a function of:

· the quality and quantity of available data;

· the interpretation of that data;

· the accuracy of various mandated economic assumptions; and

· the judgment of the persons preparing the estimate.

Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by the

Engineering and Operations departments of Abraxas. 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 cause material

revisions to the estimate.

In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gas

prices based on the average 12 month first-day-of-month pricing for the years ended December 31, 2011 and 2012, and costs as of December 31, 2011 and

2012. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves.

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The estimates of proved reserves materially impact depreciation, depletion and amortization, or 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 commodity prices, which

may make it uneconomic to drill for and produce higher cost fields.

Derivative Instruments and Hedging Activities

The Company enters into agreements to hedge the risk of future oil and gas price fluctuations. Such agreements are in the form of fixed price swaps,

which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. The Company does not enter into speculative hedges.

The Company accounts for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are

determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative

contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in

our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for hedge accounting rules as

prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, we do not account for our derivative instruments as cash flow hedges for

financial reporting purposes and instead record their fair value on the balance sheet with adjustments to the carrying value of the instruments being recognized

as a gain or loss in the current period.

Fair Value of Financial Instruments

The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is

materially different from the carrying value. The carrying value of those financial instruments that are classified as current approximates fair value because of

the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no

available quoted market prices, market prices for similar instruments.

Share-Based Payments

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

and directors. Options granted are valued at the date of grant and expense is recognized over the vesting period. Restricted stock awards are awards of common

stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the

restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period. For the

years ended December 31, 2010, 2011 and 2012, stock-based compensation was approximately $1.6 million, $2.0 million and $2.1 million, respectively. For

additional information regarding share-based payments, refer to Note 6, “Stock-based Compensation, Option Plans and Warrants.”

Restoration, Removal and Environmental Liabilities

The Company is subject to extensive Federal, provincial, state and local environmental laws and regulations. These laws regulate the discharge of

materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances

at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing

condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be

reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably

determinable.

The Company accounts for asset retirement obligations based on the guidance of ASC 410 which addresses accounting and reporting for

obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a

liability for an asset's retirement obligation be 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 estimated

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 we amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements.

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The following table summarizes the Company’s asset retirement obligations during the three years ended December 31: 

2010 2011 2012

(In thousands)

Beginning asset retirement obligation $ 10,326 $ 7,734 $ 8,412

New wells placed on production and other 64 318 330

Deletions related to property disposals and plugging costs (3,089) (84) (423)

Accretion expense 516 452 474

Revisions (83) (8) 2,588

Ending asset retirement obligation $ 7,734 $ 8,412 $ 11,381

Revenue Recognition and Major Purchasers

The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The

Company utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company’s net revenue

interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2011 and 2012.

During 2010 and 2011, two purchasers accounted for 21% and 28% of oil and gas revenues, respectively. During 2012, three purchasers accounted

for 39% of oil and gas revenues.

Deferred Financing Fees

Deferred financing fees are being amortized on the effective yield basis over the term of the related debt arrangements.

Income Taxes

The Company records deferred income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for future tax

consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and

operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect to taxable income in

the years in which those temporary differences are expected to be recovered or settled. Uncertainties exist as to the future utilization of the operating loss

carryforwards under the criteria set forth under ASC 740-10. Therefore, we have established a valuation allowance of $89.7 million for deferred tax assets at

December 31, 2012.

Accounting for Uncertainty in Income Taxes

ASC 740 provides guidance on accounting for uncertainty in income taxes. ASC 740 is intended to clarify the accounting for uncertainty in income taxes

recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return.

ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

Under ASC 740, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be

sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to

measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax

position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the

threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent

reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.

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Other Comprehensive Income (Loss)

ASC 220 requires disclosure of comprehensive income (loss), which includes reported net income (loss) as adjusted for other comprehensive income

(loss). Other Comprehensive income (loss) for the Company is the change in the unrealized value of investments and foreign currency translation adjustments.

2. Joint Venture

On August 18, 2010, Abraxas Petroleum and its wholly-owned subsidiary, Abraxas Operating, LLC, contributed 8,333 net acres in the Eagle Ford Shale

play to Blue Eagle Energy, LLC (“Blue Eagle”) and received a $25.0 million equity interest in Blue Eagle pursuant to the terms of the Subscription and

Contribution Agreement among Abraxas Petroleum, Abraxas Operating, Blue Eagle and Rock Oil Company, LLC (“Rock Oil”) formerly known as Blue Stone

Oil & Gas, LLC. Simultaneously, Rock Oil contributed $25.0 million in cash to Blue Eagle for a $25.0 million equity interest. Rock Oil committed to

contribute an additional $50.0 million to Blue Eagle and upon full funding, Abraxas Petroleum would have owned a 25% equity interest and Rock Oil would

have owned a 75% equity interest in Blue Eagle.

On September 4, 2012, Abraxas Petroleum Corporation entered into an Agreement to dissolve Blue Eagle with Rock Oil. The effective date of the

dissolution was August 31, 2012.

Under the terms of the Agreement, Abraxas retained a 100 percent interest to the base of the Buda formation in Jourdanton, Atascosa County (4,401 net

acres), a 100 percent interest in Yoakum, DeWitt County (1,868 net acres), a 25 percent interest in WyCross, McMullen County (695 net acres), and a 25

percent interest in Nordheim, DeWitt County (532 net acres). We also received $7.0 million in cash, adjusted for various working capital components, and

will receive 25% of the cash and working capital in Blue Eagle upon its final liquidation.

Through August 31, 2012 we accounted for the joint venture under the equity method of accounting in accordance with ASC 323. Under this method,

Abraxas’ share of net income (loss) from the joint venture is reflected as an increase (decrease) in its investment account in “Investment in joint venture” and

was also recorded as equity investment income (loss) in “Equity in (income) loss of joint venture.” For the years ended December 31, 2011 and 2012 we

reported income of $2.2 million and $2.2 million, respectively, related to Blue Eagle.

The following is condensed financial data from Blue Eagle’s August 31, 2012 (date of dissolution) and December 31, 2011 financial statements:

Balance Sheets:

As of

December 31,

2011

As of

August 31,

2012

Assets:

Current assets $ 11,910 $ 7,921

Oil and gas properties 66,663 75,741

Other assets 36 30

Total assets $ 78,609 $ 83,692

Liabilities and Members’ Capital:

Current liabilities $ 3,070 $ 1,474

Other liabilities 41 48

Members’ capital 75,498 82,170

Total liabilities and members’ capital $ 78,609 $ 83,692

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Statement of Operations:

Year Ended

 December 31,

2011

Year Ended

 December 31,

2012 (1)

(In thousands)

Revenue $ 12,579 $ 12,106

Operating expenses 7,138 7,144

Other income (11) (4)

Net income $ 5,452 $ 4,966

(1) Through August 31, 2012

3. Divestiture of Non-Core Properties

In the third quarter of 2012 we sold certain non-core assets for combined net proceeds of approximately $21.5 million. Properties sold included

certain properties received upon the dissolution of the Blue Eagle joint venture. The net proceeds were used to repay outstanding indebtedness under our credit

facility, for capital expenditures and general corporate purposes. Proceeds from these sales were credited to the full cost pool as the sale was not significant

under full cost accounting rules.

4. Long-Term Debt

The following is a description of the Company’s debt as of December 31, 2011 and 2012, respectively:

December 31,

2011

December 31,

2012

(In thousands)

Senior secured credit facility $ 115,000 $ 113,000

Rig loan agreement 6,500 7,000

Real estate lien note 4,939 4,758

126,439 124,758

Less current maturities (181) (657)

$ 126,258 $ 124,101

Maturities of long-term debt are as follows:

Year ending December 31, (In thousands)

2013 $ 657

2014 2,117

2015 119,364

2016 2,085

2017 535

Thereafter —

$ 124,758

Credit Facility

We have a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as

the credit facility. As of December 31, 2012, $113.0 million was outstanding under the credit facility.

The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At December 31, 2012, we had a

borrowing base of $150.0 million. This amount will remain in effect until the next redetermination of the borrowing base which is scheduled to be completed in

April 2013. The borrowing base 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 securing the facility utilizing these

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reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, are able to make one additional borrowing base

redetermination during any six-month period between scheduled redeterminations and we are able to request one redetermination during any six-month period

between scheduled redeterminations. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market

value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more.

Our borrowing base was increased to $150.0 million based upon our reserve report dated June 30, 2012, and did not include any of the properties held for

sale. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the 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) 1.25—2.25%, depending on the utilization of the borrowing base, or, if we

elect LIBOR plus 2.25%—3.25%, depending on the utilization of the borrowing base. At December 31, 2012, the interest rate on the credit facility was 3.21%

based on 1-month LIBOR borrowings and level of utilization.

Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2015. Interest is payable quarterly on

reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to

permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured

by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and

assets, other than Raven Drilling.

Under the 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 of not less than 2.50 to 1.00. We are also

required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 4.00 to 1.00 and liquidity (defined as the sum of our

borrowing base availability, liquid investments and unrestricted cash) of at least $7.5 million for each fiscal quarter ending on or after June 30, 2012 and on

or before March 31, 2013. The current ratio is defined as 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 excludes any cash deposited with a counter-party to a hedging

arrangement and any assets representing a valuation account arising from the application of ASC 815 and ASC 410-20 and current liabilities exclude the

current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest

coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the

purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes,

depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC

410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts 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 ASC 815 and ASC 410-20. Interest expense

includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the

ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is the

outstanding principal amount of debt, excluding debt associated with the office building, and obligations with respect to surety bonds and hedge arrangements.

As of December 31, 2012, the interest coverage ratio was 7.72 to 1.00, the total debt to EBITDAX ratio was 2.97 to 1.00, our current ratio was 1.19 to

1.00 and we had liquidity of $39.1 million, which included $37.0 million of availability under the credit facility. At December 31, 2012 we were in

compliance with all of our debt covenants.

The credit facility contains a number of covenants that, among other things, restrict our ability to:

· incur or guarantee additional indebtedness;

· transfer or sell assets;

· create liens on assets;

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· 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.

The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and

cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.

Rig Loan Agreement

On September 19, 2011, Raven Drilling entered into a rig loan agreement with RBS Asset Finance, Inc. to finance the costs of purchasing and

refurbishing an Oilwell 2000 HP diesel electric drilling rig (the “Collateral”). The rig loan agreement provided for interim borrowings payable to Raven Drilling

until the final amount of the loan was determined. 

On February 14, 2012, Raven Drilling finalized the note with respect to the rig loan agreement. The principal amount of the note is $7.0 million and

bears interest at 4.26%. Interest only is due for the first 18-months of the note and thereafter, the note will amortize in full over the remaining life of the

note. Interest and principal, when required, is payable monthly. Subject to earlier prepayment provisions and events of default, the stated maturity date of the

note is February 14, 2017. As of December 31, 2011 and 2012, $6.5 million and $7.0 million, respectively, was outstanding under the rig loan agreement.

The Company has guaranteed Raven Drilling’s obligations under the rig loan agreement and associated note. Obligations under the rig loan agreement are

secured by a first priority perfected security interest, subject to certain permitted encumbrances, in the Collateral.

Real Estate Lien Note

On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to

serve as its corporate headquarters. This note was refinanced in November 2008. The note bears interest at a fixed rate of 5.25% and is payable in monthly

installments of principal and interest of $36,652 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance

becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2011 and 2012, $4.9 million and $4.8

million, respectively, was outstanding on the note,

5. Property and Equipment

The major components of property and equipment, at cost, are as follows:

Estimated December 31,

Useful Life 2011 2012

Years (In thousands)

Oil and gas properties — $ 492,008 $ 565,406

Equipment and other 3-39 16,330 19,052

Drilling rig 15 17,453 18,781

$ 525,791 $ 603,239

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6. Stock-based Compensation, Option Plans and Warrants

Stock Options

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

and directors. The fair value for these options was estimated at the date of grant using the following weighted average assumptions for 2010, 2011 and 2012:

2010 2011 2012

Weighted average value per option granted during the period $ 1.61 $ 3.11 $ 2.17

Assumptions: (1)(2)

Expected dividend yield 0% 0% 0%

Volatility 84.0% 80.0% 81.4%

Risk free interest rate 2.87% 2.21% 1.19%

Expected life (years) 9.0 years 6.4 years 6.7 years

Fair value of options granted (in thousands) $ 1,553 $ 2,506 $ 1,324

(1) The estimated future forfeiture rate is based on the Company’s historical forfeiture rate.

(2) The Company does not pay dividends on its common stock.

The Company grants options to its officers, directors, and other employees under various stock option and incentive plans.

The Company’s 2005 Employee Long-Term Equity Incentive Plan has authorized the grant of up to 5.2 million awards to management and

employees, including options. Options have a term not to exceed 10 years. Options issued under this plan vest according to a vesting schedule as determined

by the compensation committee of the Company’s board of directors. Vesting may occur upon (1) the attainment of one or more performance goals or targets

established by the committee, (2) the optionee’s continued employment or service for a specified period of time, (3) the occurrence of any event or the

satisfaction of any other condition specified by the committee, or (4) a combination of any of the foregoing.

The following table is a summary of the Company’s stock option activity for the three years ended December 31, 2012:

Options

(000s)

Weighted average

exercise price

Weighted

 average

 remaining life

Intrinsic

value

per share

Options outstanding December 31, 2009 4,090 $ 2.18

Granted 964 2.12

Exercised (213) 0.89

Forfeited/Expired (21) 2.93

Options outstanding December 31, 2010 4,820 $ 2.23

Granted 807 4.37

Exercised (530) 1.54

Forfeited/Expired (341) 3.01

Options outstanding December 31, 2011 4,756 $ 2.61

Granted 610 $ 3.01

Exercised (391) 1.11

Forfeited/Expired (214) 2.80

Options outstanding December 31, 2012 4,761 $ 2.77 6.5 years $ 1.98

Exercisable at end of year 2,992 $ 2.75 5.7 years $ 1.95

Other information pertaining to the Company’s stock option activity for the three years ended December 31, 2012:

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 2010 2011 2012

Weighted average grant date fair value of stock options granted (per share) $ 1.61 $ 3.11 $ 2.17

Total fair value of options vested (000’s) $ 949 $ 1,230 $ 1,497

Total intrinsic value of options exercised (000’s) $ 373 $ 1,584 $ 414

As of December 31, 2012, the total compensation cost related to non-vested awards not yet recognized was approximately $2.5 million, which will be

recognized in 2013 through 2016. For the years ended December 31, 2010, 2011 and 2012, we recognized $1.2 million, $1.5 million and $1.6 million

respectively, in stock-based compensation expense relating to options.

The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of December 31,

2012:

Options outstanding Exercisable

Number

outstanding

Weighted

average

remaining

life

Weighted

average

exercise

price

Number

exercisable

Weighted

average

remaining

life

Weighted

average

exercise

price

$ 0.68 – 0.99 743,793 5.68 $ 0.96 548,293 5.50 $ 0.95

$ 1.00 – 1.99 1,130,629 7.27 $ 1.75 696,677 6.75 $ 1.68

$ 2.00 – 2.99 924,225 7.17 $ 2.26 563,159 7.13 $ 2.36

$ 3.00 – 3.99 719,763 7.61 $ 3.65 276,713 5.41 $ 3.60

$ 4.00 – 4.99 1,168,500 5.47 $ 4.58 833,625 4.38 $ 4.53

$ 5.00 – 6.05 74,000 3.15 $ 6.05 74,000 3.15 $ 6.05

4,760,910 2,992,467

Restricted Stock Awards

Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates

employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date.

Compensation expense is recorded over the applicable restricted stock vesting periods. As of December 31, 2012, the total compensation cost related to nonvested awards not yet recognized was approximately $1.1 million, which will be recognized in 2013 through 2016. For the years ended December 31, 2010,

2011 and 2012, we recognized $0.4 million, $0.5 million and $0.5 million, respectively, in stock-based compensation expense related to restricted stock

awards.

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The following table is a summary of the Company’s restricted stock activity for the three years ended December 31, 2012:

Number

of

Shares

Weighted

average

grant date

fair value

Unvested December 31, 2009 548,908 $ 2.05

Granted 20,000 2.45

Vested/Released (155,268) 2.22

Forfeited (13,345) 1.85

Unvested December 31, 2010 400,295 $ 2.02

Granted 408,676 3.67

Vested/Released (156,890) 2.24

Forfeited (22,310) 2.27

Unvested December 31, 2011 629,771 $ 3.03

Granted 89,860 2.12

Vested/Released (229,172) 2.57

Forfeited (8,434) 2.42

Unvested December 31, 2012 482,025 $ 3.09

Director Stock Awards

Shares Reserved and Awards. The 2005 Directors Plan (as amended) reserves 1.5 million shares of Abraxas common stock, subject to

adjustment following certain events. The 2005 Directors Plan provides that each year, at the first regular meeting of the board of directors immediately

following Abraxas’ annual stockholder’s meeting, each non-employee director shall be granted or issued awards of 12,000 shares of Abraxas common stock,

for participation in board and committee meetings during the previous calendar year. The maximum annual award for any one person is 100,000 shares of

Abraxas common stock or options for common stock. If options, as opposed to shares, are awarded, the exercise price shall be no less than 100% of the fair

market value on the date of the award while the option terms and vesting schedules are at the discretion of the committee. In addition to the 12,000 shares or

options and prior to April 2010, directors were compensated $20,000 per year, $12,000 of which was paid quarterly by issuance of common stock and the

remaining $8,000 was paid quarterly in cash. During 2010, there were 11,480 shares issued related to this compensation. The number of shares issued was

determined based on the stock price on the date of issuance. Between April 2010 and April 2011, directors were compensated for their annual retainer fee of

$26,000 in cash, which increased to $27,500 in April 2011 and to $40,000 in April 2012.

At December 31, 2012, the Company had approximately 9.2 million shares reserved for future issuance for conversion of its stock options,

warrants, and incentive plans for the Company’s directors, employees and consultants.

Warrants

On May 25, 2007, Abraxas entered into a Securities Purchase Agreement with certain accredited investors pursuant to which Abraxas issued

warrants to purchase 1,174,938 shares of common stock. The warrants expired on May 25, 2012. There were 877,941 warrants outstanding at expiration.

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7. Income Taxes

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting

purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax liabilities and assets are as follows:

Years Ended December 31,

2010 2011 2012

(In thousands)

Deferred tax liabilities:

Marketable securities $ 57 $ 36 $ 28

Canada full cost pool — 377 —

Investment in Blue Eagle 7,107 7,527 —

Hedge contracts — 345 —

Total deferred tax liabilities 7,164 8,285 28

Deferred tax assets:

U.S. full cost pool 37,464 29,976 13,837

Canada full cost pool 1,238 — 3,720

Depletion carryforward 4,667 4,842 4,930

U.S. net operating loss carryforward 49,621 52,564 59,362

Canada net operating loss carryforward 301 2,151 4,196

Alternative minimum tax credit 422 422 422

Hedge contracts 1,904 — 2,231

Other 3,447 1,811 1,042

Total deferred tax assets 99,064 91,766 89,740

Valuation allowance for deferred tax assets (91,900) (83,481) (89,712)

Net deferred tax assets 7,164 8,285 28

Net deferred tax $ — $ — $ —

Significant components of the provision (benefit) for income taxes are as follows:

Years ended December 31,

2010 2011 2012

(In thousands)

Current:

Federal $ — $ (77) $ 310

State (79) — —

Foreign — — —

$ (79) $ (77) $ 310

Deferred:

Federal $ — $ — $ —

Foreign — — —

$ — $ — $ —

At December 31, 2012, the Company had, subject to the limitation discussed below, $169.6 million of net operating loss carryforwards for U.S. tax

purposes, and $15.0 million of net operating loss carryforwards for Canadian tax purposes. The U.S. loss carryforward will expire in varying amounts

through 2032 and the Canadian loss carryforward will expire in 2032, if not utilized.

In addition to any Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set

forth under ASC 740-10. Therefore, the Company has established a valuation allowance of $91.9 million at December 31, 2010, $83.5 million at December

31, 2011 and $89.7 million at December 31, 2012.

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The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:

Years ended December 31,

2010 2011 2012

(In thousands)

Tax (expense) benefit at U.S. statutory rates (35%) $ (591) $ (4,809) $ 6,468

(Increase) decrease in deferred tax asset valuation allowance (412) 5,408 (6,231)

Basis difference in hedge liability 1,890 — —

Rate differential for non U.S. income (385) (46) (1,533)

State income taxes — —

Accrual of prior year federal taxes (2009) — — (310) 

Permanent differences (409) (533) (732)

Increase in asset for partnership distribution — — 1,945

Other (14) 57 83

$ 79 $ 77 $ (310) 

During 2012, the Company reduced deferred tax assets by $2.1 million related the full cost pool assets and the net operating loss carryforward. The

deferred tax assets were fully offset by a valuation allowance which was reduced at the same time. There were no deferred income tax expense or benefit due to

losses and/or loss carryforwards and valuation allowances which have been recorded against such benefits.

The Company accounts for uncertain tax positions under provisions ASC 740-10. The Company recognizes interest and penalties related to uncertain tax

positions in income tax expense. As of December 31, 2012, the Company did not have any accrued interest or penalties related to uncertain tax positions. The

tax years 2002 through 2012 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and Abraxas Energy

Partners, L.P., which was merged into a wholly owned subsidiary of Abraxas, have undergone audits of their 2009 Federal income tax returns. The audit of

the Federal income tax return of Abraxas Energy Partners, L.P. was completed with no changes. The audit of Abraxas Petroleum Corporation resulted in a

notice of a proposed adjustment of $619,000. The Company does not agree with the findings and intends to aggressively appeal the proposed adjustment;

however, no assurances can be made that such appeals will be successful. For the year ended December 31, 2012, the Company accrued $310,000 in income

tax expense related to the audit of its 2009 Federal tax return. This amount was determined by an analysis of what the amount that is greater than 50% likely to

be paid upon final settlement.

8. Commitments and Contingencies

Operating Leases

The Company leases office space in Calgary, Alberta. During 2010, 2011 and 2012, rent expense of $91,528 CN ($88,511 USD) ; $102,453

CN ($121,500 USD) and $112,261 CN ($112,276 USD), respectively, was incurred related to this lease. In July 2011, the Company leased office space in

Dickinson, North Dakota. During 2011 and 2012, rent expense of $9,250 and $23,800, respectively was incurred related to this lease. This lease expires on

August 31, 2013.

Litigation and Contingencies

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At

December 31, 2012, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect

on the Company.

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9. Earnings per Share

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

Years ended December 31:

2010 2011 2012

(In thousands, except per share data)

Numerator:

Net income (loss) $ 1,766 $ 13,743 $ (18,791)

Denominator:

Denominator for basic earnings per share – weighted-average common shares outstanding 75,923 90,151 91,914

Effect of dilutive securities:

Stock options, restricted shares and warrants 1,301 2,093 —

Dilutive potential common shares:

Denominator for diluted earnings per share – adjusted weighted-average shares and assumed

exercise of options, restricted shares and warrants 77,224 92,244 91,914

Net income (loss) per common share – basic $ 0.02 $ 0.15 $ (0.20)

Net income (loss) per common share – diluted $ 0.02 $ 0.15 $ (0.20)

Basic earnings per share, excluding any dilutive effects of stock options, warrants and unvested restricted stock, is computed by dividing net

income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share

is computed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the year ended

December 31, 2012, 1,348,924 potential shares relating to stock options and unvested restricted shares were excluded from the calculation of diluted income

(loss) per share since their inclusion would have been anti-dilutive due to the loss incurred in the period. None of the dilutive shares were excluded for the years

ended December 31, 2010 and 2011.

10. Quarterly Results of Operations (Unaudited)

Selected results of operations for each of the fiscal quarters during the years ended December 31, 2011 and 2012 are as follows:

1

st

Quarter

2

nd

Quarter

3

rd

Quarter

4

th

Quarter

(In thousands, except per share data)

Year Ended December 31, 2011

Net revenue $ 13,847 $ 16,656 $ 17,666 $ 16,453

Operating income $ 2,503 $ 3,438 $ 4,225 $ 1,482

Net (loss) income $ (10,019) $ 8,937 $ 20,085 $ (5,260)

Net (loss) income per common share – basic $ (0.12) $ 0.10 $ 0.22 $ (0.06)

Net (loss) income per common share – diluted $ (0.12) $ 0.10 $ 0.21 $ (0.06)

Year Ended December 31, 2012

Net revenue $ 16,396 $ 15,938 $ 17,170 $ 19,069

Operating income (loss) $ 2,224 $ (23) $ (11,359) $ (7,190)

Net income (loss) income $ 817 $ 10,903 $ (18,644) $ (11,867)

Net income (loss) per common share – basic $ 0.01 $ 0.12 $ (0.20) $ (0.13)

Net income (loss) per common share – diluted $ 0.01 $ 0.12 $ (0.20) $ (0.13)

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11. Benefit Plans

The Company has a defined contribution plan (401(k) plan) covering all eligible employees. In 2010, 2011 and 2012, in accordance with the safe

harbor provisions of the plan, the Company contributed $177,817, $226,377 and $267,289, respectively, to the plan. The Company adopted the safe

harbor provisions for its 401(k) plan which requires us to contribute a fixed match to each participating employee’s contribution to the plan. The fixed match

is set at the rate of dollar for dollar on the first 1% of eligible pay contributed, then 50 cents on the dollar for each additional percentage point of eligible pay

contributed, up to 5%. Employee’s eligible pay with respect to calculating the fixed match is limited by IRS regulations. In addition, the Board of Directors, at

its sole discretion, may authorize the Company to make additional contributions to each participating employee’s plan. The employee contribution limit for

2010 and 2011 was $16,500 for employees under the age of 50 and $22,000 for employees 50 years of age or older. For 2012 the employee contribution limit

was $17,000 for employees under the age of 50 and $22,500 for employees 50 years of age or older.

12. Business Segments

The Company has operations in only one industry segment, the oil and gas exploration and production industry; however, beginning in 2010, the

Company was organizationally structured along geographic operating segments or regions. The Company has reportable operations in the United States and

Canada.

In 2010, two customers accounted for approximately 20% of our consolidated oil and gas revenue, Two customers accounted for approximately 20%

of United States revenue and one customer accounted for 100% of revenue in Canada. In 2011, three customers accounted for approximately 28% of our

consolidated oil and gas revenue. Two customers accounted for approximately 26% of United States revenue and one customer accounted for 100% of revenue

in Canada. In 2012, four customers accounted for approximately 42% of our consolidated oil and gas revenue. Three customers accounted for approximately

39% of United States revenue and one customer accounted for 100% of revenue in Canada.

The following tables provide the Company’s geographic operating segment data as of and for the year ended December 31, 2010, 2011 and 2012

Year Ended December 31, 2010

U.S. Canada Corporate Total

(In thousands)

Revenues:

Oil and gas production $ 57,990 $ 60 $ — $ 58,050

Other — — 10 10

57,990 60 10 58,060

Costs and expenses:

Lease operating 19,459 16 — 19,475

Production taxes 5,910 — — 5,910

Depreciation, depletion and amortization 15,603 6 6 543 16,212

Impairment — 4,787 — 4,787

General and administrative 1,635 688 6,546 8,869

Net interest — — 9,098 9,098

Amortization of deferred financing fees — — 2,479 2,479

Equity in loss of joint venture — — 473 473

Other — — (10,930) (10,930)

Income (loss) before tax $ 15,383 $ (5,497) $ (8,199) $ 1,687

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Year Ended December 31, 2011

U.S. Canada Corporate Total

(In thousands)

Revenues:

Oil and gas production $ 63,105 $ 1,510 $ — $ 64,615

Other — — 7 7

63,105 1,510 7 64,622

Costs and expenses:

Lease operating 20,788 793 — 21,581

Production taxes 5,764 2 — 5,766

Depreciation, depletion and amortization 15,236 709 249 16,194

General and administrative 1,698 654 7,081 9,433

Net interest 448 4 4,439 4,891

Amortization of deferred financing fees — — 1,762 1,762

Equity in (income) of joint venture — — (2,187) (2,187)

Other — — (6,484) (6,484)

Income (loss) before tax $ 19,171 $ (652) $ (4,853) $ 13,666

Year Ended December 31, 2012

U.S. Canada Corporate Total

(In thousands)

Revenues:

Oil and gas production $ 65,590 2,909 — 68,499

Other — — 74 74

65,590 2,909 74 68,573

Costs and expenses:

Lease operating 22,578 2,228 — 24,806

Production taxes 6,588 25 — 6,613

Depreciation, depletion and amortization 20,704 2,063 249 23,016

Impairment — 19,774 — 19,774

General and administrative 1,980 699 8,033 10,712

Net interest 457 17 5,042 5,516

Amortization of deferred financing fees — — 937 937

Equity in (income) of joint venture — — (2,207) (2,207)

Other — — (2,113) (2,113)

Income (loss) before tax $ 13,283 (21,897) (9,867) (18,481)

The following table provides the Company’s geographic asset data as of December 31, 2011 and December 31, 2012:

Segment Assets:

December 31,

2011

December 31,

2012

(In thousands)

United States $ 167,739 $ 223,253

Canada 19,379 7,053

Corporate 54,032 10,301

$ 241,150 $ 240,607

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13. Hedging Program and Derivatives

The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. Our

derivative contracts do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are

recognized in earnings during the current period.

The following table sets forth the summary position of our derivative contracts as of December 31, 2012:

Oil

Contract Periods

Daily Volume

(Bbl)

Swap Price

(per Bbl)

2013 1,341 $ 86.70

2014 1,100 $ 92.58

2015 933 $ 85.00

2016 883 $ 84.00

 In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR-based

debt. The two-year interest rate swap for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. This interest rate swap was amended

in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009, lowering our fixed rate to 2.55% and

extending the term through August 12, 2012. The interest rate swap expired in August 2012.

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:

Fair Value of Derivative Instruments as of December 31, 2011

Asset Derivatives Liability Derivatives

Derivatives not designated as hedging

instruments Balance Sheet Location Fair Value Balance Sheet Location Fair Value

Commodity price derivatives Derivatives – current $ 11,416 Derivatives – current $ 10,094

Interest rate derivatives Derivatives – current — Derivatives – current 1,546

Commodity price derivatives Derivatives – long-term 6,412 Derivatives – long-term 4,307

$ 17,828 $ 15,947

Fair Value of Derivative Instruments as of December 31, 2012

Asset Derivatives Liability Derivatives

Derivatives not designated as hedging

instruments Balance Sheet Location Fair Value Balance Sheet Location Fair Value

Commodity price derivatives Derivatives – current $ 41 Derivatives – current $ 3,462

Commodity price derivatives Derivatives – long-term 594 Derivatives – long-term 3,568

$ 635 $ 7,030

Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statement of

Operations.

14. Financial Instruments

Effective January 1, 2008, the Company adopted ASC 820-10 which defines fair value, establishes a framework for measuring fair value,

establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.

The implementation of ASC 820-10 did not cause a change in the method of calculating fair value of our assets or liabilities, with the exception of

incorporating a measure of the Company’s own non-performance risk or that of its counter-parties, as appropriate, which was not material. The primary

impact from adoption was additional disclosures.

Fair Value Hierarchy—ASC 820-10 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy

categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the

measurement. The three levels are defined as follows:

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Table of Contents

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

· Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are

observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

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

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value

measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and

considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract.

The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the

derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of

December 31, 2011 and 2012, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in

thousands):

Quoted Prices

 in Active

Markets for

Identical

Assets

(Level 1)

Significant

Other

Observable

Inputs

 (Level 2)

Significant

Unobservable

Inputs (Level 3)

Balance as of

December 31,

2011

Assets:

Investment in common stock $ 104 $ — $ — $ 104

NYMEX Fixed Price Derivative contracts — 17,828 — 17,828

Total Assets $ 104 $ 17,828 $ — $ 17,932

Liabilities:

NYMEX Fixed Price Derivative contracts $ — $ 14,401 $ — $ 14,401

Interest Rate Swaps — — 1,546 1,546

Total Liabilities $ — $ 14,401 $ 1,546 $ 15,947

Quoted Prices

 in Active

Markets for

Identical

Assets

(Level 1)

Significant

Other

Observable

Inputs

 (Level 2)

Significant

Unobservable

Inputs (Level 3)

Balance as of

December 31,

2012

Assets:

Investment in common stock $ 78 $ — $ — $ 78

NYMEX Fixed Price Derivative contracts — 635 — 635

Total Assets $ 78 $ 635 $ — $ 713

Liabilities:

NYMEX Fixed Price Derivative contracts $ — $ 7,030 $ — $ 7,030

Total Liabilities $ — $ 7,030 $ — $ 7,030

The Company has an investment in Insigna Energy Ltd, the surviving entity in the merger with a former subsidiary, consisting of shares of

common stock. The stock is actively traded on the Toronto Stock Exchange. This investment is valued at its quoted price as of December 31, 2012 in US

dollars. Accordingly, this investment is characterized as Level 1.

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Table of Contents

The Company’s derivative contracts consist of NYMEX-based fixed price commodity swaps and interest rate swaps. The NYMEX-based fixed

price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the

energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of

these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future

NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated

through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation, we enter the various inputs

into a model and compare our results to the third party for reasonableness.

In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt.

The two-year interest rate swap for $100 million at a fixed rate of 3.367% originally expired on August 12, 2010. The interest rate swap was amended in

February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and

extending the term through August 12, 2012. This interest rate swap expired in August 2012 and was not renewed.

Additional information for the Company’s recurring fair value measurements using significant unobservable inputs (Level 3) for the three years

ended December 31, 2012 is as follows (in thousands):

Derivative

Assets

(Liabilities) -

net

Balance December 31, 2010 $ (3,348)

Total realized and unrealized losses included in change in net liability (565)

Settlements during the period 2,367

Balance December 31, 2011 (1,546)

Total realized and unrealized losses included in change in net liability (214)

Settlements during the period 1,760

Balance December 31, 2012 —

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair

value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as the

interest rates are market rates and this debt is considered Level 2.

F-29
Table of Contents

15. Supplemental Oil and Gas Disclosures (Unaudited)

The accompanying table presents information concerning the Company’s oil and gas producing activities as required by ASC 932-235,

“Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows:

Years Ended December 31

2011 2012

Total U.S. Canada Total U.S. Canada

(In thousands)

Proved oil and gas properties $ 490,908 $ 468,218 $ 22,690 $ 563,317 $ 531,971 $ 31,346

Unproved properties 1,100 — 1,100 2,089 — 2,089

Total 492,008 468,218 23,790 565,406 531,971 33,435

Accumulated depreciation, depletion,

amortization and impairment (341,264) (335,871) (5,393) (383,469) (356,255) (27,214)

Net capitalized costs $ 150,744 $ 132,347 $ 18,397 $ 181,937 $ 175,716 $ 6,221

Cost incurred in oil and gas property acquisition and development activities are as follows:

Years Ended December 31

2010 2011 2012

Total U.S. Canada Total U.S. Canada Total U.S. Canada

(In thousands)

Development

costs $ 31,278 $ 23,757 $ 7,521 $ 46,735 $ 32,471 $ 14,264 $ 56,318 $ 48,283 $ 8,035

Exploration

costs 3,809 3,809 — 8,410 8,410 — — — —

Property

acquisition

costs — — — — — — 7,200 7,200 —

Unproved 1,085 — 1,085 1,100 — 1,100 989 — 989

$ 36,172 $ 27,566 $ 8,606 $ 56,245 $ 40,881 $ 15,364 $ 64,507 $ 55,483 $ 9,024

F-30
Table of Contents

The results of operations for oil and gas producing activities for the three years ended December 31, 2010, 2011 and 2012 are as follows:

Years Ended December 31,

2010 2011 2012

Total U.S. Canada Total U.S. Canada Total U.S. Canada

(In thousands)

Revenues $ 58,050 $ 57,990 $ 60 $ 64,615 $ 63,105 $ 1,510 $ 68,499 $ 65,590 $ 2,909

Production costs (25,790) (25,774) (16) (27,347) (26,552) (795) (31,419) (29,166) (2,253)

Depreciation,

depletion, and

amortization (15,653) (15,603) (50) (15,595) (14,914) (681) (22,767) (20,704) (2,063)

Proved property

impairment (4,787) — (4,787) — — — (19,774) — (19,774)

General and

administrative (2,323) (1,635) (688) (2,352) (1,698) (654) (2,679) (1,980) (699)

Results of

operations

from oil and

gas producing

activities

(excluding

corporate

overhead and

interest costs) $ 9,497 $ 14,978 $ (5,481) $ 19,321 $ 19,941 $ (620) $ (8,140) $ 13,740 $ (21,880)

Depletion rate per

barrel of oil

equivalent $ 11.00 $ 10.98 $ 59.97 $ 12.26 $ 11.96 $ 27.58 $ 15.59 $ 14.74 $ 37.48

F-31
Table of Contents

Estimated Quantities of Proved Oil and Gas Reserves

The following table presents the Company’s estimate of its net proved oil and gas reserves as of December 31, 2010, 2011, and 2012. The

Company’s management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of

producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been

predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and

engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating

conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All

of the Company’s proved reserves are located in the continental United States and Canada.

Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared

under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the average

prior 12-month-first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods

presented.

Total United States Canada

Oil/NGL Gas Oil

Equivalents Oil/NGL Gas OilEquivalents Oil/NGL Gas OilEquivalents

(MBbl) (MMcf) (MBoe) (MBbl) (MMcf) (MBoe) (MBbl) (MMcf) (MBoe)

(In thousands)

Proved developed and

undeveloped reserves:

Balance at December 31,

2009 8,832 96,525 24,919 8,832 96,525 24,919— — —

Revisions of previous

estimates 1,067 729 1,189 1,067 729 1,189 — — —

Extensions and

discoveries 1,329 1,456 1,572 1,252 1,066 1,430 77 390 142

Sales of minerals in place (925) (8,318) (2,311) (925) (8,318) (2,311) — — —

Production (509) (5,479) (1,422) (508) (5,479) (1,421) (1) — (1)

Balance at December 31,

2010 9,794 84,913 23,947 9,718 84,523 23,80676 390

141

Revisions of previous

estimates 2,290 (13,009) 122 2,290 (13,009)

122 — — —

Extensions and

discoveries 2,703 4,393 3,435 2,326 1,837 2,632 377 2,556 803

Production (568) (4,222) (1,272) (554) (4,160) (1,247) (14) (62) (25)

Balance at December 31,

2011 14,219 72,075 26,232 13,780 69,191 25,313 439 2,884 919

Revisions of previous

estimates 1,574 (7,470)

328 1,774 (5,786)

809 (200)

(1,684)(481)

Extensions and

discoveries 5,809 6,983 6,973 5,809 6,983 6,973 — — —

Purchases of minerals in

place 1 6 9 13 1 6 9 13 — — —

Sales of minerals in place (850) (6,376) (1,913) (850) (6,376) (1,913) — — —

Production (797) (4,097) (1,481) (763) (3,982) (1,427) (34) (115) (54)

Balance at December 31,

2012

19,956 61,184 30,152 19,751 60,099 29,768 205 1,085 384

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Table of Contents

Total United States Canada

Oil/NGL Gas

Oil

Equivalents Oil/NGL Gas

Oil

Equivalents Oil/NGL Gas

Oil

Equivalents

(MBbl) (MMcf) (MBoe) (MBbl) (MMcf) (MBoe) (MBbl) (MMcf) (MBoe)

(In thousands)

Proved Developed

Reserves:

December 31, 2010 5,862 42,750 12,987 5,786 42,360 12,846 76 390 141

December 31, 2011 7,761 42,582 14,858 7,433 40,451 14,175 328 2,131 683

December 31, 2012 8,650 41,220 15,520 8,531 40,723 15,318 119 497 202

Proved Undeveloped

Reserves:

December 31, 2010 3,932 42,163 10,959 3,932 42,163 10,959 — — —

December 31, 2011 6,460 29,493 11,376 6,348 28,740 11,138 112 753 238

December 31, 2012 11,306 19,964 14,634 11,220 19,376 14,450 86 588 184

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The Company’s proved oil and gas reserves have been estimated by the Company with the assistance of an independent petroleum engineering firm

(DeGolyer & MacNaughton) as of December 31, 2010, 2011 and 2012. The following information has been prepared in accordance with SEC rules and

accounting standards based on the 12-month first-day-of-the-month average prices in accordance with provisions of the Financial Accounting Standards

Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” Future cash inflows were reduced by estimated future

production and development costs based on year-end costs to determine pre-tax cash inflows. Future net cash flows have not been adjusted for commodity

derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash

inflows over the tax basis and net operating losses associated with the properties. Since prices used in the calculation are average prices for 2012, the

standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year.

The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications,

independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information

promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and

petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. All reports by DeGolyer and MacNaughton

were developed utilizing studies performed DeGolyer and MacNaughton assisted by the Engineering and Operations departments of Abraxas. Reserves are

estimated by independent petroleum engineers. The report of DeGolyer and MacNaughton dated February 26, 2013, which contains further discussions of the

reserve estimates and evaluations prepared by DeGolyer and MacNaughton as well as the qualifications of DeGolyer and MacNaughton’s technical personnel

responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report.

Estimates of proved reserves at December 31, 2010, 2011 and 2012 were based on studies performed by our independent petroleum engineers assisted

by the Engineering and Operations departments of Abraxas. The Engineering department is directly responsible for Abraxas’ reserve evaluation process. The

Vice President of Engineering is the manager of this department and is the primary technical person responsible for this process. The Vice President of

Engineering holds a Bachelor of Science degree in Petroleum Engineering and has 34 years of experience in reserve evaluations. The Vice President of

Engineering is a Registered Professional Engineer in the State of Texas. The operations department of Abraxas assisted in the process, and consists of three

petroleum engineers with Bachelor degrees in Petroleum Engineering, and various other technical professionals.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent the

fair market value of the Company’s proved oil and gas reserves. An estimate of fair market value would also take into account, among other factors, the

recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of

money and the risks inherent in reserve estimates.

F-34
Table of Contents

Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below

sets forth the Standardized Measure of our proved oil and gas reserves for the three years ended December 31, 2010, 2011 and 2012 :

Years Ended December 31,

2010 2011 2012

Total U.S. Canada Total U.S. Canada Total U.S. Canada

(In thousands)

Future cash

inflows $1,020,286 $1,012,829 $ 7,457 $1,471,352 $ 1,420,013 $ 51,339 $1,784,920 $1,766,515 $ 18,405

Future production

costs (391,396) (389,395) (2,001) (544,970) (532,056) (12,914) (642,706) (634,903) (7,803)

Future

development

costs (164,135) (163,085) (1,050) (228,804) (224,254) (4,550) (328,554) (324,704) (3,850)

Future income tax

expense — — — (106,839) (104,279) (2,560) (149,625) (149,625) —

Future net cash

flows 464,755 460,349 4,406 590,739 559,424 31,315 664,035 657,283 6,752

Discount (267,762) (266,041) (1,721) (321,657) (310,516) (11,141) (385,890) (383,271) (2,619)

Standardized

Measure of

discounted

future net

cash relating

to proved

reserves $ 196,993 $ 194,308 $ 2,685 $ 269,082 $ 248,908 $ 20,174 $ 278,145 $ 274,012 $ 4,133

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure:

Year Ended December 31,

2010 2011 2012

(In thousands)

Standardized Measure, beginning of year $ 150,529 $ 196,993 $ 269,082

Sales and transfers of oil and gas produced, net of production costs (32,261) (37,171) (37,080)

Net change in prices and development and production costs from prior year 70,311 92,886 60,710

Extensions, discoveries, and improved recovery, less related costs 14,508 47,765 73,236

Sales of minerals in place (18,868) — (20,089)

Purchased of minerals in place — — 131

Revisions of previous quantity estimates 9,694 1,329 3,355

Change in timing and other (11,973) (23,501) (88,309)

Change in future income tax expense — (28,918) (9,799)

Accretion of discount 15,053 19,699 26,908

Standardized Measure, end of year $ 196,993 $ 269,082 $ 278,145

The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates:

Year Ended December 31,

2010 2011 2012

Oil (per Bbl) (1) $ 79.43 $ 96.19 $ 95.14

Gas (per MMbtu) (2) 4.45 4.16 2.86

Oil (per Bbl) (3) 70.72 88.58 88.26

Gas (per MMBtu) (4) 3.91 3.73 2.61

NGL’s (per Bbl) (5) 55.60 50.21 36.76

_____________________

(1) The quoted oil price for the year ended December 31, 2010, 2011 and 2012 is the 12-month average first-day-of-the-month West Texas Intermediate

spot price for each month of 2010, 2011 and 2012.

(2) The quoted gas price for the year ended December 31, 2010, 2011 and 2012 is the 12-month average first-day-of-the-month Henry Hub spot price for

each month of 2010, 2011 and 2012.

(3) The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

(4) The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.

(5) The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.

F-36
Table of Contents

Exhibit Index

10.9 Employment Agreement between Abraxas and Geoffrey R. King (Filed herewith)

23.1 Consent of BDO USA, LLP. (Filed herewith).

23.2 Consent of DeGolyer & MacNaughton. (Filed herewith).

31.1 Certification – Chief Executive Officer. (Filed herewith).

31.2 Certification – Chief Financial Officer. (Filed herewith).

32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of

2002. (Filed herewith).

32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of

2002. (Filed herewith).

99.1 Report of DeGolyer and MacNaughton with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).
Table of Contents
ABRAXAS PETROLEUM CORPORATION

18803 Meisner Dr.

San Antonio, Texas 78258

September 4, 2012

Geoffrey R. King

San Antonio, TX 78258

Dear Geoff:

The Board of Directors (the "Board") of Abraxas Petroleum Corporation (the "Company") has determined that appropriate steps should be taken to reinforce

and encourage the continued attention and dedication of members of the Company's management, including yourself, to their assigned duties. In order to

induce you to remain in the employ of the Company, in consideration of your agreement to continue employment with the Company, and in consideration of

your agreement to the termination of any existing employment or severance agreement you may have with the Company, the Company agrees that you shall

receive, upon the terms and conditions set forth herein, the benefits set forth in this letter agreement ("Agreement") during the term hereof.

1. Terms of Agreement. This Agreement shall commence on the date hereof and shall continue in effect through December 31, 2012 (the "Term");

provided, however, that commencing on January 1, 2013 and each January 1 thereafter, the Term shall automatically be extended for an additional year

unless, not later than December 1 of the preceding year, either party shall have given notice that it does not wish to extend the Term. Except in the event of a

Change in Control (as defined in Section 4 hereof), at all times during the Term or extended Term your employment shall remain at will and may be terminated

by the Company for any reason without notice or Cause (as hereinafter defined). If a Change in Control shall have occurred during the original or extended

Term, the Term shall continue in effect for a period of 36 months beyond the Term in effect immediately before such Change in Control.

2. Term of Employment. During the Term, you agree to be a full-time employee of the Company serving in the position of Vice President-Chief

Financial Officer, to devote substantially all of your working time and attention to the business and affairs of the Company and, to the extent necessary to

discharge the responsibilities associated with your position, to use your best efforts to perform faithfully and efficiently such responsibilities. In addition, you

agree to serve in such other capacities or offices to which you may be assigned, appointed or elected from time to time by the Board. Nothing herein shall

prohibit you from devoting your time to civic and community activities or managing personal investments, as long as the foregoing do not interfere with the

performance of your duties hereunder.

3. Compensation. (a) As compensation for your services under this Agreement, you shall be entitled to receive base salary and other compensation to be

determined from time to time by the Board in its sole discretion. In addition, you shall be entitled to participate in any additional bonus, incentive

compensation or employee benefit arrangement which may be established from time to time by the Company in its sole discretion. Notwithstanding anything

to the contrary provided in this Agreement, prior to a Change in Control you shall not be entitled to receive any compensation from the Company upon

termination, voluntary or involuntary, of your employment with the Company, regardless of the reason for such termination.
(b) The Company shall reimburse you, in accordance with Company policy in effect from time to time, for all reasonable travel, entertainment and

other business expenses incurred by you in the performance of your responsibilities under this Agreement promptly upon receipt of written substantiation of

such expenses.

4. Change in Control. For purposes of this Agreement, a Change in Control shall be deemed to have occurred if (a) any "person" or "group" (as such

terms are used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended, (the "Exchange Act")) is or becomes the "beneficial owner" (as

defined in Rule 13d-3 under the Exchange Act as in effect on the date hereof, except that a person shall be deemed to be the "beneficial owner" of all shares that

any such person has the right to acquire pursuant to any agreement or arrangement or upon exercise of conversion rights, warrants, options or otherwise,

without regard to the sixty day period referred to in such Rule), directly or indirectly, of securities representing 20% or more of the combined voting power of

the Company's then outstanding securities, (b) any person or group shall make a tender offer or an exchange offer for 20% or more of the combined voting

power of the Company's then outstanding securities, (c) at any time during any period of two consecutive years (not including any period prior to the execution

of this Agreement), individuals who at the beginning of such period constituted the Board and any new directors, whose election by the Board or nomination

for election by the Company's stockholders was approved by a vote of at least two-thirds (2/3) of the Company directors then still in office who either were the

Company directors at the beginning of the period or whose election or nomination for election was previously so approved ("Current Directors"), cease for any

reason to constitute a majority thereof, (d) the Company shall consolidate, merge or exchange securities with any other entity and the stockholders of the

Company immediately before the effective time of such transaction do not beneficially own, immediately after the effective time of such transaction, shares

entitling such stockholders to a majority of all votes (without consideration of the rights of any class of stock entitled to elect directors by a separate class vote)

to which all stockholders of the corporation issuing cash or securities in the consolidation, merger or share exchange would be entitled for the purpose of

electing directors or where the Current Directors immediately after the effective time of the consolidation, merger or share exchange would not constitute a

majority of the Board of Directors of the corporation issuing cash or securities in the consolidation, merger or share exchange, or (e) any person or group

acquires 50% or more of the Company's assets.

Notwithstanding the foregoing, however, a Change in Control shall not be deemed to occur merely by reason of an acquisition of Company securities by, or

any consolidation, merger or exchange of securities with, any entity that, immediately prior to such acquisition, consolidation, merger or exchange of

securities, was a "subsidiary", as such term is defined below. For these purposes, the term "subsidiary" means (a) any corporation of which 95% of the

capital stock of such corporation is owned, directly or indirectly, by the Company and (b) any unincorporated entity in respect of which the Company has,

directly or indirectly, an equivalent degree of ownership.
5. Termination of Employment Following Change in Control. Prior to a Change in Control, your employment shall remain at will and may be

terminated by the Company for any reason without notice or Cause. From and after a Change in Control, you shall be entitled to the benefits provided in

Subsection 6(d) hereof upon the subsequent termination of your employment during the Term or extended Term unless such termination is because of your

death or Retirement, by the Company for Cause or Disability, or by you other than for Good Reason.

(a) Disability; Retirement. If, as a result of your incapacity due to physical or mental illness, you shall have been absent from the full-time performance

of your duties with the Company for six (6) consecutive months, and within thirty (30) days after written Notice of Termination is given you shall not have

returned to the full-time performance of your duties, the Company may terminate your employment for "Disability." Any question as to the existence of your

Disability upon which you and the Company cannot agree shall be determined by a qualified independent physician selected by you (or, if you are unable to

make such selection, it shall be made by any adult member of your immediate family), and approved by the Company. The determination of such physician

made in writing to the Company and to you shall be final and conclusive for all purposes of this Agreement. Termination by the Company or you of your

employment based on "Retirement" shall mean termination in accordance with the Company's retirement policy, generally applicable to its salaried employees

or in accordance with any retirement arrangement established with your consent with respect to you.

(b) Cause. Termination by the Company of your employment for "Cause" shall mean termination upon (i) the willful and continued failure by you to

substantially perform your duties with the Company (other than any such failure resulting from your incapacity due to physical or mental illness or any such

actual or anticipated failure resulting from termination by you for Good Reason) after a written demand for substantial performance is delivered to you by the

Board, which demand specifically identifies the manner in which the Board believes that you have not substantially performed your duties, or (ii) the willful

engaging by you in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise. For purposes of this Subsection, no

act, or failure to act, on your part shall be deemed "willful" unless done, or omitted to be done, by you not in good faith and without reasonable belief that

your action or omission was in the best interest of the Company. Notwithstanding the foregoing, you shall not be deemed to have been terminated for Cause

unless and until there shall have been delivered to you a copy of a resolution duly adopted by the affirmative vote (which cannot be delegated) of not less than a

majority of the members of the Board who are not officers of the Company at a meeting of the Board called and held for such purposes (after reasonable notice

to you and an opportunity for you, together with your counsel, to be heard before the Board), finding that in the good faith opinion of the Board you were

guilty of conduct set forth above in clauses (i) or (ii) of the first sentence of this Subsection and specifying the particulars thereof in detail.
(c) Good Reason. You shall be entitled to terminate your employment for Good Reason. For purposes of this Agreement, "Good Reason" shall mean,

without your express written consent, any of the following:

(i) a material adverse alteration in the nature or status of your position, duties or responsibilities from those in effect immediately prior to a Change in

Control, other than any such alteration primarily attributable to the fact that the Company may no longer be a public company or may be a subsidiary of

another entity;

(ii) a reduction in your annual base salary as in effect immediately prior to the Change in Control or as the same may be increased from time to time;

(iii) a change in the principal place of your employment, as in effect at the time of a Change in Control, to a location more than fifty (50) miles from

such principal place of employment, excluding required travel on the Company's business to an extent substantially consistent with your present business

travel obligations;

(iv) the failure by the Company, without your consent, to pay to you any portion of your current compensation, or to pay to you any portion of any

deferred compensation, within ten (10) days of the date any such compensation payment is due;

(v) the failure by the Company to continue in effect any compensation plan in which you participate, or any substitute plans adopted prior to the

Change in Control, unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan in

connection with the Change in Control, or the failure by the Company to continue your participation therein on the same basis, both in terms of the amount of

benefits provided and the level of your participation relative to other participants, as existed at the time of the Change in Control;

(vi) the failure by the Company to continue to provide you with benefits at least as favorable to those enjoyed by you under any of the Company's

pension, life insurance, medical, health and accident, disability, deferred compensation or savings plans in which you were participating at the time of the

Change in Control, the taking of any action by the Company which would directly or indirectly materially reduce any of such benefits or deprive you of any

material fringe benefit enjoyed by you at the time of the Change in Control, or the failure by the Company to provide you with the number of paid vacation

days to which you are entitled on the basis of the Company's practice with respect to you as in effect at the time of the Change in Control;

(vii) the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform this Agreement, as contemplated

in Section 7 hereof; or

(viii) any purported termination of your employment which is not effected pursuant to a Notice of Termination satisfying the requirements of

Subsection (d) below (and, if applicable, the requirements of Subsection (b) above); for purposes of this Agreement, no such purported termination shall be

effective.
(d) Notice of Termination. Prior to a Change in Control, you may be terminated with or without notice. From and after a Change in Control, any

purported termination of your employment by the Company or by you shall be communicated by written notice to the other party hereto in accordance with

Section 8 hereof ("Notice of Termination"). Such Notice of Termination shall indicate the specific termination provision in this Agreement relied upon and

shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of your employment under the provisions so

indicated.

(e) Date of Termination, Etc. Prior to a Change in Control, "Date of Termination" shall mean the date your employment is terminated. From and after a

Change in Control, "Date of Termination" shall mean (i) if your employment is terminated for Disability, 30 days after Notice of Termination is given

(provided that you shall not have returned to the full-time performance of your duties during such 30 day period, and (ii) if your employment is terminated

pursuant to Subsections 5(b) or 5(c) above or for any other reason (other than Disability), the date specified in the Notice of Termination (which, in the case

of a termination pursuant to Subsection 5(b) above shall not be less than 10 days, and in the case of a termination pursuant to Subsection 5(c) above shall not

be less than 30 nor more than 60 days, respectively, from the date such Notice of Termination is given) (except for a termination pursuant to Subsection

5(c)(vii), in which event the date upon which any succession referred to therein becomes effective shall be deemed the Date of Termination); provided that if at

any time from and after a Change in Control within 30 days after any Notice of Termination is given the party receiving such Notice of Termination notifies

the other party that a dispute exists concerning the termination, the Date of Termination shall be the date on which the dispute is finally determined, either by

mutual written agreement of the parties, by a binding arbitration award, or by a final judgment, order or decree of a court of competent jurisdiction (which is

not appealable or the time for appeal therefrom having expired and no appeal having been perfected); provided further that at any time from and after a Change

in Control the Date of Termination shall be extended by a notice of dispute only if such notice is given in good faith and the party giving such notice pursues

the resolution of such dispute with reasonable diligence. From and after a Change in Control, the Company will continue to pay you your full compensation

in effect when the notice giving rise to the dispute was given (including, but not limited to, base salary) or, if higher, the compensation in effect as of the

Change in Control, and continue you as a participant in all compensation, benefit and insurance plans in which you were participating when the notice giving

rise to the dispute was given, until the dispute is finally resolved in accordance with this Subsection 5(e), notwithstanding the pendency of any such

dispute. Amounts paid under this Subsection 5(e) from and after a Change in Control are in addition to all other amounts due under this Agreement and shall

not be offset against or reduce any other amounts due under this Agreement. Prior to a Change in Control, you shall not be entitled to be paid any

compensation or other amounts due under this Agreement from and after the Date of Termination.

6. Compensation Upon Termination or During Disability. From and after a Change in Control, upon termination of your employment or during a

period of Disability you shall be entitled to the following benefits:

(a) During any period that you fail to perform your full-time duties with the Company as a result of your Disability, you shall continue to receive your

base salary at the rate in effect at the commencement of any such period, together with all compensation payable to you under the Company's disability plan or

other plan during such period, until this Agreement is terminated pursuant to Subsection 5(a) hereof. Thereafter, your benefits shall be determined in

accordance with the Company's long-term disability plan as in effect immediately prior to a Change in Control.
(b) If your employment shall be terminated by the Company for Cause or by you other than for Good Reason, Disability, death or Retirement, the

Company shall pay you your full base salary through the Date of Termination at the rate in effect at the time Notice of Termination is given and any amounts

to be paid to you pursuant to the Company's retirement and other benefits plans of the Company then in effect, and the Company shall have no further

obligations to you under this Agreement.

(c) If your employment shall be terminated by the Company or by you for Retirement, or by reason of your death, your benefits shall be determined in

accordance with the Company's retirement, benefit and insurance programs then in effect.

(d) If your employment by the Company shall be terminated by the Company other than for Cause and other than because of your death, Disability or

Retirement or by you for Good Reason then, effective as of the Date of Termination, in lieu of any severance benefits which you otherwise would be eligible to

receive under the Company's severance plan or policy as in effect immediately prior to the Change in Control, you shall be entitled to the benefits provided

below:

(i) The Company shall pay you your full base salary through the Date of Termination at the rate in effect at the time the Notice of Termination is given,

plus all other amounts to which you are entitled under any compensation or benefit plan of the Company (excluding any severance benefits under the

Company's severance plan or policy) at the time such payments are due under the terms of such plans.

(ii) In lieu of any further salary payments to you for periods subsequent to the Date of Termination, the Company shall pay to you, not later than the

fifth day following the Date of Termination, a lump sum payment equal to three times your annual base salary.

(iii) The Company shall also pay to you all legal fees and expenses incurred by you as a result of such termination (including all such fees and

expenses, if any, incurred in contesting or disputing any such termination or in seeking to obtain or enforce any right or benefit provided by this Agreement).

(iv) Notwithstanding any other provision of this Agreement, if any amount payable hereunder ("Payments") would, individually or together with any

other amounts paid or payable, constitute an "excess parachute payment", within the meaning of Section 280G of the Internal Revenue Code of 1986 and any

applicable regulations thereunder (the "Code") which would require the payment by you of the excise tax imposed by Section 4999 of the Code or any interest

or penalty (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then you shall be entitled

to receive an additional Payment (the "Gross-Up Payment") in an amount such that after the payment by you of all taxes (including any interest or penalties

imposed with respect to such taxes) including, without limitation, any income taxes (and any interest and penalties
 with respect thereto) and the Excise Tax imposed upon the Gross-Up Payment, you shall retain an amount of the Gross-Up Payment equal to the Excise Tax

imposed upon the total Payments to be received by you pursuant to this Agreement. The determination of whether the Gross-Up Payment shall be paid shall be

made by a nationally recognized accounting firm selected by you and such determination shall be binding upon you and the Company for purposes of this

Agreement. The costs and expenses of such accounting firm shall be paid by the Company.

(e) Except as specifically provided in this Section 6, you shall not be required to mitigate the amount of any payment provided for in this Section 6 by

seeking other employment or otherwise, nor shall the amount of any payment or benefit provided for in this Section 6 be reduced by any compensation earned

by you as the result of employment by another employer or by retirement benefits after the Date of Termination, or otherwise.

(f) In addition to all other amounts payable to you under this Section 6, you shall be entitled to receive all benefits payable to you under any other plan

or agreement relating to retirement benefits in accordance with the terms of such plan or agreement.

7. Successors; Binding Agreement. (a) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or

otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner

and to the same extent that the Company would be required to perform it if no such succession had taken place. Such assumption and agreement shall be

obtained prior to the effectiveness of any such succession. As used in this Agreement, "Company" shall mean the Company as herein before defined and any

successor to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement by operation of law, or otherwise. Prior to a Change

in Control, the term "Company" shall also mean any affiliate of the Company to which you may be transferred and Company shall cause such successor

employer to be considered the "Company" bound by the terms of this Agreement and this Agreement shall be amended to so provide. Following a Change in

Control the term "Company" shall not mean any affiliate of the Company to which you may be transferred unless you shall have previously approved of such

transfer in writing, in which case the Company shall cause such successor employer to be considered "Company" bound by the terms of this Agreement and

this Agreement shall be amended to so provide.

(b) This Agreement shall inure to the benefit of and be enforceable by your personal or legal representatives, executors, administrators, successors,

heirs, distributees, devisees and legatees. If you should die while any amount would still be payable to you hereunder if you had continued to live, all such

amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to your devisee, legatee or other designee or, if there is

no such designee, to your estate.

8. Notice. For the purpose of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and shall be

deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the

respective addresses set forth on the first page of this Agreement, provided that all notices to the Company shall be directed to the attention of the Board with a

copy to the Secretary of the Company, or to such other address as either party may have furnished to the other in writing in accordance herewith, except that

notice of change of address shall be effective only upon receipt.

9 Miscellaneous. No provision of this Agreement shall be modified, waived or discharged unless such waiver, modification or discharge is agreed to in

writing and signed by you and such officer as may be specifically
 designated by the Board. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or

provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at

any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made

by either party which are not expressly set forth in this Agreement. THE VALIDITY, INTERPRETATION, CONSTRUCTION AND PERFORMANCE OF

THIS AGREEMENT SHALL BE GOVERNED BY THE LAWS OF THE STATE OF TEXAS.

10 Validity. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of

this Agreement, which shall remain in full force and effect.

11. Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together

will constitute one and the same instrument.

12. Arbitration. THIS AGREEMENT IS SUBJECT TO ARBITRATION UNDER THE TEXAS ARBITRATION ACT. Any dispute or controversy

arising under or in connection with this Agreement shall be settled exclusively by arbitration in San Antonio, Texas in accordance with the rules of the

American Arbitration Association then in effect. Judgment may be entered on the arbitrator's award in any court having jurisdiction; provided, however, that

you shall be entitled to seek specific performance of your right to be paid until the Date of Termination during the pendency of any dispute or controversy

arising under or in connection with this Agreement.

13. Entire Agreement. This Agreement contains the entire agreement by the parties with respect to the matters covered herein and supersedes any prior

agreement (including, without limitation, any prior employment or severance agreement), condition, practice, custom, usage and obligation with respect to

such matters insofar as any such prior agreement, condition, practice, custom, usage or obligation might have given rise to any enforceable right.
If this letter sets forth our agreement on the subject matter hereof, kindly sign and return to the Company the enclosed copy of this letter which will then

constitute our agreement on this subject.

Sincerely,

ABRAXAS PETROLEUM CORPORATION

 

Robert L. G. Watson

Chief Executive Officer

Agreed to this ______ day of

September 2012

Geoffrey R. King
Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

Abraxas Petroleum Corporation

San Antonio, Texas

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-127480, 333-132971, 333-143728, 333-162573, and

333-163763) and Form S-8 (No. 333-17375, 333-17377, 033-81416, 333-55691, 333-74614, 333-74592, 333-135032, 333-153635, 333-162358 and 333-

168022) of Abraxas Petroleum Corporation of our reports dated March 15, 2013, relating to the consolidated financial statements, and the effectiveness of

Abraxas Petroleum Corporation’s internal control over financial reporting, which appear in this Form 10-K.

/s/ BDO USA, LLP

Dallas, Texas

March 18, 2013
Exhibit 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 15, 2013

Abraxas Petroleum Corporation

18803 Meisner Drive

San Antonio, Texas 78258

Ladies and Gentlemen:

We consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton, and to the inclusion of information

taken from our “Appraisal Report as of December 31, 2012 on Certain Properties owned by Abraxas Petroleum Corporation,” “Appraisal Report as of

December 31, 2011 on Certain Properties owned by Abraxas Petroleum Corporation,” “Appraisal Report as of December 31, 2010 on Certain Properties owned

by Abraxas Petroleum Corporation,” “Appraisal Report as of December 31, 2011 on Certain Properties owned by Blue Eagle Energy, LLC” and “Appraisal

Report as of December 31, 2010 on Certain Properties owned by Blue Eagle Energy, LLC” (our Reports) under the sections “Item 1-Business General”, “Item

2-Properties”, “Primary Operating Areas”, and “Reserves Information” in the Abraxas Petroleum Corporation Annual Report on Form 10–K for the year ended

December 31, 2012. We also consent to the inclusion of our letter report dated February 26, 2013 in the Annual Report on Form 10-K of Abraxas Petroleum

Corporation as Exhibit 99.1. We further consent to the incorporation by reference in the Registration Statements on Form S-3 (333-127480, 333-132971, 333-

162537 and 333-163763) and Form S-8 (No. 333-17375, 333-17377, 033-81416, 333-55691, 333-74592, 333-74614, 333-135032,0333-153635, 333-

162358 and 333-168022) of information from our Reports.

Very truly yours,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716
EXHIBIT 31.1

CERTIFICATIONS

I, Robert L. G. Watson, certify that:

1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make

the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report.

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to

ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those

entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal

quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

Date: March 18, 2013

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President and

Principal Executive Officer
EXHIBIT 31.2

CERTIFICATIONS

I, Geoffrey R. King, certify that:

1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to

make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered

by this report.

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to

ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those

entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal

quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

Date: March 18, 2013

/s/ Geoffrey R. King

Geoffrey R. King

Vice President and

Principal Financial Officer
EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Abraxas Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2012 as filed with

the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert L.G. Watson, Chairman of the Board, President and Chief Executive

Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Robert L.G. Watson

Robert L.G. Watson

Chairman of the Board, President and Chief Executive Officer

March 18, 2013

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the

Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to

the Securities and Exchange Commission or its staff upon request.
EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Abraxas Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2012 as filed with

the Securities and Exchange Commission on the date hereof (the “Report”), I, Geoffrey R. King, Vice President and Chief Financial Officer of the Company,

certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/Geoffrey R. King

Geoffrey R. King

Vice President and Chief Financial Officer

March 18, 2013

This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the

Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to

the Securities and Exchange Commission or its staff upon request.
Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 26, 2013

Abraxas Petroleum Corporation

18803 Meisner Drive

San Antonio, Texas 78258

Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the net proved, probable, and possible crude oil, condensate, natural

gas liquids (NGL), and natural gas reserves, as of December 31, 2012, of certain selected properties owned by Abraxas Petroleum Corporation (Abraxas).

This evaluation was completed on February 26, 2013. Abraxas has represented that these properties account for 98 percent on a net equivalent barrel basis of

Abraxas’ net proved reserves as of December 31, 2012. The properties appraised are located in the states of Louisiana, Montana, North Dakota, Oklahoma,

South Dakota, Texas, Utah, Wyoming, and in the province of Alberta in Canada. The net proved, probable, and possible reserves estimates prepared by us

have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC)

of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in

certain SEC filings by Abraxas. All values are shown in United States (U.S.) dollars.

Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties

after December 31, 2012. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Abraxas after deducting all

interests owned by others.

Estimates of oil, condensate, NGL, and natural gas reserves should be regarded only as estimates that may change as further production history and

additional information become available. Not only are such reserves estimates based on that information which is currently available, but such estimates are

also subject

1
to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this evaluation were obtained from reviews with Abraxas personnel, Abraxas files, from records on file with the appropriate regulatory

agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by

Abraxas with respect to property interests, production from such properties, current costs of operation and development, current prices for production,

agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field

examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in

accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled

“Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination

of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic

data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and

isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare

these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified,

material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of

the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When

applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production

rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. Most of the undeveloped reserves were estimated by analogy to

similar wells or offset wells.

2
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics,

reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves,

reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Definition of Reserves

Petroleum reserves estimated by us included in this report are classified as proved, probable, and possible. Reserves classifications used by us in

this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically

producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices

using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic

rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including

consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The

petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and

engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known

reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts

providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or

probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be

reasonably certain that it will commence the project within a reasonable time.

3
(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that

can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of

available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH)

as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact

with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for

an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,

engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not

limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a

whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology

establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project

has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.

The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report,

determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless

prices are defined by contractual arrangements, excluding escalations based upon future conditions.

4
Probable oil and gas reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves

but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of

estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the

actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of

available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable

certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in

communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the

hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible oil and gas reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of

exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10%

probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves

estimates.

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(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of

available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to

define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place

than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative

technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons

to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir

within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness

or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent

portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally

higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil

(HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally

higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through

reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and

possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

6
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is

relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by

means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from

new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain

of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic

producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating

that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of

fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual

projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence

using reliable technology establishing reasonable certainty.

7
The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and

well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as

the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable

with proved reserves.

The development status shown herein represents the status applicable on December 31, 2012. In the preparation of this report, data available from

wells drilled on the appraised properties through December 31, 2012, were used in estimating gross ultimate recovery. When applicable, gross production

estimated to December 31, 2012, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of December 31, 2012. Production

data through November 2012 were available for most properties.

8
Our estimates of Abraxas’s net proved, probable and possible reserves attributable to the reviewed U.S. properties are based on the definitions of

reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

U.S. Net Reserves

Estimated by

DeGolyer and MacNaughton

as of December 31, 2012

Oil and

Condensate

(Mbbl)

NGL

(Mbbl)

Sales

Gas

(MMcf)

Oil

Equivalent

(Mboe)

Proved

 Developed Producing 6,426 1,243 38,039 14,009

 Developed Nonproducing 714 54 1,331 990

 Undeveloped 9,932 1,285 19,302 14,434

Total Proved 17,072 2,582 58,672 29,433

Probable

 Developed Producing 17 4 21 24

 Developed Nonproducing 6 6 0 346 124

 Undeveloped 12,233 2,532 57,082 24,279

Total Probable 12,316 2,536 57,449 24,427

Possible

 Developed Producing 0 0 0 0

 Developed Nonproducing 0 0 0 0

 Undeveloped 10,555 1,177 17,578 14,662

Total Possible 10,555 1,177 17,578 14,662

Notes:

1. Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

2. Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per

 1 barrel of oil equivalent.

9
Our estimates of Abraxas’s net proved and probable reserves attributable to the reviewed Canadian properties are based on the definitions of reserves

of the SEC and are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

Canada Net Reserves

Estimated by

DeGolyer and MacNaughton

as of December 31, 2012

Oil and

Condensate

(Mbbl)

NGL

(Mbbl)

Sales

Gas

(MMcf)

Oil

Equivalent

(Mboe)

Proved

 Developed Producing 110 0 497 193

 Developed Nonproducing 0 0 0 0

 Undeveloped 74 0 588 172

Total Proved 184 0 1,085 365

Probable

 Developed Producing 5 0 24 9

 Developed Nonproducing 0 0 0 0

 Undeveloped 0 0 0 0

Total Probable 5 0 24 9

Possible 0 0 0 0

Notes:

1. Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

2. Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per

 1 barrel of oil equivalent.

Primary Economic Assumptions

Revenue values in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth of future net revenue.

Future gross revenue is defined as that revenue to be realized from the production and sale of the estimated net reserves. Future net revenue is calculated by

deducting estimated production taxes, ad valorem taxes, operating, gathering, processing expenses, and capital costs from the future gross revenue. Present

worth of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded monthly over the

expected period of realization.

10
Revenue values in this report were estimated using the initial prices and expenses provided by Abraxas. Future prices were estimated using guidelines

established by the SEC and the Financial Accounting Standards Board (FASB). The prices used in this report are based on SEC guidelines. The following

economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, and NGL Prices

Abraxas has represented that the oil, condensate, and NGL prices were based on a reference price, calculated as the unweighted

arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting

period, unless prices are defined by contractual arrangements. Abraxas supplied differentials to a West Texas Intermediate (WTI)

reference price of $95.14 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to

estimated proved reserves was $88.28 per barrel.

NGL prices were provided by Abraxas for each property using the first-day-of-the-month prices and were held constant thereafter.

The volume-weighted average price attributable to estimated proved reserves was $36.76 per barrel.

Natural Gas Prices

Abraxas has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average

of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices

are defined my contractual arrangements. The gas prices were calculated for each property using differentials to the reference price

of $2.86 per million British thermal units (MMBtu) furnished by Abraxas and held constant thereafter. The volume-weighted

average price attributable to estimated proved reserves was $2.61 per thousand cubic feet (Mcf).

11
Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Abraxas, were used in estimating future costs required to

operate the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of

anticipated changes in operating conditions. These costs were not escalated for inflation.

The estimated future revenue and expenditures attributable to the production and sale of Abraxas’s net proved, probable and possible reserves of the

U.S. properties appraised, as of December 31, 2012, is summarized in thousands of dollars (M$) as follows:

Proved

Developed

Producing

Developed

Nonproducing Undeveloped

Total

Proved

Future Gross Revenue, M$ 705,536 68,788 980,886 1,755,210

Production and Ad Valorem Taxes, M$ 65,754 6,800 98,564 171,118

Operating Expenses, M$ 275,405 10,050 169,796 455,251

Capital Costs, M$ 326 6,461 316,215 323,002

Abandonment Costs, M$ 1,425 0 38 1,463

Future Net Revenue, M$ 362,626 45,477 396,273 804,376

Present Worth at 10 Percent, M$ 187,637 24,113 100,154 311,904

Note: Future income taxes have not been taken into account in the preparation of these estimates.

Probable

Developed

Producing

Developed

Nonproducing Undeveloped

Total

Probable

Future Gross Revenue, M$ 1,882 7,481 1,343,757 1,353,120

Production and Ad Valorem Taxes, M$ 146 568 138,098 138,812

Operating Expenses, M$ 259 441 207,444 208,144

Capital Costs, M$ 0 560 418,895 419,455

Abandonment Costs, M$ 0 0 87 87

Future Net Revenue, M$ 1,477 5,912 579,233 586,622

Present Worth at 10 Percent, M$ 606 3,980 144,946 149,532

Notes:

1. Future income taxes have not been taken into account in the preparation of these estimates.

2. Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

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Possible

Developed

Producing

Developed

Nonproducing Undeveloped

Total

Possible

Future Gross Revenue, M$ 0 0 1,003,603 1,003,603

Production and Ad Valorem Taxes, M$ 0 0 98,041 98,041

Operating Expenses, M$ 0 0 197,790 197,790

Capital Costs, M$ 0 0 370,751 370,751

Abandonment Costs, M$ 0 0 0 0

Future Net Revenue, M$ 0 0 337,021 337,021

Present Worth at 10 Percent, M$ 0 0 61,443 61,443

Notes:

1. Future income taxes have not been taken into account in the preparation of these estimates.

2. Values for possible reserves have not been risk adjusted to make them comparable to values for proved reserves.

The estimated future revenue and expenditures attributable to the production and sale Abraxas’s net proved and probable reserves of the Canadian

properties appraised, as of December 31, 2012, is summarized in thousands of dollars (M$) as follows:

Proved

Developed

Producing

Developed

Nonproducing Undeveloped

Total

Proved

Future Gross Revenue, M$ 12,216 0 8,521 20,737

Production and Ad Valorem Taxes, M$ 0 0 0 0

Operating Expenses, M$ 5,387 0 2,416 7,803

Capital Costs, M$ 0 0 3,500 3,500

Abandonment Costs, M$ 300 0 50 350

Future Net Revenue, M$ 3,655 0 773 4,428

Present Worth at 10 Percent, M$ 3,697 0 436 4,133

Note: Future income taxes have not been taken into account in the preparation of these estimates.

Probable

Developed

Producing

Developed

Nonproducing Undeveloped

Total

Probable

Future Gross Revenue, M$ 498 0 0 498

Production and Ad Valorem Taxes, M$ 0 0 0 0

Operating Expenses, M$ 352 0 0 352

Capital Costs, M$ 0 0 0 0

Abandonment Costs, M$ 0 0 0 0

Future Net Revenue, M$ 71 0 0 71

Present Worth at 10 Percent, M$ 115 0 0 115

Notes:

1. Future income taxes have not been taken into account in the preparation of these estimates.

2. Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

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While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its

oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2012, estimated oil and gas

reserves. The reserves estimated in this report can be produced under current regulatory guidelines.

In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved, probable,

and possible reserves, and present worth of estimated future net revenue from proved, probable, and possible reserves of oil, condensate, natural gas liquids,

and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-

30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas

Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules

302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, (i) future

income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the

proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are

necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

14
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services

throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Abraxas. Our fees were not

contingent on the results of our evaluation. This letter report has been prepared at the request of Abraxas. DeGolyer and MacNaughton has used all

assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

15
DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A.,

hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Abraxas dated

February 26, 2013, and that I, as Senior Vice President, was responsible for the preparation of this report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am

a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American

Association of Petroleum Geologists; and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves evaluations.

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

16