Edgar Filing: ABRAXAS PETROLEUM CORP

AXAS 10-Q Q2 06.30.2013

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2013



o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______ TO ______

COMMISSION FILE NUMBER: 001-16071

ABRAXAS PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)



Nevada		74-2584033
(State of Incorporation)		(I.R.S. Employer Identification No.)

18803 Meisner Drive, San Antonio, TX 78258

(Address of principal executive offices) (Zip Code)

210-490-4788

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether 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 ýNo ¨

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



Large accelerated filer o	Accelerated filer x
Non-accelerated filer o (Do not mark if a smaller reporting company)	Smaller reporting company o

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

The number of shares of the issuer’s common stock outstanding as of August 6, 2013 was 92,799,262.

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 “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.

“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.

“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.”

ABRAXAS PETROLEUM CORPORATION

FORM 10 – Q

INDEX



PART I
FINANCIAL INFORMATION

ITEM 1 -	Financial Statements
	Condensed Consolidated Balance Sheets - June 30, 2013 (unaudited) and December 31, 2012		6
	Condensed Consolidated Statements of Operations – (unaudited) Three and Six Months Ended June 30, 2013 and 2012		8
	Condensed Consolidated Statements of Other Comprehensive Income (Loss) – (unaudited) Three and Six Months Ended June 30, 2013 and 2012		9
	Condensed Consolidated Statements of Cash Flows – (unaudited) Six Months Ended June 30, 2013 and 2012		10
	Notes to Condensed Consolidated Financial Statements - (unaudited)		11

ITEM 2 -	Management's Discussion and Analysis of Financial Condition and Results of Operations		24

ITEM 3 -	Quantitative and Qualitative Disclosures about Market Risk		37

ITEM 4 -	Controls and Procedures		38

PART II
OTHER INFORMATION

ITEM 1 -		Legal Proceedings	39
ITEM 1A -		Risk Factors	39
ITEM 2 -		Unregistered Sales of Equity Securities and Use of Proceeds	39
ITEM 3 -		Defaults Upon Senior Securities	39
ITEM 4 -		Mine Safety Disclosure	39
ITEM 5 -		Other Information	39
ITEM 6 -		Exhibits	39
		Signatures	40

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets

(in thousands)



	June 30, 2013 (Unaudited)			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	2,432		$	2,061
Accounts receivable, net:
Joint owners	5,647			8,883
Oil and gas production	16,366			10,887
Other	4,880			661
	26,893			20,431

Derivative asset – current	1,170			41
Assets held for sale	34,800			—
Other current assets	624			488
Total current assets	65,919			23,021

Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved	550,407			563,317
Unproved properties excluded from depletion	3,779			2,089
Other property and equipment	38,249			37,833
Total	592,435			603,239
Less accumulated depreciation, depletion, and amortization	(404,088		)	(390,407		)
Total property and equipment – net	188,347			212,832


Deferred financing fees, net	2,817			3,397
Derivative asset – long-term	2,317			594
Other assets	693			763
Total assets	$	260,093		$	240,607

See accompanying notes to condensed consolidated financial statements (unaudited).

Abraxas Petroleum Corporation

Condensed Consolidated Balance Sheets (continued)

(in thousands, except share data)



	June 30, 2013 (Unaudited)			December 31, 2012
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	41,971		$	42,387
Oil and gas production payable	14,006			6,947
Accrued interest	86			75
Other accrued expenses	2,139			962
Derivative liability – current	2,532			3,462
Current maturities of long-term debt	1,634			657
Total current liabilities	62,368			54,490

Long-term debt, excluding current maturities	131,023			124,101
Other liabilities	57			367
Derivative liability – long-term	510			3,568
Future site restoration	10,136			11,381
Total liabilities	204,094			193,907

Stockholders’ Equity
Preferred stock, par value $0.01 per share, authorized 1,000,000 shares; -0- issued and outstanding	—			—
Common stock, par value $0.01 per share, authorized 200,000,000 shares; 92,799,762 and 92,733,448 issued and outstanding	928			927
Additional paid-in capital	252,184			250,998
Accumulated deficit	(196,796		)	(205,256		)
Accumulated other comprehensive (loss) income	(317		)	31
Total stockholders’ equity	55,999			46,700
Total liabilities and stockholders’ equity	$	260,093		$	240,607

See accompanying notes to condensed consolidated financial statements (unaudited).

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Operations

(Unaudited)

(in thousands except per share data)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Revenue:
Oil and gas production revenues	$	21,478		$	15,934		$	42,641		$	32,313
Other	16			4			49			18
	21,494			15,938			42,690			32,331
Operating costs and expenses:
Lease operating expenses	6,166			5,382			12,628			11,316
Production taxes	1,911			1,489			3,838			2,985
Depreciation, depletion, and amortization	5,776			5,380			12,285			10,218
Impairment	1,977			1,306			1,977			1,306
General and administrative (including stock-based compensation of $669, $722, $1,142 and $1,199, respectively)	2,797			2,404			5,327			4,305
	18,627			15,961			36,055			30,130
Operating income (loss)	2,867			(23		)	6,635			2,201

Other (income) expense:
Interest income	—			(1		)	(1		)	(2		)
Interest expense	1,259			1,270			2,467			2,465
Amortization of deferred financing fees	343			266			676			296
(Gain) loss on derivative contracts - Realized	783			(914		)	1,708			(866		)
(Gain) loss on derivative contracts - Unrealized	(7,485		)	(10,296		)	(6,864		)	(9,420		)
Earnings from equity method investment	—			(1,251		)	—			(2,034		)
Other	14			—			101			42
	(5,086		)	(10,926		)	(1,913		)	(9,519		)
Net income before income tax	7,953			10,903			8,548			11,720
Income tax expense	87			—			87			—
Net income	$	7,866		$	10,903		$	8,461		$	11,720

Net income per common share – basic	$	0.09		$	0.12		$	0.09		$	0.13

Net income per common share – diluted	$	0.08		$	0.12		$	0.09		$	0.13

See accompanying notes to condensed consolidated financial statements (unaudited).

Abraxas Petroleum Corporation

Condensed Consolidated Statements of

Other Comprehensive Income (Loss)

(Unaudited)

(in thousands)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Consolidated net income	$	7,866		$	10,903		$	8,461		$	11,720
Other comprehensive income (loss):
Change in unrealized value of investments	56			(34		)	49			(38		)
Foreign currency translation adjustment	(266		)	(500		)	(397		)	(215		)
Other comprehensive loss	(210		)	(534		)	(348		)	(253		)
Comprehensive income	$	7,656		$	10,369		$	8,113		$	11,467

See accompanying notes to condensed consolidated financial statements (unaudited).

Abraxas Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(in thousands)



	Six Months Ended June 30,
	2013			2012
Operating Activities
Net income	$	8,461		$	11,720
Adjustments to reconcile net income to net
cash provided by (used in) operating activities:
Equity in gain of joint venture	—			(2,034		)
Change in derivative fair value	(6,840		)	(10,472		)
Monetization of derivative contracts	—			12,364
Depreciation, depletion, and amortization	12,285			10,218
Impairment	1,977			1,306
Amortization of deferred financing fees	676			296
Accretion of future site restoration	335			235
Stock-based compensation	1,142			1,199
Changes in operating assets and liabilities:
Accounts receivable	(6,474		)	1,507
Other	4,941			(79		)
Accounts payable and accrued expenses	6,268			(517		)
Net cash provided by operating activities	22,771			25,743

Investing Activities
Capital expenditures, including purchases and development of properties	(33,466		)	(35,116		)
Proceeds from sale of oil and gas properties	3,192			—
Net cash used in investing activities	(30,274		)	(35,116		)

Financing Activities
Proceeds from long-term borrowings	21,000			14,500
Payments on long-term borrowings	(13,101		)	(4,089		)
Deferred financing fees	(96		)	(603		)
Exercise of stock options	44			—
Other	(29		)	(128		)
Net cash provided by financing activities	7,818			9,680
Effect of exchange rate changes on cash	56			1
Increase in cash	371			308
Cash and equivalents, at beginning of period	$	2,061		—
Cash and equivalents, at end of period	$	2,432		$	308

Supplemental disclosure of cash flow information:
Interest paid	$	2,256		$	2,289

See accompanying notes to condensed consolidated financial statements (unaudited).

Abraxas Petroleum Corporation

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(tabular amounts in thousands, except per unit data)

Note 1. Basis of Presentation

The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the “Company”) are set forth in the notes to the Company’s audited consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 18, 2013. Such policies have been continued without change. Also, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations, and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim condensed consolidated financial statements have not been audited by our independent registered public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. Although management believes the unaudited interim related disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the SEC. The results of operations and the cash flows for the period ended June 30, 2013 are not necessarily indicative of the results to be expected for the full year. The condensed consolidated financial statements included herein should be read in conjunction with the consolidated audited financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Consolidation Principles

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 a wholly-owned foreign subsidiary, Canadian Abraxas Petroleum, ULC (“Canadian Abraxas”).

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 to be 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 to be credited to the full cost pool and recognized through lower amortization as reserves are produced.

Use of Estimates

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

Stock-based Compensation and Option Plans

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 following table summarizes the Company’s stock-based compensation expense related to stock options for the periods presented:



Three Months Ended June 30,				Six Months Ended June 30,
2013		2012		2013		2012
$	558	$	599	$	920	$	944

The following table summarizes the Company’s stock option activity for the six months ended June 30, 2013:



	Number of Shares		Weighted Average Option Exercise Price Per Share		Weighted Average Grant Date Fair Value Per Share
Outstanding, December 31, 2012	4,761		$	2.77	$	1.98
Granted	801		2.39		1.70
Exercised	(66	)	0.68		0.32
Canceled	(1	)	$	2.18	$	1.53
Outstanding, June 30, 2013	5,495		$	2.74	$	1.96

Additional information related to stock options at June 30, 2013 and December 31, 2012 is as follows:



	June 30, 2013	December 31, 2012
Options exercisable	3,592	2,992

As of June 30, 2013, there was approximately $2.9 million of unamortized compensation expense related to outstanding stock options that will be recognized in 2013 through 2016.

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 fair value of such stock was determined using the closing price on the grant date and compensation expense is recorded over the applicable vesting periods.

The following table summarizes the Company’s restricted stock activity for the six months ended June 30, 2013:



	Number of Shares		Weighted Average Grant Date Fair Value Per Share
Unvested, December 31, 2012	482		$	3.09
Granted	1		2.42
Vested/Released	(44	)	1.92
Forfeited	—		—
Unvested, June 30, 2013	439		$	3.21

The following table summarizes the Company’s stock-based compensation expense related to restricted stock for the periods presented:



Three Months Ended June 30,				Six Months Ended June 30,
2013		2012		2013		2012
$	111	$	123	$	222	$	255

As of June 30, 2013, there was approximately $0.9 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized in 2013 through 2015.

Assets Held for Sale

During the second quarter of 2013 the Company entered into a purchase and sale agreement to sell certain non-operated properties for anticipated net proceeds of $34.8 million. The assets which the Company agreed to sell in June 2013 are presented separately as "Assets held for sale" in the condensed consolidated balance sheet at June 30, 2013. Assets held for sale were recorded at the amount of the expected sales proceeds less fees with a corresponding reduction to the full cost pool. As the sale was not significant under full cost accounting rules, no gain or loss was recognized. Proceeds from this sale are expected to be received upon closing in August 2013.

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 the 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-of-production 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 the unamortized capitalized cost or the cost ceiling. The ceiling cost is calculated as PV-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. We calculate the projected income tax effect using the “short-cut” method for the cost ceiling test calculation. Costs in excess of the cost ceiling are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties, except where the sale or disposition causes a significant change in the relationship between capitalized cost and the estimated quantity of proved reserves. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. At June 30, 2012, our net capitalized costs of oil and gas properties in the United States did not exceed the cost ceiling of our estimated Proved reserves; however, the net capitalized cost of oil and gas properties in Canada exceeded the cost ceiling by $1.3 million resulting in a write down for the six months ended June 30, 2012. At June 30, 2013, our net capitalized costs of oil and gas properties in the United States did not exceed the cost ceiling of our estimated proved reserves; however, the net capitalized cost of oil and gas properties in Canada exceeded the cost ceiling by $2.0 million resulting in a write down for the six months ended June 30, 2013.

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 non-capital 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 amortize these costs as a component of our depletion expense in the accompanying condensed consolidated financial statements.

The following table summarizes the Company’s asset retirement obligation transactions for the six months ended June 30, 2013 and the year ended December 31, 2012:



	June 30, 2013			December 31, 2012
Beginning asset retirement obligation	$	11,381		$	8,412
New wells placed on production and other	117			330
Deletions related to property disposals and plugging costs	(1,667		)	(423		)
Accretion expense	335			474
Revisions	(30		)	2,588
Ending asset retirement obligation	$	10,136		$	11,381

Working Capital (Deficit)

At June 30, 2013, our current assets of $65.9 million exceed our current liabilities of approximately $62.4 million resulting in working capital of $3.5 million. This compares to a working capital deficit of $31.5 million at December 31, 2012. Current assets at June 30, 2013 primarily consisted of accounts receivable of $26.9 million and assets held for sale of $34.8 million. Current liabilities at June 30, 2013 primarily consisted of trade payables of $42.0 million, revenues due third parties of $14.0 million, current portion of derivative liabilities of $2.5 million, current maturities of long-term debt of $1.6 million and accrued liabilities of $2.2 million.

Note 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. Blue Eagle was dissolved effective August 31, 2012.

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 “Earnings from equity method investment.” For the three and six months ended June 30, 2012 we reported income of $1.3 million and $2.0 million respectively related to Blue Eagle.

The following is condensed financial data from Blue Eagle’s June 30, 2012 financial statements:



	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012
Revenue:	$	5,946	$	9,767
Operating expenses	2,899		5,027
Other (income) expense	—		(1		)
Net income:	$	3,047	$	4,741

Note 3. Income Taxes

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

For the three and six months ended June 30, 2013, there wase no current or deferred income tax expense or benefit due to loss carryforwards. Valuation allowances have been recorded against such benefits in prior periods.

The Company accounts for uncertain tax positions under the provisions of 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. 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. On July 23, 2013 we settled the assessment for $391,000 resulting in $81,000 being recognized as expense for the quarter ended June 30, 2013.

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.

Note 4. Long-Term Debt

The following table summarizes the Company’s long-term debt:



	June 30, 2013			December 31, 2012
Credit facility	$	121,000		$	113,000
Rig loan agreement	7,000			7,000
Real estate lien note	4,657			4,758
	132,657			124,758
Less current maturities	(1,634		)	(657		)
	$	131,023		$	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 June 30, 2013, $121.0 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. As of December 31, 2012 we had a borrowing base of $150.0 million. Effective March 31, 2013, the facility was amended and increased to $155.0 million. In connection with the asset sale described in Note 1, our borrowing base will be reduced to $143.0 million. Unless redetermined otherwise based on new reserve and production information from the June 30, 2013 engineering report, the borrowing base will reduce to $133.0 million on October 1, 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 $155.0 million based upon our reserve report dated

December 31, 2012. 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 June 30, 2013 the interest rate on the credit facility was 3.2% based on 1-month LIBOR borrowings and the 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 debt to EBITDAX ratio as of the last day of each quarter of not more than 4.00 to 1.00. 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 defined as the sum of 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, Raven Drilling’s rig loan and obligations with respect to surety bonds and derivative contracts.

At June 30, 2013, we were in compliance with all of our debt covenants. As of June 30, 2013, the interest coverage ratio was 7.88 to 1.00, the total debt to EBITDAX ratio was 3.85 to 1.00 and our current ratio was 1.70 to 1.00.

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 2,000 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 June 30, 2013, $7.0 million was outstanding under the rig loan agreement.

Abraxas Petroleum 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 was modified on April 4, 2013, reducing the interest to a fixed rate of 4.0%, effective March 13, 2013 and was payable in monthly installments of principal and interest of $33,763 based on a twenty year amortization. The note was to matures in May 2015 at which time the outstanding balance would have become due. The note is secured by a first lien deed of trust on the property and improvements. As of June 30, 2013, $4.7 million was outstanding on the note. This note was modified on July 20, 2013. The modification extended the maturity date to July 20, 2023. The note will bear interest for five years at a fixed rate of 4.25% and is payable in month installments of $34,354. Beginning August 20, 2018, the interest rate will adjust to the bank's current prime rate plus 1.00% with a maximum annual rate of 7.25% .

Note 5. Income Per Share

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Numerator:
Net income	$	7,866	$	10,903	$	8,461	$	11,720
Denominator:
Denominator for basic income per share -
Weighted-average shares	92,351		91,808		92,323		91,775

Effect of dilutive securities:
Stock options and restricted stock	1,010		1,455		988		1,673

Denominator for diluted income per share -
Weighted-average shares and assumed conversions	93,361		93,263		93,311		93,448

Net income per common share – basic	$	0.09	$	0.12	$	0.09	$	0.13

Net income per common share – diluted	$	0.08	$	0.12	$	0.09	$	0.13

Note 6. 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. Management has elected not to apply hedge accounting as prescribed by ASC 815. Accordingly, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period.

The following table sets forth our derivative contracts at June 30, 2013:



	Fixed Price Swap
	Oil – WTI			Oil - Brent
Contract Periods	Daily Volume (Bbl)	Swap Price (per Bbl)		Daily Volume (Bbl)	Swap Price (per Bbl)
2013	1,007	$	84.76	510	$	105.00
2014	687	$	94.16	505	$	100.56
2015	560	$	83.03	500	$	97.04
2016	963	$	84.10	—	$	—
2017	500	$	84.18	—	$	—

At June 30, 2013, the aggregate fair value of our commodity derivative contracts was an asset of approximately $0.4 million.

The following table illustrates the impact of derivative contracts on the Company’s balance sheet:



Fair Value of Derivative Instruments as of June 30, 2013
	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	$	1,170	Derivatives – current	$	2,532
Commodity price derivatives	Derivatives - long-term	2,317		Derivatives - long-term	510
		$	3,487		$	3,042



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 “(Gain) loss on derivative contracts” in the accompanying condensed consolidated statements of operations.

Note 7. Fair Value

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:


•	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 set forth information about the Company’s assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 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 June 30, 2013
Assets:
Investment in common stock	$	128	$	—	$	—	$	128
NYMEX Fixed Price Derivative contracts	—		3,487		—		3,487
Total Assets	$	128	$	3,487	$	—	$	3,615
Liabilities:
NYMEX Fixed Price Derivative contracts	$	—	$	3,042	$	—	$	3,042
Total Liabilities	$	—	$	3,042	$	—	$	3,042



	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 Insignia 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 June 30, 2013 and December 31, 2012 in U.S. dollars. Accordingly, this investment is characterized as Level 1. On May 6, 2013, Insignia Energy Ltd, announced plans to privatize the company whereby all shareholders will receive C$1.35 per share. On July 19, 2013 Insignia announced that it had completed the plan. The Company has submitted its shares for the cash consideration.

The Company’s derivative contracts consist of NYMEX-based fixed price commodity swaps and Brent-based fixed price commodity swaps. The NYMEX-based and Brent based fixed price derivative contracts are indexed to their respective futures contracts, which are actively traded for the underlying commodity and commonly used in the energy industry. 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.

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.

Note 8. Business Segments

The following tables provide the Company’s geographic operating segment data for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30, 2013
	U.S.		Canada			Corporate			Total
Revenues:
Oil and gas production	$	20,946	$	532		$	—		$	21,478
Other	—		—			16			16
	20,946		532			16			21,494
Expenses:
Lease operating	5,783		383			—			6,166
Production taxes	1,906		5			—			1,911
Depreciation, depletion and amortization	5,411		302			63			5,776
Impairment	—		1,977			—			1,977
General and administrative	486		186			2,125			2,797
Net interest	157		5			1,097			1,259
Amortization of deferred financing fees	—		—			343			343
Loss on derivative contracts - Realized	—		—			783			783
(Gain) on derivative contracts - Unrealized	—		—			(7,485		)	(7,485		)
Other	—		—			14			14
Income tax	—		—			87			87
Net income (loss)	$	7,203	$	(2,326	)	$	2,989		$	7,866



	Three Months Ended June 30, 2012
	U.S.		Canada			Corporate			Total
Revenues:
Oil and gas production	$	15,112	$	822		$	—		$	15,934
Other	—		—			4			4
	15,112		822			4			15,938
Expenses (income):
Lease operating	5,041		341			—			5,382
Production taxes	1,489		—			—			1,489
Depreciation, depletion and amortization	4,896		421			63			5,380
Impairment	—		1,306			—			1,306
General and administrative	377		174			1,853			2,404
Net interest	115		4			1,150			1,269
Amortization of deferred financing fees	—		—			266			266
Earnings from equity method investment	—		—			(1,251		)	(1,251		)
(Gain) on derivative contracts - Realized	—		—			(914		)	(914		)
(Gain) on derivative contracts - Unrealized	—		—			(10,296		)	(10,296		)
Other	—		—			—			—
Net income (loss)	$	3,194	$	(1,424	)	$	9,133		$	10,903



		Six Months Ended June 30, 2013
		U.S.		Canada			Corporate			Total
Revenues:
Oil and gas production		$	41,504	$	1,137		$	—		$	42,641
Other		—		—			49			49
		41,504		1,137			49			42,690
Expenses:
Lease operating		11,587		1,041			—			12,628
Production taxes		3,833		5			—			3,838
Depreciation, depletion and amortization		11,625		535			125			12,285
Impairment		—		1,977			—			1,977
General and administrative		961		341			4,025			5,327
Net interest		323		11			2,132			2,466
Amortization of deferred financing fees		—		—			676			676
Loss on derivative contracts - Realized		—		—			1,708			1,708
(Gain) on derivative contracts - Unrealized		—		—			(6,864		)	(6,864		)
Other		—		—			101			101
Income tax	—	—		—			87			87
Net income (loss)		$	13,175	$	(2,773	)	$	(1,941	)	$	8,461



	Six Months Ended June 30, 2012
	U.S.		Canada			Corporate			Total
Revenues:
Oil and gas production	$	30,987	$	1,326		$	—		$	32,313
Other	—		—			18			18
	30,987		1,326			18			32,331
Expenses:
Lease operating	10,750		566			—			11,316
Production taxes	2,985		—			—			2,985
Depreciation, depletion and amortization	9,454		639			125			10,218
Impairment	—		1,306			—			1,306
General and administrative	703		295			3,307			4,305
Net interest	227		8			2,228			2,463
Amortization of deferred financing fees	—		—			296			296
Earnings from equity method investment	—		—			(2,034		)	(2,034		)
(Gain) on derivative contracts - Realized	—		—			(866		)	(866		)
(Gain) on derivative contracts - Unrealized	—		—			(9,420		)	(9,420		)
Other	—		—			42			42
Net income (loss)	$	6,868	$	(1,488	)	$	6,340		$	11,720

The following table provides the Company’s geographic asset data as of June 30, 2013 and December 31, 2012:



Segment Assets:	June 30, 2013		December 31, 2012
United States	$	206,900	$	223,253
Canada	5,888		7,053
Corporate	47,305		10,301
	$	260,093	$	240,607

Note 9. Contingencies – Litigation

From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At June 30, 2013, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its operations.

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

The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 18, 2013.

The results of operations set forth below do not include our interest in the operations of Blue Eagle which was dissolved effective August 31, 2012.

Except as otherwise noted, all tabular amounts are in thousands except per unit values.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in our Annual Report on Form 10-K for the year ended December 31, 2012.

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.

Factors Affecting Our Financial Results

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;


•	the level of and interest rates on borrowings; and


•	the level and success of exploration and development activity

Commodity Prices and Hedging Activities

The results of our operations are highly dependent upon the prices received for our production. The prices we receive 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 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 production are dependent upon numerous factors beyond our control. Significant declines in commodity prices could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis.

During the six months ended June 30, 2013, the New York Mercantile (NYMEX) future price for oil averaged $94.26 per barrel as compared to $98.13 per barrel during the six months ended June 30, 2012. NYMEX future spot prices for gas averaged $3.76 per MMBtu for the six months ended June 30, 2013 compared to $2.36 for the same period of 2012. Prices closed on June 30, 2013 at $96.56 per Bbl of oil and $3.57 per MMBtu of gas, compared to closing on June 30, 2012 at $84.96 per Bbl of oil and $2.74 per MMBtu of gas. 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;


•	quality of the hydrocarbons; and


•	gathering; processing and transportation costs.

The following table sets forth our average differentials for the six months ended June 30, 2013 and 2012:



	Oil - NYMEX						Gas - NYMEX
	2013			2012			2013			2012
Average realized price (1)	$	90.61		$	86.36		$	3.26		$	2.02
Average NYMEX price	$	94.26		$	98.13		$	3.76		$	2.36
Differential	$	(3.65	)	$	(11.77	)	$	(0.50	)	$	(0.34	)


(1)	excludes the impact of derivative activities

Increases in the differential between the NYMEX price and the realized price we receive have in the past, and could in the future, significantly reduce our revenues and cash flow from operations. The increase in the gas differential was primarily due to gas produced in the Eagle Ford which has a higher differential due to the quality of the gas.

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. By removing a significant portion of price volatility on our future 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 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 recognize realized and unrealized gains on our commodity derivative contracts. In the six months ended June 30, 2013, we recognized a realized loss of $1.7 million and an unrealized gain of $6.9 million on our commodity swaps. In the six months ended June 30, 2012, we recognized a realized gain of $2.0 million and an unrealized gain of $8.5 million on our commodity swaps. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.

The following table sets forth our derivative contracts at June 30, 2013:



	Fixed Price Swap
	Oil – WTI			Oil - Brent
Contract Periods	Daily Volume (Bbl)	Swap Price (per Bbl)		Daily Volume (Bbl)	Swap Price (per Bbl)
2013	1,007	$	84.76	510	$	105.00
2014	687	$	94.16	505	$	100.56
2015	560	$	83.03	500	$	97.04
2016	963	$	84.10	—	$	—
2017	500	$	84.18	—	$	—

At June 30, 2013, the aggregate fair value of our oil and gas derivative contracts was an asset of approximately $0.4 million.

Production Volumes

Our proved reserves will decline as oil and gas are produced, unless we find, acquire or develop additional properties containing Proved reserves or conduct successful exploration and development activities in a timely manner. Based on the reserve information set forth in our reserve estimates as of December 31, 2012, the 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. Our ability to acquire or find additional reserves will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.

We had capital expenditures of $33.5 million during the six months ended June 30, 2013. We have a capital expenditure budget for 2013 of $70.0 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 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.

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, 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 June 30, 2013, we had $34.0 million of availability under our credit facility.

Exploration and Development Activity

We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. 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.

Operational Update

Williston Basin

In McKenzie County, North Dakota, the Lillibridge 1H, 2H and 3H have all been flowing to sales at rates significantly above the Company's type curve. The Lillibridge 1H, producing from the Middle Bakken, is currently producing 1,442 Boepd (1,165 barrels of oil per day, 1,662 Mcf of natural gas per day) on a 16/64” choke. Cumulative production from the Lillibridge 1H is 18,423 Boe (14,920 barrels of oil, 21,018 Mcf of natural gas) over its first 16 full production days on a restricted choke. The Lillibridge 2H, producing from the Three Forks, is currently producing 1,170 Boepd (943 barrels of oil per day, 1,364 Mcf of natural gas per day) on a 18/64” choke. Cumulative production from the Lillibridge 2H is 15,866 Boe (12,761 barrels of oil, 18,630 Mcf of natural gas) over its first 16 full production days on a restricted choke. The Lillibridge 3H, producing from the Middle Bakken, is currently producing 1,794 Boepd (1,428 barrels of oil per day, 2,195 Mcf of natural gas per day) on a 12/64” choke. Cumulative production from the Lillibridge 3H is 14,158 Boe (11,233 barrels of oil, 17,547 Mcf of natural gas) over its first 11 full production days on a restricted choke. The production rates for each well do not include the impact of natural gas liquids and shrinkage at the processing plant. The Lillibridge 4H is currently shut in awaiting cleanout due to what is believed to be a sand plug. Post cleaning out the well with coil tubing Abraxas will provide its flow rate. Each of the three producing Lillibridge wells was constrained on a smaller than normal choke to manage midstream gas takeaway bottlenecks, which are being remedied.

On the Lillibridge West pad, Abraxas recently set intermediate casing on the Lillibridge 7H and is currently drilling the final intermediate section on the Lillibridge 8H. After reaching TD on the intermediate section for the 8H, Abraxas will commence the drilling of all four laterals. Abraxas owns a working interest of approximately 34% in both the Lillibridge East and West pads.

Eagle Ford Shale

In McMullen County, Texas, Abraxas' forty acre pilot wells, the Camaro B 3H and Camaro B 4H, have been successfully completed with 39 stages across the two wells. Post the drilling out of plugs, the wells will be turned over to sales. The Company is currently prepping the Gran Torino A 11H for a 19 stage completion. Abraxas' thirteenth well at the WyCross prospect, the Sting Ray A 8H is currently drilling below 4,500 feet. Abraxas owns an 18.75% working interest in the Sting Ray A 8H and Gran Torino A 11H and a 25% working interest in the Camaro B 3H and Camaro B 4H.

Results of Operations

The following table sets forth certain of our consolidated operating data for the periods presented:



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
Operating revenue: (1)
Oil sales	$	17,261	$	12,897		$	34,445	$	26,289
Gas sales	3,137		1,943			5,989		4,005
NGL sales	1,080		1,094			2,207		2,019
Other	16		4			49		18
	$	21,494	$	15,938		$	42,690	$	32,331

Operating income (loss)	2,867		(23		)	6,635		2,201

Oil sales (MBbl)	191		158			380		304
Gas sales (MMcf)	894		1,029			1,839		1,983
NGL sales (MBbl)	34		29			67		50
BOE sales	374		359			753		685
Average oil sales price (per Bbl) (1)	$	90.59	$	81.66		$	90.61	$	86.36
Average gas sales price (per Mcf) (1)	$	3.51	$	1.89		$	3.26	$	2.02
Average NGL sales price (per Bbl)	$	31.46	$	37.53		$	33.12	$	40.20
Average oil equivalent price (Boe)	$	57.45	$	44.44		$	56.60	$	47.16


(1)	Revenue and average sales prices are before the impact of derivative activities.

Comparison of Three Months Ended June 30, 2013 to Three Months Ended June 30, 2012

Operating Revenue. During the three months ended June 30, 2013, operating revenue increased to $21.5 million from $15.9 million for the same period of 2012. The increase in revenue was primarily due to higher realized prices for oil and gas as well as increased sales volumes of oil and NGL. Increased prices contributed $2.9 million to revenue for the quarter ended June 30, 2013. Increase sales volumes of oil and NGL contributed $3.1 million to operating revenue for the period. Lower gas sales volumes negatively impacted earnings by $0.5 million and lower NGL prices had a $0.2 million negative impact on revenue.

Oil sales volumes increased to 191 MBbl during the quarter ended June 30, 2013 from 158 MBbl for the same period of 2012. The increase in oil sales was due to new wells brought on line offset by natural field declines and property sales. New wells brought on production contributed 68 MBbl for the three months ended June 30, 2013. Gas sales volumes decreased to 894 MMcf for the three months ended June 30, 2013 from 1,029 MMcf for the same period of 2012. The decrease in gas sales was due to natural field declines and property sales partially offset by new wells brought on line. New wells brought on line produced 71 MMcf for the three months ended June 30, 2013. NGL sales volumes increased to 34 MBbl for the three months ended June 30, 2013 from 29 MBbl for the same period of 2012. The increase in NGL sales was primarily due to increased gas production in West Texas, North Dakota and in the Eagle Ford that has a higher NGL content than our historical gas production.

Lease Operating Expenses (“LOE”). LOE for the three months ended June 30, 2013 increased to $6.2 million from $5.4 million for the same period of 2012. LOE per Boe for the three months ended June 30, 2013 was $16.49 compared to $15.01 for

the same period of 2012. The increase in LOE was primarily due to a significant increase in non-recurring LOE as well as higher overall costs. The increase per Boe was due to higher overall costs for the three months ended June 30, 2013 as compared to the same period of 2012 which were partially offset by higher sales volumes for the three months ended June 30, 2013 as compared to the same period of 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2013 increased to $1.9 million from $1.5 million for the same period of 2012, primarily as the result of higher sales volumes and higher realized prices.

General and Administrative (“G&A”) Expenses. G&A expenses, excluding stock-based compensation, were $2.1 million for the quarter ended June 30, 2013 compared to $1.7 million for the same period of 2012. The increase in G&A was primarily due to increased salaries and professional fees related to the proxy contest in 2013. G&A per Boe was $5.69 for the quarter ended June 30, 2013 compared to $4.69 for the same period of 2012. The increase per Boe was due to higher overall costs for the three months ended June 30, 2013 compared to the same period in 2012 which were partially offset by higher sales volumes for the three months ended June 30, 2013 as compared to the same period of 2012.

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 the Company's common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For each of the three months ended June 30, 2013 and 2012, stock-based compensation was approximately $0.7 million.

Depreciation, Depletion and Amortization (“DD&A”) Expenses. DD&A expense for the three months ended June 30, 2013 increased to $5.8 million from $5.4 million for the same period of 2012. The increase was primarily the result of increased production volumes for the quarter ended June 30, 2013 as compared to the same period of 2012, as well as an increase in the full cost pool in 2013 as compared to 2012. DD&A expense per Boe for the three months ended June 30, 2013 was $15.45 compared to $15.00 in 2012. The increase in per Boe DD&A was due to a higher full cost pool in 2013 as compared to 2012.

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 June 30, 2013, our net capitalized costs of oil and gas properties in the United States did not exceed the present value of our estimated proved reserves. As of June 30, 2013 the net capitalized cost of our oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $2.0 million, resulting in a write down of $2.0 million. As of June 30, 2012, the net capitalized cost of our oil and gas properties in Canada exceeded the present value of our estimated proved reserves by $1.3 million, resulting in a write down of $1.3 million.

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.

Interest Expense. Interest expense for each of the three months ended June 30, 2013 and 2012 was $1.3 million. Higher levels of debt for the three months ended June 30, 2012 were offset by lower interest rates.

losses. For the three months ended June 30, 2013, we realized a loss on our commodity derivative contracts of $0.8 million. For the three months ended June 30, 2013 we incurred an unrealized gain of $7.5 million on our commodity derivative contracts. For the three months ended June 30, 2012, we realized a gain on our derivative contracts of $0.9 million, which included a realized gain of $1.5 million on our commodity swaps and a realized loss of $0.6 million on our interest rate swap. For the three months ended June 30, 2012 we incurred an unrealized gain of $10.3 million on our derivative contracts, which included an unrealized gain of $9.8 million on our commodity swaps and an unrealized gain of $0.5 million on our interest rate swap. Our interest rate swap expired in August of 2012.

Earnings from Equity Method Investment. 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 “Earnings from equity method investment.” For the three months ended June 30, 2012, our net equity interest in the joint venture’s income was $1.3 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.

Income Tax. Income tax expense for the period ended June 30, 2013 is related to income taxes assessed as a result of an Internal Revenue Service examination of our 2009 Federal income tax return as well as various state taxes. 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. On July 23, 2013, we settled the assessment for $391,000 resulting in $81,000 being recognized as expense for the quarter ended June 30, 2013.

Comparison of Six Months Ended June 30, 2013 to Six Months Ended June 30, 2012

Operating Revenue. During the six months ended June 30, 2013, operating revenue increased to $42.7 from $32.3 million for the same period of 2012, The increase in revenue was primarily due to higher sales volumes of oil and NGL, which was offset by lower gas sales volumes. Increased sales volumes of oil and NGL contributed $7.4 million to operating revenues, while lower gas sales volumes had a negative impact of $0.5 million. Increased commodity prices for oil and gas contributed $3.7 million to revenue while lower NGL prices had a negative impact of $0.4 million for the six months ended June 30, 2013.

Oil sales volumes increased to 380 MBbl during the six months ended June 30, 2013 from 304 MBbl for the same period of 2012. The increase in oil sales was due to new wells being brought on line offset by natural field declines and property sales. New wells contributed 124 MBbl for the six months ended June 30, 2013. Gas sales volumes decreased to 1,839 MMcf for the six months ended June 30, 2013 from 1,983 MMcf for the same period of 2012. The decrease in gas sales was due to natural field declines and property sales partially offset by new wells brought on line. New wells brought onto production contributed 137 MMcf for the six months ended June 30, 2013. NGL sales volumes increased to 67 MBbl for the six months ended June 30, 2013 from 50 MBbl for the same period of 2012. The increase in NGL sales was primarily due to increased gas production in West Texas, North Dakota and Eagle Ford that has a higher NGL content than our historical gas production.

LOE. LOE for the six months ended June 30, 2013 increased to $12.6 million from $11.3 million for the same period of 2012. The increase in 2013 was due to an overall increase in the cost of services. LOE per Boe for the six months ended June 30, 2013 was $16.76 compared to $16.52 for the same period of 2012. The increase per Boe was due to higher costs which were partially offset by higher sales volumes for the six months ended June 30, 2013 as compared to the same period of 2012.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the six months ended June 30, 2013 increased to $3.8 million from $3.0 million for the same period of 2012. The increase was primarily the result of higher oil sales volumes and higher realized commodity prices for the six months ended June 30, 2013 as compared to the same period of 2012.

G&A Expenses. G&A expenses, excluding stock-based compensation, increased to $4.2 million for the first six months of 2013 from $3.1 million for the same period of 2012. The increase in G&A expense was primarily related to professional fees in connection with a proxy contest in 2013 as well as an increase in overall salaries. G&A expense per Boe was $5.56 for the six months ended June 30, 2013 compared to $4.53 for the same period of 2012. The increase per Boe was primarily due to higher costs offset by higher production volumes in the first six months of 2013 compared to the same period in 2012.

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 the Company's common stock have been granted and are valued at the date of grant and expense is recognized over their vesting period. For the six months ended June 30, 2013 and 2012, stock-based compensation was approximately $1.1 million and $1.2 million, respectively.

DD&A Expenses. DD&A expense for the six months ended June 30, 2013 increased to $12.3 million from $10.2 million for same period of 2012. The increase was primarily the result of increased production volumes, as well as an increase in the full cost pool in 2013 as compared to 2012. Our DD&A expense per Boe for the six months ended June 30, 2013 was $16.31 compared to $14.91 in 2012.

Interest Expense. Interest expense for each of the six months ended June 30, 2013 and 2012 was $2.5 million. Higher levels of debt for the six months ended June 30, 2013 were offset by lower interest rates.

(Gain) Loss 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 derivative contracts was an asset of approximately $0.4 million as of June 30, 2013. 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 six months ended June 30, 2013, we realized a loss on our commodity derivative contracts of $1.7 million. For the six months ended June 30, 2013 we incurred an unrealized gain of $6.9 million on our commodity derivative contracts. For the six months ended June 30, 2012, we realized a gain on our derivative contracts of $0.9 million, which included a realized gain of $2.0 million on our commodity swaps and a realized loss of $1.1 million on our interest rate swap. For the six months ended June 30, 2012 we incurred an unrealized gain of $9.4 million on our derivative contracts, which included an unrealized gain of $8.5 million on our commodity swaps and an unrealized gain of $0.9 million on our interest rate swap. Our interest rate swap expired in August of 2012.

Earnings from Equity Method Investment. 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 “Earnings from equity method investment.” For the six months ended June 30, 2012, our net equity interest in the joint venture's income was $2.0 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.

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;


•	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 June 30, 2013, our current assets of approximately $65.9 million exceeded our current liabilities of $62.4 million resulting in working capital of $3.5 million. This compares to a working capital deficit of $31.5 million at December 31, 2012. Current assets at June 30, 2013 primarily consist of accounts receivable of $26.9 million and assets held for sale of $34.8 million. Current liabilities at June 30, 2013 primarily consisted of trade payables of $42.0 million, revenues due third parties of $14.0 million, current portion of derivative liabilities of $2.5 million, current maturities of long-term debt of $1.6 million and accrued liabilities of $2.2 million.

Capital expenditures. Capital expenditures during the six months ended June 30, 2013 were $33.5 million compared to $35.1 million during the same period of 2012.

The table below sets forth the components of these capital expenditures:



	Six Months Ended June 30,
	2013		2012
Expenditure category:
Development	$	32,996	$	31,608
Facilities and other	470		3,508
Total	$	33,466	$	35,116

During the six months ended June 30, 2013, capital expenditures were primarily for development of our existing oil and gas properties. During the six months ended June 30, 2012, capital expenditures were primarily for development of our existing oil and gas properties 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.

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:



	Six Months Ended June 30,
	2013			2012
Net cash provided by operating activities	22,771			25,743
Net cash used in investing activities	(30,274		)	(35,116		)
Net cash provided by financing activities	7,818			9,680
Total	$	315		$	307

Operating activities during the six months ended June 30, 2013 provided $22.8 million of cash compared to providing $25.7 million in the same period of 2012. Net income plus non-cash expense items during the six months ended June 30, 2013 and 2012 and net changes in operating assets and liabilities accounted for most of these funds. In addition the monetization of our gas hedges on March 12, 2012 provided $12.4 million. Investing activities used $30.3 million during the six months ended June 30, 2013 compared to using $35.1 million for the same period of 2012. Funds used during the six months ended June 30, 2013 were expenditures for the development of our existing properties offset by property sales of $3.2 million. Funds used during the six months ended June 30, 2012 were expenditures for the development of our existing properties and the completion of the refurbishment of our drilling rig. Financing activities provided $7.8 million for the six months ended June 30, 2013 compared to providing $9.7 million for the same period in 2012. Funds provided during the six months ended June 30, 2013 were primarily borrowings under our credit facility. Funds provided during the six months ended June 30, 2012 were primarily proceeds from borrowings under our credit facility.

Future Capital Resources. Our principal sources of capital going forward are cash flows 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 second quarter of 2013, we agreed to sell certain non-core, non-operated properties for net anticipated proceeds of $34.8 million. It is anticipated that this transaction will close in August 2013. In the first and second quarter of 2013, we sold certain non-core assets for net proceeds of $3.2 million and 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.

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 June 30, 2013:



	Payments due in twelve month periods ending:
	Total		June 30, 2014		June 30, 2015-2016		June 30, 2017-2018		Thereafter
Long-term debt (1)	$	132,657	$	1,634	$	129,434	$	1,589	$	—
Interest on long-term debt (2)	8,726		4,347		4,351		28		—
Lease obligations (3)	31		31		—		—		—
Total	$	141,414	$	6,012	$	133,785	$	1,617	$	—

___________________


(1)	These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These repayments 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 cost associated with the retirement of tangible long-lived assets. At June 30, 2013, our reserve for these obligations totaled $10.1 million for which no contractual commitment exists. For additional information relating to this obligation, see Note 1 of the Notes to Condensed Consolidated Financial Statements.

Off-Balance Sheet Arrangements. At June 30, 2013, we had no existing off-balance sheet arrangements, as defined under SEC regulations, which have or are reasonably likely to have a current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At June 30, 2013, we were not engaged in any legal proceedings that were expected, individually or in the aggregate, to have a material adverse effect on the Company.

Other Obligations. We make and will continue to make substantial capital expenditures for the acquisition, development, exploration and production of oil and gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments and borrowings under our credit facilities and other sources. Given our high degree of operating control, the timing and incurrence of capital expenditures is largely within our discretion.

Long-Term Indebtedness

The following table summarizes the Company’s long-term debt:



	June 30, 2013			December 31, 2012
Credit facility	$	121,000		$	113,000
Rig loan agreement	7,000			7,000
Real estate lien note	4,657			4,758
	132,657			124,758
Less current maturities	(1,634		)	(657		)
	$	131,023		$	124,101

Credit Facility

included elsewhere in this report, our borrowing base will be reduced to $143.0 million. Unless redetermined otherwise based on new reserve and production information from the June 30, 2013 engineering report, the borrowing base will reduce to $133.0 million on October 1, 2013. We will be submitting a reserve report dated June 30, 2013 to the lenders during the third quarter of 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 $155.0 million based upon our reserve report dated December 31, 2012. 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 June 30, 2013, the interest rate on the credit facility was 3.2% based on 1-month LIBOR borrowings and level of utilization.

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 as of the last day of each quarter of not more than 4.00 to 1.00. 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 defined as the sum of 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, Raven Drilling rig loan and obligations with respect to surety bonds and derivative contracts.

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.

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.

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 was modified on April 4, 2013, reducing the interest to a fixed rate of 4.0%, effective March 13, 2013 and was payable in monthly installments of principal and interest of $33,763 based on a twenty year amortization. The note was to matures in May 2015 at which time the outstanding balance would have become due. The note is secured by a first lien deed of trust on the property and improvements. As of June 30, 2013, $4.7 million was outstanding on the note. This note was modified on July 20, 2013. The modification extended the maturity date to July 20, 2023. The note will bear interest for five years at a fixed rate of 4.25% and is payable in month installments of $34,354. Beginning August 20, 2018, the interest rate will adjust to the current prime rate plus 1.00% with a maximum rate of 7.25% .

Hedging Activities

The following table sets forth our derivative contract position as of June 30, 2013:



	Fixed Price Swap
	Oil – WTI			Oil - Brent
Contract Periods	Daily Volume (Bbl)	Swap Price (per Bbl)		Daily Volume (Bbl)	Swap Price (per Bbl)
2013	1,007	$	84.76	510	$	105.00
2014	687	$	94.16	505	$	100.56
2015	560	$	83.03	500	$	97.04
2016	963	$	84.10	—	$	—
2017	500	$	84.18	—	$	—

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. 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, the 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.

See “—Quantitative and Qualitative Disclosures about Market Risk—Derivative Instruments” for further information.

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 the 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 three and six months ended June 30, 2013. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2013, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 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 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. 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. On July 23, 2013, we settled the assessment for $391,000 resulting in $81,000 being recognized as expense for the quarter ended June 30, 2013.

Item 3. 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 indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the six months ended June 30, 2013, a 10% decline in oil and gas prices would have reduced our operating revenue, cash flow and net income by approximately $4.3 million; 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. Management has elected not to apply 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 our derivative contract position as of June 30, 2013:



	Fixed Price Swap
	Oil – WTI			Oil - Brent
Contract Periods	Daily Volume (Bbl)	Swap Price (per Bbl)		Daily Volume (Bbl)	Swap Price (per Bbl)
2013	1,007	$	84.76	510	$	105.00
2014	687	$	94.16	505	$	100.56
2015	560	$	83.03	500	$	97.04
2016	963	$	84.10	—	$	—
2017	500	$	84.18	—	$	—

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 arrangement for $100 million at a fixed rate of 3.367% originally was set to expire on August 12, 2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95% and 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 June 30, 2013, the aggregate fair market value of our commodity derivative contracts was an asset of approximately $0.4 million.

For the six months ended June 30, 2013, we recognized a realized loss of $1.7 million and an unrealized gain of $6.9 million on our commodity derivative contracts.

Interest Rate Risk

We are subject to interest rate risk associated with borrowings under our credit facility. As of June 30, 2013, we had $121.0 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 June 30, 2013, the interest rate on the credit facility was 3.2%. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.2 million on an annual basis, based on our outstanding indebtedness as of June 30, 2013.

Item 4. Controls and Procedures.

As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas’ “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that the disclosure controls and procedures were effective.

There were no changes in our internal controls over financial reporting during the six months ended June 30, 2013 covered by this report that could materially affect, or are reasonably likely to materially affect, our financial reporting.

ABRAXAS PETROLEUM CORPORATION

PART II

OTHER INFORMATION

Item 1. Legal Proceedings.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing Abraxas. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

None

Item 3. Defaults Upon Senior Securities.

None

Item 4. Mine Safety Disclosure.

Not applicable

Item 5. Other Information.

None

Item 6. Exhibits.


(a)	Exhibits



	Exhibit 31.1		Certification - Robert L.G. Watson, CEO
	Exhibit 31.2		Certification - Geoffrey R. King, CFO
	Exhibit 32.1		Certification pursuant to 18 U.S.C. Section 1350 - Robert L.G. Watson, CEO
	Exhibit 32.2		Certification pursuant to 18 U.S.C. Section 1350 - Geoffrey R. King, CFO

ABRAXAS PETROLEUM CORPORATION

SIGNATURES

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



Date: August 9, 2013		By: /s/Robert L.G. Watson
		ROBERT L.G. WATSON,
		President and Principal
		Executive Officer



Date: August 9, 2013		By: /s/Geoffrey R. King
		GEOFFREY R. KING,
		Vice President and
		Principal Financial Officer



Date: August 9, 2013		By: /s/G. William Krog, Jr.
		G. WILLIAM KROG, JR.,
		Principal Accounting Officer