XNAS:AXAS Abraxas Petroleum Corporation Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012
 
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
(Registrants 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 x    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 x        No ¨
 
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 x
 

 
The number of shares of the issuer’s common stock outstanding as of August 6, 2012 was 92,335,057 shares.
 

 
1

 

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:
 
 
·
our success in development, exploitation and exploration activities;

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

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

 
·
our ability to make planned capital expenditures;

 
·
declines in our production of oil and gas;

 
·
the availability of capital;

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

 
·
price and availability of alternative fuels;

 
·
our restrictive debt covenants;

 
·
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 equivalents are determined using the ratio of six Mcf of gas to one barrel of oil, condensate or natural gas liquids. One Mcf of gas at 1,000 British Thermal Units (“BTU”) is equivalent to one MMBtu. 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.
 
Boe” – barrels of oil equivalent.
 
MBbl” – thousand barrels.
 
MBoethousand barrels of oil equivalent.
 
Mcf” – thousand cubic feet of gas.
 

 
2

 


“MMBoe” – million barrels of oil equivalent.
 
MMBtu” – million BTU of gas.
 
MMcf” – million cubic feet of gas.
 
“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 well” 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 well.
 
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 describe 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 wereshut-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.

 
3

 
“Proved undeveloped reserves”  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 Codifications (“ASC”) 932,  “Disclosures About Oil and Gas Producing Activities.”

 
4

 


ABRAXAS PETROLEUM CORPORATION
 
FORM 10 – Q
INDEX

 
PART I
FINANCIAL INFORMATION
 
     
ITEM 1 -
Financial Statements
 
 
 
 
 
 
     
ITEM 2 -
     
ITEM 3 -
     
ITEM 4 -
     
OTHER INFORMATION
ITEM 1 -
Legal Proceedings
42
ITEM 1A -
Risk Factors
43
ITEM 2 -
Unregistered Sales of Equity Securities and Use of Proceeds
43
ITEM 3 -
Defaults Upon Senior Securities
43
ITEM 4 -
Mine Safety Disclosure
43
ITEM 5 -
Other Information
43
ITEM 6 -
Exhibits
43
 
Signatures
44
     
 


 
5

 


PART I
FINANCIAL INFORMATION

Item 1.                 Financial Statements

Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets
(in thousands)
 
   
June 30,
   
December 31,
 
   
2012
   
2011
 
   
(Unaudited)
       
Assets
           
Current assets:
           
Cash and cash equivalents
  $ 308     $  
Accounts receivable, net:
               
Joint owners
    1,801       3,354  
Oil and gas production
    8,850       8,897  
Other
    754       655  
      11,405       12,906  
                 
Derivative asset – current
    2,535       11,416  
Other current assets
    455       391  
Total current assets
    14,703       24,713  
                 
Property and equipment:
               
Oil and gas properties, full cost method of accounting:
               
Proved
    521,919       490,908  
Unproved properties excluded from depletion
    2,185       1,100  
Other property and equipmet
    37,290       33,783  
Total
    561,394       525,791  
Less accumulated depreciation, depletion, and amortization
    (358,232 )     (346,239 )
Total property and equipment – net
    203,162       179,552  
 
               
Investment in joint venture                                                                                        
    28,249       26,215  
                 
Deferred financing fees, net
    3,797       3,490  
Derivative asset – long-term
    2,640       6,412  
Other assets
    744       768  
Total assets
  $ 253,295     $ 241,150  



 

See accompanying notes to condensed consolidated financial statements (unaudited)

 
6

 

Abraxas Petroleum Corporation
Condensed Consolidated Balance Sheets (continued)
(in thousands, except share data)
 
 
 
   
June 30,
   
December 31,
 
   
2012
   
2011
 
   
(Unaudited)
       
Liabilities and Stockholders’ Equity
           
Current liabilities:
           
Accounts payable                                                                                       
  $ 18,491     $ 21,373  
Oil and gas production payable                                                                                       
    7,208       5,835  
Accrued interest                                                                                       
    151       209  
Other accrued expenses                                                                                       
    1,319       284  
Derivative liability – current                                                                                       
    4,058       11,640  
Current maturities of long-term debt                                                                                       
    186       181  
Total current liabilities                                                                                    
    31,413       39,522  
                 
Long-term debt, excluding current maturities                                                                                         
    136,664       126,258  
                 
Derivative liability – long-term                                                                                         
    1,128       4,307  
Future site restoration                                                                                         
    8,716       8,412  
Total liabilities                                                                                         
    177,921       178,499  
                 
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; 92,335,057 and 92,261,057 issued and outstanding
    923       923  
Additional paid-in capital                                                                                       
    249,738       248,480  
Accumulated deficit                                                                                       
    (174,748 )     (186,465 )
Accumulated other comprehensive loss                                                                                       
    (539 )     (287 )
Total stockholders’ equity                                                                                       
    75,374       62,651  
Total liabilities and stockholders’ equity                                                                                         
  $ 253,295     $ 241,150  



 

 
See accompanying notes to condensed consolidated financial statements (unaudited)

 
7

 

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,
 
   
2012
   
2011
   
2012
   
2011
 
Revenue:
                       
Oil and gas production revenues
  $ 15,934     $ 16,653     $ 32,313     $ 30,500  
Other
    4       3       18       4  
      15,938       16,656       32,331       30,504  
Operating costs and expenses:
                               
Lease operating expenses
    5,382       5,566       11,316       9,581  
Production taxes
    1,489       1,426       2,985       2,680  
Depreciation, depletion, and amortization
    5,380       3,780       10,218       7,210  
Impairment
    1,306             1,306        
General and administrative (including stock-based compensation of $722, $706, $1,199 and $1,069)
    2,404       2,446       4,305       5,092  
      15,961       13,218       30,130       24,563  
Operating income (loss)
    (23 )     3,438       2,201       5,941  
                                 
Other (income) expense:
                               
Interest income
    (1 )     (2 )     (2 )     (4 )
Interest expense
    1,270       1,336       2,465       2,941  
Amortization of deferred financing fee
    266       770       296       1,270  
(Gain) loss on derivative contracts  - realized
    (914 )     1,113       (866 )     1,228  
(Gain) loss on derivative contracts – unrealized
    (10,296 )     (7,959 )     (9,420 )     3,019  
Equity in income of joint venture
    (1,251 )     (769 )     (2,034 )     (1,518 )
Other
          12       42       87  
      (10,926 )     (5,499 )     (9,519 )     7,023  
Net income (loss)
  $ 10,903     $ 8,937     $ 11,720     $ (1,082 )
                                 
Net income (loss) per common share – basic
  $ 0.12     $ 0.10     $ 0.13     $ (0.01 )
                                 
Net income (loss) per common share – diluted
  $ 0.12     $ 0.10     $ 0.13     $ (0.01 )

 
 

See accompanying notes to condensed consolidated financial statements (unaudited)

 
8

 


Abraxas Petroleum Corporation
Condensed Consolidated Statements of
Other Comprehensive Income (loss)
 (Unaudited)
(in thousands)

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Consolidated net income (loss)
  $ 10,903     $ 8,937     $ 11,720     $ (1,082 )
Change in unrealized value of investments
    (34 )     (20 )     (38 )     (4 )
Foreign currency translation adjustment
    (500 )     4       (215 )     124  
Other comprehensive income (loss):
    (534 )     (16 )     (253 )     120  
Comprehensive income (loss)
  $ 10,369     $ 8,921     $ 11,467     $ (962 )




 


See accompanying notes to condensed consolidated financial statements (unaudited)

 
9

 



Abraxas Petroleum Corporation
Condensed Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
 
   
Six Months Ended
June 30,
 
   
2012
   
2011
 
Operating Activities
           
Net (loss) income
  $ 11,720     $ (1,082 )
Adjustments to reconcile net (loss) income to net
               
cash provided by operating activities:
               
Equity in income of joint venture
    (2,034 )     (1,518 )
Change in derivative fair value
    (10,472 )     3,097  
Monetization of derivative contracts
    12,364        
Depreciation, depletion, and amortization
    10,218       7,210  
Impairment
    1,306        
Amortization of deferred financing fees
    296       1,270  
Accretion of future site restoration
    235       221  
Stock-based compensation
    1,199       1,069  
Changes in operating assets and liabilities:
               
Accounts receivable                                                                                                   
    1,507       1,770  
Other                                                                                                   
    (79 )     69  
Accounts payable and accrued expenses                                                                                                   
    (517 )     (5,527 )
Net cash provided by operating activities
    25,743       6,579  
                 
Investing Activities
               
Capital expenditures, including purchases and development of properties
    (35,116 )     (25,622 )
Proceeds from sale of oil and gas properties
          8,457  
Net cash used in investing activities
    (35,116 )     (17,165 )
                 
Financing Activities
               
Proceeds from long-term borrowings
    14,500       12,000  
Payments on long-term borrowings
    (4,089 )     (58,075 )
Deferred financing fees
    (603 )     (1,527 )
Proceeds from issuance of common stock
          62,224  
Other
    (128 )     16  
Net cash provided by financing activities
    9,680       14,638  
                 
Effect of exchange rate changes on cash
    1        
Increase in cash
    308       4,052  
Cash and equivalents, at beginning of period
          99  
Cash and equivalents, at end of period
  $ 308     $ 4,151  
                 
Supplemental disclosure of cash flow information:
               
Interest paid
  $ 2,289     $ 2,968  
 
See accompanying notes to condensed consolidated financial statements (unaudited)

 
10

 

Abraxas Petroleum Corporation
Notes to Condensed Consolidated Financial Statements
(Unaudited)
(tabular amounts in thousands, except per share 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, 2011 filed with the SEC on March 15, 2012. 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 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 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, 2012 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, 2011.

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, Option Plans and Warrants
 
Stock Options
 
The Company currently utilizes a standard option-pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors.
 

 
11

 


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,
 
2012
   
2011
   
2012
   
2011
 
$ 599     $ 599     $ 944     $ 866  

 
The following table summarizes the Company’s stock option activity for the six months ended June 30, 2012:
 
   
 
Number
of
Shares
   
Weighted
Average
 Option
 Exercise
 Price Per
 Share
   
Weighted
 Average
Grant
Date Fair
 Value
Per Share
   
Aggregate
Intrinsic
Value
 
Outstanding, December 31, 2011
    4,756     $ 2.61     $ 1.85     $ 8,214  
Granted                                              
    408     $ 3.51     $ 2.56       1,044  
Exercised                                              
    (67 )   $ 0.89     $ 0.43       (29 )
Outstanding, June 30, 2012                                              
    5,097     $ 2.70     $ 1.81     $ 9,229  

The following table shows the weighted average assumptions used in the Black-Scholes calculation of the fair value of stock option grants for the six months ended June 30, 2012:
 
Expected dividend yield                                                                                                
    0  
%
Volatility                                                                                                
    80.75  
%
Risk free interest rate                                                                                                
    1.36  
%
Expected life                                                                                                
    7.00  
Years
Fair value of options granted (in thousands)                                                                                                
  $ 1,044    
Weighted average grant date fair value per share of options granted
  $ 2.56    

 Additional information related to stock options at June 30, 2012 and December 31, 2011 is as follows:
 
   
June 30,
   
December 31,
 
   
2012
   
2011
 
Options exercisable                                                                                    
    3,076       2,512  

As of June 30, 2012, there was approximately $3.2 million of unamortized compensation expense related to outstanding stock options that will be recognized in 2012 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.

 
12

 


The following table summarizes the Company’s restricted stock activity for the six months ended June 30, 2012:
 
   
Number
of
Shares
   
Weighted
Average
Grant Date
Fair Value
Per Share
 
Unvested, December 31, 2011                                                 
    630     $ 3.03  
Granted                                                 
    7       3.16  
Vested/Released                                                 
    (111 )     1.86  
Forfeited                                                 
           
Unvested, June 30, 2012                                                 
    526     $ 3.28  
 
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,
 
2012
   
2011
   
2012
   
2011
$
123
 
$
107
 
$
255
 
$
203

 
As of June 30, 2012, there was approximately $1.2 million of unamortized compensation expense relating to outstanding restricted shares that will be recognized in 2012 through 2016.
 
Warrants
 
  On May 25, 2007, the Company entered into a Securities Purchase Agreement with certain accredited investors pursuant to which the Company issued warrants to purchase 1,174,938 shares of common stock. The warrants expired on May 25, 2012.
 
Oil and Gas Properties
 
  The Company follows the full cost method of accounting for oil and gas properties.  Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-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 in unusual circumstances. 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.

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.

 
13

 


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, 2012 and the year ended December 31, 2011:
 
   
June 30,
2012
   
December 31, 2011
 
Beginning asset retirement obligation
  $ 8,412     $ 7,734  
Settled
    (210 )     (83 )
Revisions
    123       (9 )
New wells placed on production and other
    156       318  
Accretion expense
    235       452  
Ending asset retirement obligation
  $ 8,716     $ 8,412  
 
Working Capital (Deficit)
 
At June 30, 2012, our current liabilities of approximately $31.4 million exceeded our current assets of $14.7 million resulting in a working capital deficit of $16.7 million. This compares to a working capital deficit of $14.8 million at December 31, 2011. Current liabilities at June 30, 2012 primarily consisted of the current portion of derivative liabilities of $4.1 million, trade payables of $18.5 million and revenues due third parties of $7.2 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. Rock Oil committed to contribute an additional $50.0 million to Blue Eagle and upon full funding (should it occur), Abraxas Petroleum would own a 25% equity interest and Rock Oil would own a 75% equity interest in Blue Eagle.
 
Blue Eagle’s subject area encompasses 12 counties across the Eagle Ford Shale play. Abraxas Petroleum operates the wells owned by Blue Eagle and Rock Oil and Abraxas jointly manage the day-to-day business affairs of Blue Eagle.   Robert L.G. Watson, our President and CEO, serves as one of the three members of the Board of Managers of Blue Eagle.
 
As of June 30, 2012, Rock Oil has contributed $47.0 million to Blue Eagle and we own a non-controlling 34.7% interest in the joint venture. We account for the joint venture under the equity method of accounting. 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 is also recorded as equity investment income (loss) in “Equity in (gain) loss of joint venture.” For the three and six months ended June 30, 2012 and 2011 we reported a gain of $1.3 million, $2.0 million, $769,000 and $1.5 million, respectively, related to Blue Eagle.
 

 
14

 


The following is condensed financial data from Blue Eagle’s June 30, 2012 and December 31, 2011 financial statements:

 
Balance Sheets:
 
As of
June 30,
2012
   
As of December 31, 2011
 
Assets:
           
Current assets
  $ 7,089     $ 11,910  
Oil and gas properties
    75,875       66,663  
Other assets
    31       36  
Total assets
  $ 82,995     $ 78,609  
                 
Liabilities and Members’ Capital:
               
Current liabilities
  $ 1,592     $ 3,070  
Other liabilities
    47       41  
Members’ capital
    81,356       75,498  
Total liabilities and members’ capital
  $ 82,995     $ 78,609  


   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
                         
Revenue:
  $ 5,946     $ 3,758     $ 9,767     $ 6,855  
Operating expenses
    2,899       1,544       5,027       3,148  
Other (income) expense
          (4 )     (1 )     (9 )
Net income:
  $ 3,047     $ 2,218     $ 4,741     $ 3,716  
 
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, 2012, there were no current or deferred income tax expense or benefit due to losses and/or loss carryforwards and valuation allowances which have been recorded against such benefits.
 
The Company accounts for uncertain tax positions under provisions ASC 740-10.  This ASC did not have any effect on the Company’s financial position or results of operations for the six months ended June 30, 2012 and 2011.  The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2012, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years 2001 through 2011 remain open to examination by the tax jurisdictions to which the Company is subject. The Company and Abraxas Energy Partners, L.P., which was merged into a wholly owned subsidiary of Abraxas, have undergone 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 proposed adjustment of $686,000. The Company does not agree with the findings and intends to aggressively appeal the proposed adjustment; however, no assurances can be made that such appeals will be successful.
 
At December 31, 2011, we had, subject to the limitation discussed below, $150.2 million of net operating loss carryforwards for U.S. tax purposes and $8.7 million of net operating loss carryforwards for Canadian tax purposes. The U.S. loss carryforward will expire in varying amounts through 2031 and the Canadian loss carryforward will expire in 2031, if not utilized.
 

 
15

 


 Note 4. Long-Term Debt

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

   
June 30, 2012
   
December 31, 2011
 
Credit facility                                                                                       
  $ 125,000     $ 115,000  
Rig loan agreement                                                                                       
    7,000       6,500  
Real estate lien note                                                                                       
    4,850       4,939  
      136,850       126,439  
Less current maturities                                                                                       
    (186 )     (181 )
    $ 136,664     $ 126,258  

Credit Facility

On June 29, 2012, we entered into an amendment to our 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, 2012, $125.0 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. The borrowing base is currently $140.0 million. This amount will remain in effect until the earliest of (a) the sale of our interest in Blue Eagle, (b) the date on which the borrowing base is redetermined based upon our internal engineering report as of June 30, 2012, and (c) October 31, 2012. 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 of $140.0 million was determined based upon our reserve report dated December 31, 2011. 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, 2012, the interest rate on the credit facility was 3.50% based on 1-month LIBOR borrowings and level of utilization.

Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2015. Interest is payable quarterly on reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.

Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets, other than Raven Drilling. Neither the properties owned by Blue Eagle nor our investment in Blue Eagle are used to secure our obligations under the credit facility.

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 and until the earlier of the date we sell our interest in Blue Eagle or December 31, 2012, liquidity (defined as sum of our borrowing base availability, liquid investments and unrestricted cash) of $7.5 million. 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 any accounts receivable from Blue Eagle 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, and any accounts payable to Blue Eagle.  The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense
 
 
 
16

 
for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of ASC 815 and ASC 410-20; provided that net income shall be adjusted to negate the effect of non-cash gain or loss attributable to Blue Eagle. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date.  For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, and obligations with respect to surety bonds and hedge arrangements.
 
As of June 30, 2012, the interest coverage ratio was 7.38 to 1.00, the total debt to EBITDAX ratio was 2.85 to 1.00 and our current ratio was 1.09 to 1.0 and we had liquidity of $15.3 million.
 
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.
 
 
In addition, until the earlier of the end of 2012 or the date that our interest in Blue Eagle is sold, we are required to limit our capital expenditures for drilling / completion expenditures to $10.0 million per quarter, subject to certain pull-back and carry-over provisions; however, if we maintain a borrowing base availability percentage (defined as the amount available under the credit facility divided by the amount borrowed under the credit facility) of not less than 15% at June 30, 2012 and 10% at September 30, 2012 and December 31, 2012, capital expenditures in the ordinary course of business are not subject to the limitation. At June 30, 2012, our borrowing base availability percentage was 12% and, as a result, we will be subject to this limitation during the third quarter ended September 30, 2012, excluding $7.2 million for the acquisition of producing properties for the quarter ending September 30, 2012. The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities.
 
Rig Loan Agreement
 
On September 19, 2011, Raven Drilling entered into a rig loan agreement with RBS Asset Finance, Inc. to finance the costs of purchasing and refurbishing an Oilwell 2000 hp diesel electric drilling rig (the “Collateral”). The rig loan agreement provided for interim borrowings payable to Raven Drilling until the final amount of the loan was determined. 

On February 14, 2012, Raven Drilling finalized the note with respect to the rig loan agreement.  The principal amount of the note is $7.0 million and bears interest at 4.26%, which equates to the four-year interest swap rate plus 3.50% on the date of closing.  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, 2012, $7.0 million was outstanding under the rig loan agreement.

The Company has guaranteed Raven Drilling’s obligations under the rig loan agreement and associated note.  Obligations under the rig loan agreement are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in the Collateral.

 
17

 
 
Real Estate Lien Note

On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to serve as its corporate headquarters. This note was refinanced in November 2008.  The note bears interest at a fixed rate of 5.25% and is payable in monthly installments of principal and interest of $36,652 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of June 30, 2012, $4.9 million was outstanding on the note.
 
Note 5.  Income (Loss) Per Share
 
The following table sets forth the computation of basic and diluted income (loss) per share:
 
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Numerator:
                       
Net income (loss)
  $ 10,903     $ 8,937     $ 11,720     $ (1,082 )
Denominator:
                               
Denominator for basic income (loss) per share -
                               
Weighted-average shares
    91,808       91,409       91,775       88,653  
                                 
Effect of dilutive securities:
                               
Stock options and warrants
    1,455       2,097       1,673        
                                 
Denominator for diluted income (loss) per share - adjusted weighted-average shares and assumed conversions
    93,263       93,506       93,448       88,653  
                                 
Net income (loss) per common share – basic
  $ 0.12     $ 0.10     $ 0.13     $ (0.01 )
                                 
Net income (loss) per common share – diluted
  $ 0.12     $ 0.10     $ 0.13     $ (0.01 )

For the six months ended June 30, 2011, none of the shares issuable in connection with stock options or warrants are included in diluted shares. Inclusion of these shares would be antidilutive due to the loss incurred in the period. Had there not been a loss for the period, dilutive shares would have been 2,328 shares for the six months ended June 30, 2011.

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, 2012:

   
Fixed Price Swap
 
   
Oil
 
Contract Periods
 
Daily Volume
 (Bbl)
   
Swap Price
 (per Bbl)
 
2012 (July – September)
    1,176     $ 78.23  
2012 (October – December)
    1,509     $ 79.22  
2013
    1,327     $ 86.70  
2014 (January – August)
    1,173     $ 95.60  
2014 (September – December)
    333     $ 82.72  

 
18

 


At June 30, 2012, the aggregate fair value of our commodity derivative contracts was an asset of approximately $591,000.

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 following table illustrates the impact of derivative contracts on the Company’s balance sheet:
 
Fair Value of Derivative Instruments as of June 30, 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
  $ 2,535  
Derivatives – current
  $ 3,456  
Interest rate derivatives
Derivatives – current
     
Derivatives – current
    602  
Commodity price derivatives
Derivatives - noncurrent
    2,640  
Derivatives - noncurrent
    1,128  
      $ 5,175       $ 5,186  

 
Fair Value of Derivative Instruments as of December 31, 2011
 
 
Asset Derivatives
 
Liability Derivatives
 
Derivatives not designated as hedging instruments
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
Commodity price derivatives
Derivatives – current
  $ 11,416  
Derivatives – current
  $ 10,094  
Interest rate derivatives
Derivatives – current
     
Derivatives – current
    1,546  
Commodity price derivatives
Derivatives - noncurrent
    6,412  
Derivatives - noncurrent
    4,307  
      $ 17,828       $ 15,947  

Gains and losses from derivative activities are reflected as “Loss (gain) 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 carrying value of the balances outstanding under the credit facility, the rig loan agreement and the real estate lien note approximates fair value. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at June 30, 2012 and December 31, 2011 due to their short term
 
 
 
19

 
 maturities. The following tables set forth information about the Company’s assets and liabilities measured at fair value, as of June 30, 2012 and December 31, 2011, and indicates the fair value hierarchy of the valuation methodology techniques utilized by the Company to determine such fair value.

   
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,
2012
 
Assets
                       
Investment in common stock
  $ 67     $     $     $ 67  
NYMEX Fixed Price Derivative contracts
          5,175             5,175  
Total Assets
  $ 67     $ 5,175     $     $ 5,242  
Liabilities
                               
NYMEX Fixed Price Derivative contracts
  $     $ 4,584     $     $ 4,584  
Interest Rate Swaps
                602       602  
Total Liabilities
  $     $ 4,584     $ 602     $ 5,186  


   
Quoted Prices
 in Active
Markets for
Identical
Assets
(Level 1)
   
Significant
Other
Observable
Inputs
 (Level 2)
   
 
 
Significant
Unobservable
Inputs (Level 3)
   
 
 
Balance as of
December 31,
2011
 
Assets:
                       
Investment in common stock
  $ 104     $     $     $ 104  
NYMEX Fixed Price Derivative contracts
          17,828             17,828  
Total Assets
  $ 104     $ 17,828     $     $ 17,932  
Liabilities:
                               
NYMEX Fixed Price Derivative contracts
  $     $ 14,401     $     $ 14,401  
Interest Rate Swaps
                1,546       1,546  
Total Liabilities
  $     $ 14,401     $ 1,546     $ 15,947  

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, 2012 and December 31, 2011 in U.S. dollars. Accordingly, this investment is characterized as Level 1.

The Company’s derivative contracts consist of NYMEX-based fixed price commodity swaps and interest rate swaps. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded for the underlying commodity and commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2.

In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The interest rate swap arrangement for $100 million at a
 
 
20

 
 fixed rate of 3.367% originally was set to expire on August 12, 2010.  The 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. As there are no observable market parameters for this type of swap, these derivative contracts are classified as Level 3.
 

Additional information for the Company’s recurring fair value measurements using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2012 are as follows:

   
Derivative Assets
(Liabilities) - net
 
   
Three Months Ended
 June 30, 2012
   
Six Months Ended
June 30, 2012
 
Balance beginning of period
  $ (1,106 )   $ (1,546 )
Total realized and unrealized losses included in change in net liability
    (79 )     (214 )
Settlements during the period
    583       1,158  
Balance June 30, 2012
  $ (602 )   $ (602 )

The Company relies on the counter-parties valuation of this derivative instrument and does not develop quantitative information about the significant unobservable inputs used in the fair value measurement categorized within Level 3 of the fair value hierarchy. A significant change in the LIBOR strip could impact the fair value of this derivative instrument.

Note 8. Business Segments
 
The following table provides the Company’s geographic operating segment data for the three and six months ended June 30, 2012 and 2011:

   
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  
Equity in income of joint venture
                (1,251 )     (1,251 )
(Gain) loss on derivative contracts
                (11,210 )     (11,210 )
Other
                       
      11,918       2,246       (9,129 )     5,035  
Net income (loss)
  $ 3,194     $ (1,424 )   $ 9,133     $ 10,903  


 
21

 


   
Three Months Ended June 30, 2011
 
   
U.S
   
Canada
   
Corporate
   
Total
 
Revenues:
                       
Oil and gas production
  $ 16,136     $ 517     $     $ 16,653  
Other
                3       3  
      16,136       517       3       16,656  
                                 
Expenses (income):
                               
Lease operating
    5,375       191             5,566  
Production taxes
    1,426                   1,426  
Depreciation, depletion and amortization
    3,488       229       63       3,780  
General and administrative
    395       159       1,892       2,446  
Net interest
    220       1       1,113       1,334  
Amortization of deferred financing fees
                770       770  
Equity in income of joint venture
                (769 )     (769 )
Gain on derivative contracts
                (6,846 )     (6,846 )
Other
                12       12  
      10,904       580       (3,765 )     7,719  
Net income (loss)
  $ 5,232     $ (63 )   $ 3,768     $ 8,937  

   
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 (income):
                               
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  
Equity in income of joint venture
                (2,034 )     (2,034 )
Gain on derivative contracts
                (10,286 )     (10,286 )
Other
                42       42  
      24,119       2,814       (6,322 )     20,611  
Net income (loss)
  $ 6,868     $ (1,488 )   $ 6,340     $ 11,720  


 
22

 




   
Six Months Ended June 30, 2011
 
   
U.S
   
Canada
   
Corporate
   
Total
 
Revenues:
                       
Oil and gas production
  $ 29,794     $ 706     $     $ 30,500  
Other
                4       4  
      29,794       706       4       30,504  
                                 
Expenses (income):
                               
Lease operating
    9,255       326             9,581  
Production taxes
    2,680                   2,680  
Depreciation, depletion and amortization
    6,761       324       125       7,210  
General and administrative
    911       378       3,803       5,092  
Net interest
    220       1       2,716       2,937  
Amortization of deferred financing fees
                1,270       1,270  
Equity in income of joint venture
                (1,518 )     (1,518 )
Loss on derivative contracts
                4,247       4,247  
Other
                87       87  
      19,827       1,029       10,730       31,586  
Net income (loss)
  $ 9,967     $ (323 )   $ (10,726 )   $ (1,082 )

The following table provides the Company’s geographic asset data as of June 30, 2012 and December 31, 2011:

Segment Assets:
 
June 30,
2012
   
December 31,
2011
 
United States                                                           
  $ 185,355     $ 167,739  
Canada                                                           
    24,346       19,379  
Corporate                                                           
    43,594       54,032  
    $ 253,295     $ 241,150  

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, 2012, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on its operations.
 
Note 10. Subsequent Events
 
On August 3, 2012, the Company entered into a letter of intent to dissolve its Blue Eagle (Eagle Ford) joint venture, Blue Eagle Energy LLC.  Abraxas and its joint venture partner will split the assets with Abraxas retaining a 100 percent interest in the Eagle Ford and shallower rights in Jourdanton, Atascosa County (4,401 net acres), a 100 percent interest in Yoakum, DeWitt County (1,868 net acres), a 25 percent interest in WyCross, McMullen County (695 net acres), and a 25 percent interest in Nordheim, DeWitt County (944 net acres).  The producing wells are currently producing 205 barrels of oil equivalent per day (62 percent oil and 11 percent NGL) net to the interest retained by Abraxas.  The proved reserves attributable to the Abraxas interests are approximately 2.4 million barrels of oil equivalent (27 percent oil and 25 percent NGL).  The probable reserves attributable to the Abraxas interests are 3.7 million barrels of oil equivalent (54 percent oil and 15 percent NGL).  Abraxas will receive a $7 million cash payment along with approximately 35 percent of the working capital in Blue Eagle.

On July 31, 2012 the Company closed on a transaction with a large independent to acquire their interests in jointly owned properties in Ward County, West Texas for $7.2 million less closing adjustments.  The transaction adds approximately 240 barrels of oil equivalent production per day and proved developed producing reserves of approximately 1.2 million barrels of oil equivalent.  Production and reserves are approximately 95 percent natural gas.  Net acres acquired are approximately 2,345.
 
 

 
23

 

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, 2011 filed with the SEC on March 15, 2012.

The results of operations set forth below do not include our interest in the operations of Blue Eagle.

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, 2011.

General
 
We are an independent energy company engaged in the 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 three of the last five years, we cannot assure you that we can achieve positive net income in the future. 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. 

 
24

 


During the six months ended June 30, 2012, the New York Mercantile (NYMEX) price for West Texas Intermediate crude oil (WTI) averaged $98.13 per barrel as compared to $98.44 per barrel during the six months ended June 30, 2011. NYMEX Henry Hub spot prices for gas averaged $2.36 per MMBtu for the six months ended June 30, 2012 compared to $4.27 for the same period of 2011. Prices closed on June 30, 2012 at $84.96 per Bbl of oil and $2.74 per MMBtu of gas, compared to closing on June 30, 2011 at $95.42 per Bbl of oil and $4.33 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 tables sets forth our average differentials for the three and six months ended June 30, 2012 and 2011:
 
   
Oil - WTI
 
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Average realized price (1)
  $ 81.66     $ 96.77     $ 86.36     $ 91.21  
Average NYMEX price
  $ 93.34     $ 102.34     $ 98.13     $ 98.44  
Differential
  $ (11.68 )   $ (5.57 )   $ (11.77 )   $ (7.23 )
 

   
Gas – Henry Hub
 
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2012
   
2011
   
2012
   
2011
 
Average realized price (1)
  $ 1.89     $ 3.88     $ 2.02     $ 3.75  
Average NYMEX price
  $ 2.29     $ 4.36     $ 2.36     $ 4.27  
Differential
  $ (0.40 )   $ (0.48 )   $ (0.34 )   $ (0.52 )
 
(1)  
excluding 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.
 
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, 2012, we recognized a realized gain of $2.0 million and an unrealized gain of $8.5 million on our commodity swaps. For the six months ended June 30, 2011, we incurred a realized loss of $65,000 and an unrealized loss of $3.7 million. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules.
 

 
25

 


The following table sets forth our derivative contracts at June 30, 2012:
 
   
Fixed Price Swap
 
   
Oil
 
Contract Periods
 
Daily Volume (Bbl)
   
Swap Price (per Bbl)
 
2012 (July – September)
    1,176     $ 78.23  
2012 (October – December)
    1,509     $ 79.22  
2013
    1,327     $ 86.70  
2014 (January – August)
    1,173     $ 95.60  
2014 (September – December)
    333     $ 82.72  

 

At June 30, 2012, the aggregate fair value of our commodity derivative contracts was an asset of approximately $591,000.

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, 2011 (which did not include any Blue Eagle reserves), the average annual estimated decline rate for our net proved developed producing reserves is 14% 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 $35.1 million during the six months ended June 30, 2012. We have a capital expenditure budget for 2012 of approximately $70.0 million.Until the earlier of the end of 2012 or until our interest in Blue Eagle is sold, we are required to limit our capital expenditures for drilling and completion expenditures to $10.0 million per quarter, subject to certain pull-back and carry-over provisions;, however, if we maintain a borrowing base availability percentage (defined as the amount available under the credit facility divided by the amount borrowed under the credit facility) of not less than 15% at June 30, 2012 and 10% at September 30, 2012 and December 31, 2012, our capital expenditures in the ordinary course of business are unlimited. At June 30, 2012, our borrowing base availability percentage was 12% and, as a result, we will be subject to this limitation during the quarter ended September 30, 2012, excluding the $7.2 million producing property acquisition that closed on July 31, 2012.
 
Approximately 75% of the 2012 budget will be spent on unconventional horizontal oil wells in the Bakken/Three Forks and Niobrara/Turner plays in the Rocky Mountain region of the United States and the other 25% will target conventional oil plays in the Permian Basin and in the province of Alberta, Canada.  The 2012 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.
 
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, 2012, we had $15.0 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 large inventory of drilling projects position us for future growth. At December 31, 2011, we operated properties
 
 
26

 
accounting for approximately 94% 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.
 
Our future 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 properties and our Proved reserves will decline as our reserves are produced unless we acquire or develop additional properties containing Proved 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 43% of our estimated Proved reserves at December 31, 2011 were undeveloped. By their nature, estimates of Proved 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
 
Rocky Mountain-North Dakota/Montana

·  
In McKenzie County, the Company owned drilling rig is preparing to spud the Jore Federal 2-11 3H in which Abraxas owns an approximate 76 percent working interest, after successfully drilling the Ravin 26-35 2H and Ravin 26-35 3H to total depths in excess of 21,000 feet including approximate 10,000 foot laterals.  Abraxas owns an approximate 49 percent working interest in the Ravin wells.  These three wells, all located on the same pad, are scheduled to be fraced in late September or early October, with production shortly thereafter.

·  
Elsewhere in the Bakken/Three Forks play, during the second quarter of 2012, 5 gross (.08 net) non operated wells came on line and at quarter end 1 gross (.01 net) non operated well was completing.  Additionally, we have recently agreed to participate in 5 gross (.11 net) wells that have yet to spud.

Rocky Mountain – Wyoming

·  
In Campbell County, the Hedgehog State 16-2H, a horizontal well in the Turner formation in which we own a 100 percent working interest continues to produce approximately 395 BOEPD (35 percent oil and 13 percent natural gas liquids) with little decline.

West Texas – Spires Ranch

·  
In a continuation of the horizontal Strawn Lime play initiated by Abraxas several years ago, the Spires Ranch 89 – 1H well is currently drilling the lateral at a measured depth of 7,424 feet toward an objective depth of 10,400 feet including a 3,400 foot lateral section.  Abraxas owns a 100 percent working interest in the approximate 5,500 acres Spires Ranch lease.

Canada – Pekisko

·  
In Alberta, Canada, Canadian Abraxas has six horizontal Pekisko wells on production, although two of which have yet to be fracture stimulated.  Due to the recent steep decline on oil prices, the decision was made to postpone significant additional capital expenditures until oil prices improve in the field.
 
Subsequent Events
 
On August 3, 2012, The Company entered into a letter of intent to dissolve its Eagle Ford joint venture, Blue Eagle Energy LLC.  Abraxas and its joint venture partner will split the assets with Abraxas retaining a 100 percent interest in the Eagle Ford and shallower rights in Jourdanton, Atascosa County (4,401 net acres), a 100 percent interest in Yoakum, DeWitt County (1,868 net acres), a 25 percent interest in WyCross, McMullen County (695 net acres), and a 25 percent interest in Nordheim, DeWitt County (944 net acres).  The producing wells are currently producing 205 barrels of oil equivalent per day (62
 
 
27

 
 percent oil and 11 percent NGL) net to the interest retained by Abraxas.  The proved reserves attributable to the Abraxas interests are approximately 2.4 million barrels of oil equivalent (27 percent oil and 25 percent NGL).  The probable reserves attributable to the Abraxas interests are 3.7 million barrels of oil equivalent (54 percent oil and 15 percent NGL).  Abraxas will receive a $7 million cash payment along with our share of the working capital in Blue Eagle.. Abraxas, as operator, and its working interest partner will commence a ten well drilling program utilizing one rig in the WyCross area in the near future.  The first well drilled at WyCross, the Abraxas Cobra #1H has produced over 98,000 barrels of oil equivalent since going on production in March of 2012 and is currently flowing approximately 430 barrels of oil equivalent per day (86 percent oil and 5 percent NGL).
 
On July 31, 2012 the Company closed on a transaction with a large independent to acquire their interests in jointly owned properties in Ward County, West Texas for $7.2 million less closing adjustments.  The transaction adds approximately 240 barrels of oil equivalent production per day and proved developed producing reserves of approximately 1.2 million barrels of oil equivalent.  Production and reserves are approximately 95 percent natural gas.  Net acres acquired are approximately 2,345.

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,
 
   
2012
   
2011
   
2012
   
2011
 
Operating revenue:
                       
Oil sales (1)
  $ 12,897     $ 12,278     $ 26,289     $ 22,163  
Gas sales (1)
    1,943       4,101       4,005       7,873  
NGL sales
    1,094       274       2,019       464  
Other
    4       3       18       4  
    $ 15,938     $ 16,656     $ 32,331     $ 30,504  
                                 
Operating income (loss)
  $ (23 )   $ 3,438     $ 2,201