ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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r
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Nevada
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74-2584033
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(State or Other Jurisdiction of
Incorporation or Organization)
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(I.R.S. Employer Identification Number)
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18803 Meisner Drive
San Antonio, TX 78258
(Address of principal executive offices)
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Title of each class:
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Name of each exchange on which registered:
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Common Stock, par value $.01 per share
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The NASDAQ Stock Market, LLC
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Large accelerated filer ⃞
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Accelerated filer
x
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Non-accelerated filer ⃞ (Do not check if a smaller reporting company)
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Smaller reporting company ⃞
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Document
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Parts Into Which Incorporated
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Portions of the registrant’s Proxy Statement relating to the 2016 Annual Meeting of Stockholders to be held on May 10, 2016.
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Part III
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Page
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Part I
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Part II
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Part III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Part IV
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Item 15.
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•
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the prices we receive for our production and the effectiveness of our hedging activities;
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•
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our success in development, exploitation and exploration activities;
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•
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declines in our production of oil and gas;
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•
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our restrictive debt covenants;
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•
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political and economic conditions in oil producing countries, especially those in the Middle East;
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•
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price and availability of alternative fuels;
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•
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our ability to procure services and equipment for our drilling and completion activities;
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•
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our acquisition and divestiture activities;
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•
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weather conditions and events;
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•
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the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
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•
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other factors discussed elsewhere in this report
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Estimated Net Proved Reserves
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Net
Production
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|||||||||||
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Gross
Producing
Wells
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Average
Working
Interest
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Total Net Acres
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(MBoe)
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%
Oil/NGL
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(MBoe)
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%
Oil/NGL
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|||||||
Rocky Mountain
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788
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11.79
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%
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44,013
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29,476
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83.9
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%
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1,324.4
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85.6
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%
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Permian Basin
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240
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|
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64.22
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%
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28,370
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10,106
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40.3
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%
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293.6
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44.7
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%
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Onshore Gulf Coast
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78
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82.71
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%
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14,141
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3,608
|
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52.5
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%
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562.8
|
|
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73.5
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%
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Total United States
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1,106
|
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28.17
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%
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86,524
|
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43,190
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71.0
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%
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2,180.8
|
|
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77.0
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%
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•
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the location of wells;
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•
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the method of drilling and casing wells;
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•
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the flaring of gas;
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•
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the method of completing and fracture stimulating wells;
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•
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the surface use and restoration of properties upon which wells are drilled;
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•
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the plugging and abandoning of wells; and
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•
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the notice to surface owners and other third parties.
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•
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require the acquisition of a permit or other authorization before construction or drilling commences;
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•
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impose design and construction requirements on facilities in conjunction with oil and gas operations, including the construction of pollution control devices;
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•
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require protective measures to prevent drilling fluids from coming into contact with ground water;
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•
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restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and gas processing activities;
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•
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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and areas inhabited by threatened or endangered species and other protected areas;
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•
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require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;
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•
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require disclosure of chemicals injected into wells in conjunction with hydraulic fracturing operations;
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•
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restrict injection of liquids into subsurface strata that may contaminate groundwater;
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•
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restrict the availability of water necessary for hydraulic fracturing operations;
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•
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impose substantial penalties for violations of environmental rules or pollution resulting from our operations; and
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•
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curtail production in association with exceeding gas flaring limits.
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•
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reducing the amount of oil, gas and NGL that we can produce economically;
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•
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reducing the borrowing base of our credit facility;
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•
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limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;
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•
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reducing our revenues, operating cash flows and profitability;
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•
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causing us to further decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production of oil, gas and NGL; and
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•
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reducing the carrying value of our properties, resulting in additional noncash write-downs.
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•
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the level of demand;
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•
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domestic and global supplies of oil, NGL and gas;
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•
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the price and quantity of imported and exported oil, NGL and gas;
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•
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the actions of other oil exporting nations
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•
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weather conditions and changes in weather patterns
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•
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the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities, storage facilities and refining facilities;
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•
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worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions, competition for markets and political initiatives disfavoring fossil fuels;
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•
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the price and availability of, and demand for, competing energy sources, including alternative energy sources;
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•
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the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of oil, gas and related commodities;
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•
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the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others, and;
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•
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the effect of worldwide energy conservation measures.
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•
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a reduction in reserve estimates;
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•
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lower commodity prices or production;
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•
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inability to drill or unfavorable drilling results;
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•
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increased operating and/or capital costs;
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•
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the lenders’ inability to agree to an adequate borrowing base; or
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•
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adverse changes in the lenders’ practices (including required regulatory changes) regarding estimation of reserves.
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•
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affecting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes which may be impaired or not available on favorable terms or at all;
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•
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covenants contained in our credit facility and future debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including future business opportunities;
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•
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we may need a substantial portion of our cash flow from operations to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and
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•
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our level of indebtedness will make us more vulnerable to competitive pressures if there is a downturn in our business or the economy in general, than our competitors with less debt.
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•
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incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock;
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•
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transfer or sell assets;
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•
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create liens on assets;
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•
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pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions;
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•
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engage in transactions with affiliates;
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•
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guarantee other indebtedness;
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•
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make any change in the principal nature of our business;
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•
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permit a change of control; or
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•
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consolidate, merge or transfer all or substantially all of our assets.
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•
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highly volatile oil and gas prices;
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•
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our production being less than expected; or
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•
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a counterparty to one of our hedging transactions defaulting on its contractual obligations.
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•
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prevailing and anticipated prices for oil and gas;
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•
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the availability and costs of drilling and service equipment and crews;
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•
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economic and industry conditions at the time of drilling;
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•
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the availability of sufficient capital resources;
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•
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the results of our exploitation efforts;
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•
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the acquisition, review and interpretation of seismic data;
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•
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our ability to obtain permits for and to access drilling locations;
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•
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continuous drilling obligations; and
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•
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lease expirations.
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•
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the operator could refuse to initiate exploitation or development projects and if we proceed with any of those projects, we may not receive any funding from the operator with respect to that project;
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•
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the operator may initiate exploitation or development projects on a different schedule than we would prefer;
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•
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the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects and thus, not participate in the associated revenue stream; and
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•
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the operator may not have sufficient expertise or resources.
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•
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unexpected drilling conditions;
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•
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facility or equipment failure or accidents;
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•
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adverse weather conditions;
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•
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title problems;
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•
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unusual or unexpected geological formations;
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•
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fires, blowouts and explosions; and
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•
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uncontrollable pressures or flows of oil or gas or well fluids.
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•
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environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, shoreline contamination, underground migration and surface spills or mishandling of chemical additives;
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•
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abnormally pressured formations;
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•
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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•
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leaks of gas, oil, condensate, NGL and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment or processing or other facilities in the Company’s operations or at delivery points to third parties;
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•
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fires and explosions;
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•
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personal injuries and death;
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•
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regulatory investigations and penalties; and
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•
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natural disasters.
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•
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limiting oil and gas development;
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•
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reducing access to federal and state owned lands;
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•
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delaying or canceling certain projects such as offshore drilling, shale development, and pipeline construction;
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•
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limiting or banning the use of hydraulic fracturing;
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•
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denying air-quality permits for drilling; and
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•
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advocating for increased regulations on shale drilling and hydraulic fracturing.
|
•
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blocked development;
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•
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denial or delay of drilling permits;
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•
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shortening of lease terms or reduction in lease size;
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•
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restrictions on installation or operation of gathering or processing facilities;
|
•
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restrictions on the use of certain operating practices, such as hydraulic fracturing;
|
•
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reduced access to water supplies or restrictions on water disposal;
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•
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limited access or damage to or destruction of our property;
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•
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legal challenges or lawsuits;
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•
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increased regulation of our business;
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•
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damaging publicity and reputational harm;
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•
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increased costs of doing business;
|
•
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reduction in demand for our products; and
|
•
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other adverse effects on our ability to develop our properties and expand production.
|
•
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changes in foreign and domestic supply and demand for oil and gas;
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•
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political stability and economic conditions in oil producing countries, particularly in the Middle East;
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•
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weather conditions;
|
•
|
price and level of foreign imports;
|
•
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terrorist activity;
|
•
|
availability of pipeline and other secondary capacity;
|
•
|
general economic conditions;
|
•
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domestic and foreign governmental regulation; and
|
•
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the price and availability of alternative fuel sources.
|
•
|
fluctuations in commodity prices;
|
•
|
variations in results of operations;
|
•
|
legislative or regulatory changes;
|
•
|
general trends in the oil and gas industry;
|
•
|
sales of common stock or other actions by our stockholders;
|
•
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additions or departures of key management personnel;
|
•
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commencement of or involvement in litigation;
|
•
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speculation in the press or investment community regarding our business;
|
•
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an inability to maintain the listing of our common stock on a national securities exchange;
|
•
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market conditions; and
|
•
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analysts’ estimates and other events in the oil and gas industry.
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|
|
Developed
Acreage
|
|
Undeveloped Acreage
|
|
Fee Mineral
Acreage (1)
|
|
|
|||||||||||||
|
|
Gross
Acres
|
|
Net
Acres
|
|
Gross
Acres
|
|
Net
Acres
|
|
Gross
Acres
|
|
Net
Acres
|
|
Total
Net
Acres (2)
|
|||||||
Rocky Mountain
|
|
36,855
|
|
|
22,108
|
|
|
32,957
|
|
|
21,590
|
|
|
2,758
|
|
|
316
|
|
|
44,014
|
|
Permian Basin
|
|
17,766
|
|
|
14,967
|
|
|
10,226
|
|
|
8,130
|
|
|
12,008
|
|
|
5,273
|
|
|
28,370
|
|
Onshore Gulf Coast
|
|
8,166
|
|
|
7,654
|
|
|
5,827
|
|
|
5,608
|
|
|
2,975
|
|
|
879
|
|
|
14,141
|
|
Total
|
|
62,787
|
|
|
44,729
|
|
|
49,010
|
|
|
35,328
|
|
|
17,741
|
|
|
6,468
|
|
|
86,525
|
|
(1)
|
Fee mineral acreage represents fee simple absolute ownership of the mineral estate or fraction thereof.
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(2)
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Includes 1,217 net acres in the Permian Basin region that are included in both developed and fee mineral acres.
|
|
2016
|
2017
|
2018
|
2019
|
||||
Rocky Mountain
|
280
|
|
—
|
|
647
|
|
—
|
|
Permian Basin
|
822
|
|
79
|
|
—
|
|
—
|
|
Onshore Gulf Coast
|
672
|
|
3,078
|
|
149
|
|
—
|
|
|
|
|
|
|
|
|
Productive Wells
|
||||||||||
|
|
Oil
|
|
Gas
|
||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Rocky Mountain
|
|
376.0
|
|
|
81.7
|
|
|
412.0
|
|
|
11.2
|
|
Permian Basin
|
|
189.0
|
|
|
126.5
|
|
|
51.0
|
|
|
27.6
|
|
Onshore Gulf Coast
|
|
50.5
|
|
|
39.1
|
|
|
27.5
|
|
|
25.4
|
|
Total
|
|
615.5
|
|
|
247.3
|
|
|
490.5
|
|
|
64.2
|
|
Summary of Oil, NGL and Gas Reserves
As of December 31, 2015
|
||||||||||||
Reserve Category
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)
|
|
Gas
(MMcf)
|
|
Oil
Equivalents (MBoe)
|
||||
Proved
|
|
|
|
|
|
|
|
|
||||
Developed
|
|
10,022
|
|
|
1,957
|
|
|
31,298
|
|
|
17,194
|
|
Undeveloped
|
|
14,109
|
|
|
4,599
|
|
|
43,729
|
|
|
25,996
|
|
Total Proved
|
|
24,131
|
|
|
6,556
|
|
|
75,027
|
|
|
43,190
|
|
|
MMBoe
|
|
PUDs at December 31, 2014
|
24,459
|
|
Revisions of prior estimates
|
(8,582
|
)
|
Extensions, discoveries, and other additions
|
15,333
|
|
Conversion to developed
|
(5,214
|
)
|
Sales
|
—
|
|
PUDs at December 31, 2015
|
25,996
|
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2015
|
||||
|
|
(In thousands)
|
||||||
PV-10
|
|
$
|
637,443
|
|
|
$
|
197,251
|
|
Present value of future income taxes discounted at 10%
|
|
(124,886
|
)
|
|
—
|
|
||
Standardized measure of discounted future net cash flows
|
|
$
|
512,557
|
|
|
$
|
197,251
|
|
|
|
2013
|
|
2014
|
|
2015
|
||||||
Oil production (Bbls)
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
501,657
|
|
|
816,323
|
|
|
1,000,425
|
|
|||
Permian Basin
|
|
100,846
|
|
|
86,614
|
|
|
76,391
|
|
|||
Onshore Gulf Coast
|
|
224,625
|
|
|
491,142
|
|
|
363,404
|
|
|||
Mid-Continent (1)
|
|
2,197
|
|
|
—
|
|
|
—
|
|
Total
|
|
829,325
|
|
|
1,394,079
|
|
|
1,440,220
|
|
|||
Gas production (Mcf)
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
940,969
|
|
|
1,057,759
|
|
|
1,146,953
|
|
|||
Permian Basin
|
|
1,288,198
|
|
|
1,003,018
|
|
|
973,840
|
|
|||
Onshore Gulf Coast
|
|
1,029,346
|
|
|
856,928
|
|
|
894,039
|
|
|||
Mid-Continent (1)
|
|
84,384
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
3,342,897
|
|
|
2,917,705
|
|
|
3,014,832
|
|
|||
NGL production (Bbls)
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
50,421
|
|
|
95,384
|
|
|
132,846
|
|
|||
Permian Basin
|
|
88,254
|
|
|
79,321
|
|
|
54,877
|
|
|||
Onshore Gulf Coast
|
|
7,871
|
|
|
32,592
|
|
|
50,392
|
|
|||
Mid-Continent (1)
|
|
178
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
146,724
|
|
|
207,297
|
|
|
238,115
|
|
|||
Total production (MBoe) (2)
|
|
1,533
|
|
|
2,088
|
|
|
2,181
|
|
|||
Average sales price per Bbl of oil (3)
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
$
|
87.80
|
|
|
$
|
78.59
|
|
|
$
|
39.23
|
|
Permian Basin
|
|
$
|
91.72
|
|
|
$
|
84.38
|
|
|
$
|
44.69
|
|
Onshore Gulf Coast
|
|
$
|
101.59
|
|
|
$
|
88.44
|
|
|
$
|
45.71
|
|
Mid-Continent (4)
|
|
$
|
90.53
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Composite
|
|
$
|
92.02
|
|
|
$
|
82.42
|
|
|
$
|
41.15
|
|
Average sales price per Mcf of gas (3)
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
$
|
3.33
|
|
|
$
|
4.41
|
|
|
$
|
1.46
|
|
Permian Basin
|
|
$
|
3.47
|
|
|
$
|
4.29
|
|
|
$
|
2.24
|
|
Onshore Gulf Coast
|
|
$
|
2.99
|
|
|
$
|
3.73
|
|
|
$
|
2.24
|
|
Mid-Continent (1)
|
|
$
|
2.87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Composite
|
|
$
|
3.27
|
|
|
$
|
4.17
|
|
|
$
|
1.94
|
|
Average sales price per Bbl of NGL
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
$
|
40.59
|
|
|
$
|
36.41
|
|
|
$
|
5.49
|
|
Permian Basin
|
|
$
|
32.12
|
|
|
$
|
31.10
|
|
|
$
|
13.03
|
|
Onshore Gulf Coast
|
|
$
|
18.96
|
|
|
$
|
21.41
|
|
|
$
|
8.60
|
|
Mid-Continent (1)
|
|
$
|
30.09
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Composite
|
|
$
|
34.32
|
|
|
$
|
32.02
|
|
|
$
|
7.89
|
|
Average sales price per Boe (3)
|
|
$
|
60.18
|
|
|
$
|
64.04
|
|
|
$
|
30.72
|
|
Average cost of production per Boe produced (4)
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
$
|
13.11
|
|
|
$
|
7.36
|
|
|
$
|
6.43
|
|
Permian Basin
|
|
$
|
14.50
|
|
|
$
|
15.15
|
|
|
$
|
15.76
|
|
Onshore Gulf Coast
|
|
$
|
8.34
|
|
|
$
|
9.30
|
|
|
$
|
12.71
|
|
Mid-Continent (1)
|
|
$
|
15.65
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Composite
|
|
$
|
12.71
|
|
|
$
|
9.22
|
|
|
$
|
9.31
|
|
(1)
|
All of our Mid-Continent properties were sold in 2013.
|
(2)
|
Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil.
|
(3)
|
Before the impact of hedging activities.
|
(4)
|
Production costs include controllable direct lease operating costs but exclude ad valorem taxes, production taxes and non-recurring lease operating costs.
|
|
|
2013
|
|
2014
|
|
2015
|
||||||||||
Rocky Mountain Region
|
|
|
|
|
|
|
||||||||||
Oil production (Bbls)
|
|
|
|
|
|
|
||||||||||
Bakken/Three Forks
|
|
296,451
|
|
|
|
660,447
|
|
|
|
862,458
|
|
|
||||
Gas production (Mcf)
|
|
|
|
|
|
|
||||||||||
Bakken/Three Forks
|
|
351,248
|
|
|
|
570,792
|
|
|
|
687,200
|
|
|
||||
NGL production (Bbls)
|
|
|
|
|
|
|
||||||||||
Bakken/Three Forks
|
|
31,229
|
|
|
|
77,120
|
|
|
|
116,392
|
|
|
||||
Average sales price per Bbl of oil (1)
|
|
|
|
|
|
|
|
|
|
|||||||
Bakken/Three Forks
|
|
$
|
88.35
|
|
|
|
$
|
78.01
|
|
|
|
$
|
39.15
|
|
|
|
Average sales price per Mcf of gas (1)
|
|
|
|
|
|
|
|
|
|
|||||||
Bakken/Three Forks
|
|
$
|
2.87
|
|
|
|
$
|
4.60
|
|
|
|
$
|
1.07
|
|
|
|
Average sales price per Bbl of NGL (1)
|
|
|
|
|
|
|
|
|
|
|||||||
Bakken/Three Forks
|
|
$
|
37.34
|
|
|
|
$
|
34.86
|
|
|
|
$
|
3.78
|
|
|
|
Average cost of production per Boe produced (2)
|
|
|
|
|
|
|
|
|
|
|||||||
Bakken/Three Forks
|
|
$
|
10.03
|
|
|
|
$
|
6.88
|
|
|
|
$
|
4.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Onshore Gulf Coast Region
|
|
|
|
|
|
|
|
|
|
|||||||
Oil production (Bbls)
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
154,910
|
|
|
|
431,892
|
|
|
|
305,797
|
|
|
||||
Gas production (Mcf)
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
45,560
|
|
|
|
229,385
|
|
|
|
325,942
|
|
|
||||
NGL production (Bbls)
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
7,530
|
|
|
|
32,592
|
|
|
|
50,392
|
|
|
||||
Average sales price per Bbl of oil (1)
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
$
|
102.17
|
|
|
|
$
|
88.30
|
|
|
|
$
|
45.87
|
|
|
|
Average sales price per Mcf of gas (1)
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
$
|
3.11
|
|
|
|
$
|
3.69
|
|
|
|
$
|
2.44
|
|
|
|
Average sales price per Bbl of NGL
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
$
|
18.48
|
|
|
|
$
|
21.42
|
|
|
|
$
|
8.60
|
|
—
|
|
Average cost of production per Boe produced (2)
|
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
$
|
6.40
|
|
|
|
$
|
7.98
|
|
|
|
$
|
12.33
|
|
|
|
|
2013
|
|
2014
|
|
2015
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Rocky Mountain
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Permian Basin
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Onshore Gulf Coast
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin
|
|
2.0
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
2.0
|
|
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
31.0
|
|
|
3.1
|
|
|
10.0
|
|
|
6.4
|
|
|
21.0
|
|
|
6.8
|
|
Permian Basin
|
|
1.0
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Onshore Gulf Coast
|
|
11.0
|
|
|
3.9
|
|
|
10.0
|
|
|
10.0
|
|
|
4.0
|
|
|
4.0
|
|
Total
|
|
43.0
|
|
|
8.0
|
|
|
20.0
|
|
|
16.4
|
|
|
25.0
|
|
|
10.8
|
|
|
|
|
|
Period
|
|
High
|
|
Low
|
|||||
2014
|
|
|
|
|
|
|
|||||
|
|
First Quarter
|
|
$
|
4.15
|
|
|
$
|
2.99
|
|
|
|
|
Second Quarter
|
|
6.41
|
|
|
3.82
|
|
|||
|
|
Third Quarter
|
|
6.45
|
|
|
4.81
|
|
|||
|
|
Fourth Quarter
|
|
5.30
|
|
|
2.33
|
|
|||
2015
|
|
|
|
|
|
|
|||||
|
|
First Quarter
|
|
$
|
3.56
|
|
|
$
|
2.60
|
|
|
|
|
Second Quarter
|
|
3.98
|
|
|
2.82
|
|
|||
|
|
Third Quarter
|
|
2.95
|
|
|
1.20
|
|
|||
|
|
Fourth Quarter
|
|
1.95
|
|
|
0.84
|
|
|||
2016
|
16
|
|
First Quarter (Through March 10, 2016)
|
|
$
|
1.31
|
|
|
$
|
0.65
|
|
•
|
Market capitalization;
|
•
|
Revenue;
|
•
|
Assets;
|
•
|
Enterprise value; and
|
•
|
Operational similarities.
|
|
|
12/31/2010
|
|
12/31/2011
|
|
12/31/2012
|
|
12/31/2013
|
|
12/31/2014
|
|
12/31/2015
|
||||||
Small Cap Index
|
$
|
100.00
|
|
$
|
69.26
|
|
$
|
43.97
|
|
$
|
59.15
|
|
$
|
27.68
|
|
$
|
9.96
|
|
S&P 500
|
$
|
100.00
|
|
$
|
100.00
|
|
$
|
113.40
|
|
$
|
146.97
|
|
$
|
163.71
|
|
$
|
162.52
|
|
AXAS
|
$
|
100.00
|
|
$
|
72.21
|
|
$
|
47.92
|
|
$
|
71.36
|
|
$
|
64.33
|
|
$
|
23.19
|
|
|
|
Year Ended December 31,
|
|||||||||||||||||||||||
|
|
2011
|
2012
|
|
2013
|
|
|
2014
|
|
|
2015
|
||||||||||||||
|
|
(In thousands, except per share data)
|
|||||||||||||||||||||||
Total revenue - continuing operations
|
|
$
|
63,105
|
|
|
|
$
|
65,664
|
|
|
$
|
92,324
|
|
|
|
$
|
133,776
|
|
|
|
$
|
67,030
|
|
|
|
Net income (loss)
|
|
$
|
13,743
|
|
|
|
$
|
(18,791
|
)
|
|
$
|
38,647
|
|
|
|
$
|
63,269
|
|
|
|
$
|
(127,110
|
)
|
|
|
Net income (loss) from continuing operations
|
|
$
|
14,395
|
|
|
|
$
|
3,106
|
|
|
$
|
46,841
|
|
(2)
|
|
$
|
61,951
|
|
|
|
$
|
(127,090
|
)
|
(5
|
)
|
Net (loss) income from discontinued operations
|
|
$
|
(652
|
)
|
|
|
$
|
(21,897
|
)
|
(1)
|
$
|
(8,194
|
)
|
(3)
|
|
$
|
1,318
|
|
(4)
|
|
$
|
(20
|
)
|
|
|
Net income (loss) per common share – diluted - continuing operations
|
|
$
|
0.15
|
|
|
|
$
|
0.04
|
|
|
$
|
0.50
|
|
|
|
$
|
0.61
|
|
|
|
$
|
(1.21
|
)
|
|
|
Weighted average shares outstanding – diluted
|
|
92,244
|
|
|
|
91,914
|
|
|
93,538
|
|
|
|
101,468
|
|
|
|
104,605
|
|
|
||||||
Total assets
|
|
$
|
241,150
|
|
|
|
$
|
240,607
|
|
|
$
|
223,650
|
|
|
|
$
|
374,899
|
|
|
|
$
|
267,872
|
|
|
|
Long-term debt, excluding current maturities
|
|
$
|
126,258
|
|
|
|
$
|
124,101
|
|
|
$
|
41,790
|
|
|
|
$
|
76,554
|
|
|
|
$
|
138,402
|
|
|
|
Total stockholders’ equity
|
|
$
|
62,651
|
|
|
|
$
|
46,700
|
|
|
$
|
86,906
|
|
|
|
$
|
207,495
|
|
|
|
$
|
84,465
|
|
|
(1)
|
Includes proved property impairment of $19.8 million related to discontinued operations.
|
(2)
|
Includes a gain on the sale of properties of $33.4 million.
|
(3)
|
Includes proved property impairment of $6.0 million related to discontinued operations.
|
(4)
|
Includes a gain of $1.9 million on the sale of our Canadian subsidiary.
|
(5)
|
Includes proved property impairment of $128.6 million.
|
•
|
the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
|
•
|
basis differentials which are dependent on actual delivery location;
|
•
|
adjustments for BTU content;
|
•
|
quality of the hydrocarbons; and
|
•
|
gathering, processing and transportation costs.
|
|
|
Oil
|
|
Gas
|
||||||||||||||||||||
|
|
2013
|
|
2014
|
|
2015
|
|
2013
|
|
2014
|
|
2015
|
||||||||||||
Average realized price (1)
|
|
$
|
92.02
|
|
|
$
|
82.42
|
|
|
$
|
41.15
|
|
|
$
|
3.27
|
|
|
$
|
4.17
|
|
|
$
|
1.94
|
|
Average NYMEX price
|
|
$
|
98.06
|
|
|
$
|
92.91
|
|
|
$
|
48.76
|
|
|
$
|
3.73
|
|
|
$
|
4.26
|
|
|
$
|
2.63
|
|
Differential
|
|
$
|
(6.04
|
)
|
|
$
|
(10.49
|
)
|
|
$
|
(7.61
|
)
|
|
$
|
(0.46
|
)
|
|
$
|
(0.09
|
)
|
|
$
|
(0.69
|
)
|
(1)
|
Average realized prices are before the impact of hedging activities.
|
|
|
Oil - WTI
|
|
|||||
Contract Periods
|
|
Daily Volume (Bbl)
|
|
Swap Price (per Bbl)
|
|
|||
2016
|
|
948
|
|
|
$
|
84.10
|
|
|
2017
|
|
608
|
|
|
$
|
78.55
|
|
|
|
|
Daily Volume (Bbl)
|
|
Floor (Long Put)
|
|
Ceiling (Short Call)
|
|
Short Put
|
|||||||
2016
|
|
1,000
|
|
|
$
|
60.00
|
|
|
$
|
71.00
|
|
|
$
|
45.00
|
|
|
|
Year Ended December 31,
|
|||||||
|
|
2013
|
|
2014
|
|
2015
|
|||
Total production (MBoe)
|
|
1,533
|
|
|
2,088
|
|
|
2,181
|
|
Average daily production (Boepd)
|
|
4,201
|
|
|
5,720
|
|
|
5,975
|
|
% Oil/ NGL
|
|
64
|
%
|
|
77
|
%
|
|
77
|
%
|
|
|
Year Ended December 31,
|
||||||||||
|
|
(In thousands, except per unit data)
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
Operating revenue (1):
|
|
|
|
|
|
|
||||||
Oil sales
|
|
$
|
76,311
|
|
|
$
|
114,898
|
|
|
$
|
59,270
|
|
Gas sales
|
|
10,921
|
|
|
12,166
|
|
|
5,854
|
|
|||
NGL sales
|
|
5,036
|
|
|
6,637
|
|
|
1,878
|
|
|||
Total operating revenues
|
|
$
|
92,268
|
|
|
$
|
133,701
|
|
|
$
|
67,002
|
|
Operating income (loss)
|
|
$
|
23,097
|
|
|
$
|
39,922
|
|
|
$
|
(141,805
|
)
|
Oil sales (MBbls)
|
|
829
|
|
|
1,394
|
|
|
1,440
|
|
|||
Gas sales (MMcf)
|
|
3,343
|
|
|
2,918
|
|
|
3,015
|
|
|||
NGL sales (MBbls)
|
|
147
|
|
|
207
|
|
|
238
|
|
|||
Oil equivalents (MBoe)
|
|
1,533
|
|
|
2,088
|
|
|
2,181
|
|
|||
Average oil sales price (per Bbl)(1)
|
|
$
|
92.02
|
|
|
$
|
82.42
|
|
|
$
|
41.15
|
|
Average gas sales price (per Mcf)(1)
|
|
$
|
3.27
|
|
|
$
|
4.17
|
|
|
$
|
1.94
|
|
Average NGL sales price (per Bbl)
|
|
$
|
34.32
|
|
|
$
|
32.02
|
|
|
$
|
7.89
|
|
Average oil equivalent sales price (Boe)
|
|
$
|
60.18
|
|
|
$
|
64.04
|
|
|
$
|
30.72
|
|
(1)
|
Revenue and average sales prices are before the impact of hedging activities.
|
•
|
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.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Expenditure category:
|
|
|
|
|
|
|
||||||
Acquisition of producing properties
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Exploration/Development
|
|
91,324
|
|
|
189,210
|
|
|
68,631
|
|
|||
Facilities and other
|
|
1,165
|
|
|
3,589
|
|
|
760
|
|
|||
Total
|
|
$
|
92,489
|
|
|
$
|
192,799
|
|
|
$
|
69,391
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Net cash provided by operating activities
|
|
$
|
52,479
|
|
|
$
|
94,462
|
|
|
$
|
6,999
|
|
Net cash provided by (used in) investing activities
|
|
35,040
|
|
|
(186,800
|
)
|
|
(69,253
|
)
|
|||
Net cash (used in) provided by financing activities
|
|
(84,389
|
)
|
|
87,857
|
|
|
62,042
|
|
|||
Total
|
|
$
|
3,130
|
|
|
$
|
(4,481
|
)
|
|
$
|
(212
|
)
|
•
|
Long-term debt, and
|
•
|
Operating leases for office facilities.
|
|
|
Payments due in twelve month periods ending:
|
||||||||||||||||||
Contractual Obligations
(In thousands)
|
|
Total
|
|
December 31,
2016
|
|
December 31,
2017-2018
|
|
December 31,
2019-2020
|
|
Thereafter
|
||||||||||
Long-term debt (1)
|
|
$
|
140,732
|
|
|
$
|
2,330
|
|
|
$
|
135,047
|
|
|
$
|
558
|
|
|
$
|
2,797
|
|
Interest on long-term debt (2)
|
|
10,871
|
|
|
4,156
|
|
|
6,184
|
|
|
266
|
|
|
265
|
|
|||||
Lease obligations (3)
|
|
44
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total
|
|
$
|
151,647
|
|
|
$
|
6,530
|
|
|
$
|
141,231
|
|
|
$
|
824
|
|
|
$
|
3,062
|
|
(1)
|
These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These payments assume that we will not borrow additional funds.
|
(2)
|
Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.
|
(3)
|
Lease on office space in Dickinson, North Dakota, which expires on October 31, 2016, office space in Lusk, Wyoming, which will expire on December 31, 2016 and office space in Denver, Colorado which will expire on December 31, 2016.
|
|
|
December 31, 2014
|
|
December 31, 2015
|
||||
|
|
(In thousands)
|
||||||
Credit facility
|
|
$
|
70,000
|
|
|
$
|
134,000
|
|
Rig loan agreement
|
|
4,456
|
|
|
2,620
|
|
||
Real estate lien note
|
|
4,333
|
|
|
4,112
|
|
||
|
|
78,789
|
|
|
140,732
|
|
||
Less current maturities
|
|
(2,235
|
)
|
|
(2,330
|
)
|
||
|
|
$
|
76,554
|
|
|
$
|
138,402
|
|
•
|
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.
|
|
|
Page
|
|
|
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
|
|
|
F-2
|
|
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting
|
|
|
F-3
|
|
Consolidated Balance Sheets at December 31, 2014 and 2015
|
|
|
F-4
|
|
Consolidated Statements of Operations for the years ended December 31, 2013, 2014 and 2015
|
|
|
F-6
|
|
Consolidated Statements of Other Comprehensive Income (Loss) for the years ended
December 31, 2013, 2014 and 2015
|
|
|
F-7
|
|
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended
December 31, 2013, 2014 and 2015
|
|
|
F-8
|
|
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2014 and 2015
|
|
|
F-9
|
|
Notes to Consolidated Financial Statements
|
|
|
F-11
|
|
3.1
|
Articles of Incorporation of Abraxas dated August 30, 1990. (Filed as Exhibit 3.1 to our Registration Statement on Form S-4, No. 33-36565. (the “S-4 Registration Statement”)).
|
3.2
|
Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement).
|
3.3
|
Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement).
|
3.4
|
Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on Form S-3, No. 333-00398).
|
3.5
|
Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000. (Filed as Exhibit 3.5 to our Annual Report on Form 10-K filed on April 2, 2001).
|
3.6
|
Certificate of Correction dated February 24, 2011 (Filed as Exhibit 3.6 to our Annual Report on Form 10-K filed on March 15, 2012).
|
3.7
|
Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on November 17, 2008).
|
4.1
|
Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement).
|
4.2
|
Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our Annual Report on Form 10-K filed on March 31, 1995).
|
*10.1
|
Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-18673 filed on December 24, 1996).
|
*10.2
|
Abraxas Petroleum Corporation Amended and Restated 1994 Long Term Incentive Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-120989 filed on January 12, 2005).
|
*10.3
|
Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filed March 14, 2007).
|
*10.4
|
Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the Registration Statement on Form S-1, No. 333-95281 filed on January 24, 2000 (the “2000 S-1 Registration Statement”)).
|
*10.5
|
Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the Registration Statement on Form S-3, No. 333-127480 filed on September 16, 2005 (the “S-3 Registration Statement”)).
|
*10.6
|
Employment Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27 to the S-3 Registration Statement).
|
*10.7
|
Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as Exhibit 10.28 to the S-3 Registration Statement).
|
*10.8
|
Employment Agreement between Abraxas and G. William Krog, Jr. (Filed as Exhibit 10.9 to our Annual Report on Form 10-K filed March 15, 2012).
|
*10.9
|
Employment Agreement between Abraxas and Geoffrey R. King (Filed as Exhibit 10.9 to our Annual Report on Form 10-K filed March 18, 2013)
|
*10.10
|
Abraxas Petroleum Corporation Amended and Restated 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Appendix B to our Proxy Statement filed on April 2, 2015).
|
*10.11
|
Form of Stock Option Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed June 6, 2005).
|
*10.12
|
Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed as Exhibit 10.17 to our Annual Report on Form 10-K filed March 23, 2006).
|
*10.13
|
Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. (Filed as Appendix A to our Proxy Statement filed on April 2, 2015).
|
*10.14
|
Form of Employee Stock Option Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed August 26, 2006).
|
*10.15
|
Form of Restricted Stock Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Employee Long-Term Equity Incentive Plan (Filed as Exhibit 10.1 to our Annual Report on Form 10-K filed on March 13, 2015).
|
10.16
|
Third Amended and Restated Credit Agreement dated as of June 11, 2014 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société Générale, as Administrative Agent and as Issuing Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K/A filed on June 13, 2014).
|
10.17
|
Loan Agreement dated as of September 19, 2011 between Raven Drilling, LLC, as Borrower, and RBS Asset Finance, Inc., as Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on September 23, 2011).
|
10.18
|
Promissory Note dated November 13, 2008 by Abraxas Properties Incorporated and Abraxas Petroleum Corporation, payable to the order of Plains Capital Bank, as Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on August 8, 2014.)
|
10.19
|
Second Modification, Renewal and Extension of Promissory Note and Deed of Trust Liens by and between Plains Capital Bank, Abraxas Properties Corporation and Abraxas Petroleum Corporation effective March 13, 2013. (Previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on August 8, 2014).
|
10.20
|
Third Modification, Renewal and Extension of Promissory Note and Deed of Trust Liens by and between Plains Capital Bank, Abraxas Properties Incorporated and Abraxas Petroleum Corporation effective as of July 13, 2013. (Previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on August 8, 2014).
|
14.1
|
Abraxas Petroleum Corporation Code of Business Conduct and Ethics. (Filed as Exhibit 14.1 to our Annual Report on Form 10-K filed March 22, 2006).
|
21.1
|
Subsidiaries of Abraxas. (Filed herewith).
|
23.1
|
Consent of BDO USA, LLP. (Filed herewith).
|
23.2
|
Consent of DeGolyer and MacNaughton. (Filed herewith).
|
31.1
|
Certification – Chief Executive Officer. (Filed herewith).
|
31.2
|
Certification – Chief Financial Officer. (Filed herewith).
|
32.1
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
|
32.2
|
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
|
*
|
Management Compensatory Plan or Agreement.
|
By:
|
/s/Robert L.G. Watson
|
|
By:
|
/s/Geoffrey R. King
|
By:
|
/s/ G. William Krog, Jr.
|
|
President and Principal Executive Officer
|
|
|
Vice President and Principal Financial Officer
|
|
Principal Accounting Officer
|
Signature
|
|
Name and Title
|
|
Date
|
/s/ Robert L.G. Watson
Robert L.G. Watson
|
|
Chairman of the Board, President (Principal Executive Officer) and Director
|
|
March 15, 2016
|
/s/ Geoffrey R. King
Geoffrey R. King
|
|
Vice President, CFO (Principal Financial Officer)
|
|
March 15, 2016
|
/s/ G. William Krog, Jr
.
G. William Krog, Jr.
|
|
Chief Accounting Officer (Principal Accounting Officer)
|
|
March 15, 2016
|
/s/ Harold D. Carter
Harold D. Carter
|
|
Director
|
|
March 15, 2016
|
/s/ Ralph F. Cox
Ralph F. Cox
|
|
Director
|
|
March 15, 2016
|
/s/ W. Dean Karrash
W. Dean Karrash
|
|
Director
|
|
March 15, 2016
|
/s/ Jerry J. Langdon
Jerry J. Langdon
|
|
Director
|
|
March 15, 2016
|
/s/ Dennis E. Logue
Dennis E. Logue
|
|
Director
|
|
March 15, 2016
|
/s/ Brian L. Melton
Brian L. Melton
|
|
Director
|
|
March 15, 2016
|
/s/ Paul A. Powell, Jr.
Paul A. Powell, Jr.
|
|
Director
|
|
March 15, 2016
|
/s/ Edward P. Russell
Edward P. Russell
|
|
Director
|
|
March 15, 2016
|
|
|
Page
|
|
Abraxas Petroleum Corporation and Subsidiaries
|
|
|
|
|
|
|
|
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
|
|
F-2
|
|
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting
|
|
F-3
|
|
Consolidated Balance Sheets at December 31, 2014 and 2015
|
|
F-4
|
|
Consolidated Statements of Operations for the years ended December 31, 2013, 2014 and 2015
|
|
F-6
|
|
Consolidated Statements of Other Comprehensive Income (Loss) for the years ended December 31, 2013,
2014 and 2015
|
|
F-7
|
|
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2013,
2014 and 2015
|
|
F-8
|
|
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2014 and 2015
|
|
F-9
|
|
|
|
|
|
Notes to Consolidated Financial Statements
|
|
F-11
|
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2015
|
||||
|
|
(In thousands)
|
||||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
3,772
|
|
|
$
|
3,540
|
|
Accounts receivable:
|
|
|
|
|
|
|
||
Joint owners - net
|
|
5,648
|
|
|
1,552
|
|
||
Oil and gas production sales
|
|
15,308
|
|
|
6,713
|
|
||
Other
|
|
647
|
|
|
1,241
|
|
||
|
|
21,603
|
|
|
9,506
|
|
||
|
|
|
|
|
||||
Derivative assets
|
|
12,214
|
|
|
18,902
|
|
||
Other current assets
|
|
843
|
|
|
726
|
|
||
Total current assets
|
|
38,432
|
|
|
32,674
|
|
||
|
|
|
|
|
||||
Property and equipment:
|
|
|
|
|
|
|
||
Oil and gas properties, full cost method of accounting:
|
|
|
|
|
|
|
||
Proved
|
|
716,922
|
|
|
787,683
|
|
||
Other property and equipment
|
|
40,683
|
|
|
41,444
|
|
||
Total
|
|
757,605
|
|
|
829,127
|
|
||
Less accumulated depreciation, depletion, amortization and impairment
|
|
(434,726
|
)
|
|
(604,289
|
)
|
||
Total property and equipment, net
|
|
322,879
|
|
|
224,838
|
|
||
|
|
|
|
|
||||
Deferred financing fees, net
|
|
2,216
|
|
|
1,642
|
|
||
Derivative asset
|
|
10,981
|
|
|
8,463
|
|
||
Other assets
|
|
391
|
|
|
255
|
|
||
Total assets
|
|
$
|
374,899
|
|
|
$
|
267,872
|
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2015
|
||||
|
|
(In thousands, except shares data)
|
||||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
63,549
|
|
|
$
|
24,825
|
|
Joint interest oil and gas production payable
|
|
14,423
|
|
|
7,177
|
|
||
Accrued interest
|
|
72
|
|
|
115
|
|
||
Other accrued expenses
|
|
1,006
|
|
|
622
|
|
||
Derivative liability
|
|
13
|
|
|
—
|
|
||
Current maturities of long-term debt
|
|
2,235
|
|
|
2,330
|
|
||
Total current liabilities
|
|
81,298
|
|
|
35,069
|
|
||
|
|
|
|
|
||||
Long-term debt – less current maturities
|
|
76,554
|
|
|
138,402
|
|
||
Other liabilities
|
|
57
|
|
|
257
|
|
||
Future site restoration
|
|
9,495
|
|
|
9,679
|
|
||
Total liabilities
|
|
167,404
|
|
|
183,407
|
|
||
|
|
|
|
|
||||
Commitments and contingencies (Note 7)
|
|
|
|
|
|
|
||
|
|
|
|
|
||||
Stockholders’ Equity:
|
|
|
|
|
|
|
||
Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding
|
|
—
|
|
|
—
|
|
||
Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 106,186,678 and 106,346,001, respectively
|
|
1,062
|
|
|
1,063
|
|
||
Additional paid-in capital
|
|
309,773
|
|
|
313,852
|
|
||
Accumulated deficit
|
|
(103,340
|
)
|
|
(230,450
|
)
|
||
Total stockholders’ equity
|
|
207,495
|
|
|
84,465
|
|
||
Total liabilities and stockholders’ equity
|
|
$
|
374,899
|
|
|
$
|
267,872
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands, except per share data)
|
||||||||||
Revenues:
|
|
|
|
|
|
|
||||||
Oil and gas production revenues
|
|
$
|
92,268
|
|
|
$
|
133,701
|
|
|
$
|
67,002
|
|
Other
|
|
56
|
|
|
75
|
|
|
28
|
|
|||
|
|
92,324
|
|
|
133,776
|
|
|
67,030
|
|
|||
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|||
Lease operating
|
|
23,205
|
|
|
25,875
|
|
|
23,074
|
|
|||
Production taxes
|
|
8,437
|
|
|
11,462
|
|
|
6,679
|
|
|||
Depreciation, depletion, and amortization
|
|
25,588
|
|
|
43,139
|
|
|
38,721
|
|
|||
Proved property impairment
|
|
—
|
|
|
—
|
|
|
128,573
|
|
|||
General and administrative (including stock-based compensation of $2,114, $2,703 and $3,912, respectively)
|
|
11,997
|
|
|
13,378
|
|
|
11,788
|
|
|||
|
|
69,227
|
|
|
93,854
|
|
|
208,835
|
|
|||
Operating income (loss)
|
|
23,097
|
|
|
39,922
|
|
|
(141,805
|
)
|
|||
|
|
|
|
|
|
|
||||||
Other (income) expense:
|
|
|
|
|
|
|
|
|
|
|||
Interest income
|
|
(3
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|||
Interest expense
|
|
4,556
|
|
|
2,570
|
|
|
3,906
|
|
|||
Amortization of deferred financing fees
|
|
1,367
|
|
|
934
|
|
|
643
|
|
|||
Gain on sale of properties
|
|
(33,377
|
)
|
|
—
|
|
|
—
|
|
|||
Loss (gain) on derivative contracts
|
|
2,474
|
|
|
(25,237
|
)
|
|
(19,301
|
)
|
|||
Other
|
|
539
|
|
|
(7
|
)
|
|
318
|
|
|||
|
|
(24,444
|
)
|
|
(21,742
|
)
|
|
(14,436
|
)
|
|||
Income (loss) from continuing operations before income tax
|
|
47,541
|
|
|
61,664
|
|
|
(127,369
|
)
|
|||
Income tax (expense) benefit
|
|
(700
|
)
|
|
287
|
|
|
279
|
|
|||
Net income (loss) from continuing operations
|
|
46,841
|
|
|
61,951
|
|
|
(127,090
|
)
|
|||
Net (loss) income from discontinued operations - net of tax
|
|
(8,194
|
)
|
|
1,318
|
|
|
(20
|
)
|
|||
|
|
$
|
38,647
|
|
|
$
|
63,269
|
|
|
$
|
(127,110
|
)
|
|
|
|
|
|
|
|
||||||
Net income (loss) per common share - basic
|
|
|
|
|
|
|
||||||
Continuing operations
|
|
$
|
0.51
|
|
|
$
|
0.63
|
|
|
$
|
(1.21
|
)
|
Discontinued operations
|
|
(0.09
|
)
|
|
0.01
|
|
|
—
|
|
|||
|
|
$
|
0.42
|
|
|
$
|
0.64
|
|
|
$
|
(1.21
|
)
|
|
|
|
|
|
|
|
||||||
Net income (loss) per common share - diluted
|
|
|
|
|
|
|
||||||
Continuing operations
|
|
$
|
0.50
|
|
|
$
|
0.61
|
|
|
$
|
(1.21
|
)
|
Discontinued operations
|
|
(0.09
|
)
|
|
0.01
|
|
|
—
|
|
|||
|
|
$
|
0.41
|
|
|
$
|
0.62
|
|
|
$
|
(1.21
|
)
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Net income (loss)
|
|
$
|
38,647
|
|
|
$
|
63,269
|
|
|
$
|
(127,110
|
)
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|||
Change in unrealized value of investments
|
|
(79
|
)
|
|
—
|
|
|
—
|
|
|||
Foreign currency translation adjustment
|
|
(559
|
)
|
|
607
|
|
|
—
|
|
|||
Other comprehensive income (loss)
|
|
(638
|
)
|
|
607
|
|
|
—
|
|
|||
Comprehensive income (loss)
|
|
$
|
38,009
|
|
|
$
|
63,876
|
|
|
$
|
(127,110
|
)
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Shares
|
|
Amount
|
|
Additional
Paid in
Capital
|
|
Accumulated
Deficit
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total
|
|||||||||||
Balance at December 31, 2012
|
92,733,448
|
|
|
$
|
927
|
|
|
$
|
250,998
|
|
|
$
|
(205,256
|
)
|
|
$
|
31
|
|
|
$
|
46,700
|
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
38,647
|
|
|
—
|
|
|
38,647
|
|
|||||
Change in unrealized gain (loss) on fair value of investments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79
|
)
|
|
(79
|
)
|
|||||
Foreign currency translation adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(559
|
)
|
|
(559
|
)
|
|||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
2,114
|
|
|
—
|
|
|
—
|
|
|
2,114
|
|
|||||
Stock options exercised
|
129,686
|
|
|
2
|
|
|
81
|
|
|
—
|
|
|
—
|
|
|
83
|
|
|||||
Restricted stock issued, net of cancellations
|
42,915
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2013
|
92,906,049
|
|
|
929
|
|
|
253,193
|
|
|
(166,609
|
)
|
|
(607
|
)
|
|
86,906
|
|
|||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
63,269
|
|
|
—
|
|
|
63,269
|
|
|||||
Foreign currency translation adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
607
|
|
|
607
|
|
|||||
Stock issuance
|
11,500,000
|
|
|
115
|
|
|
53,640
|
|
|
|
|
|
|
53,755
|
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
2,703
|
|
|
—
|
|
|
—
|
|
|
2,703
|
|
|||||
Stock options exercised
|
238,157
|
|
|
3
|
|
|
252
|
|
|
—
|
|
|
—
|
|
|
255
|
|
|||||
Restricted stock issued, net of cancellations
|
1,542,472
|
|
|
15
|
|
|
(15
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2014
|
106,186,678
|
|
|
1,062
|
|
|
309,773
|
|
|
(103,340
|
)
|
|
—
|
|
|
207,495
|
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(127,110
|
)
|
|
—
|
|
|
(127,110
|
)
|
|||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
3,912
|
|
|
—
|
|
|
—
|
|
|
3,912
|
|
|||||
Stock options exercised
|
164,400
|
|
|
1
|
|
|
167
|
|
|
—
|
|
|
—
|
|
|
168
|
|
|||||
Restricted stock issued, net of cancellations
|
(5,077
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Balance at December 31, 2015
|
106,346,001
|
|
|
$
|
1,063
|
|
|
$
|
313,852
|
|
|
$
|
(230,450
|
)
|
|
$
|
—
|
|
|
$
|
84,465
|
|
ABRAXAS PETROLEM CORPORATION
|
||||||||||||
|
|
|
|
|
|
|
||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
||||||||||||
|
|
|
|
|
|
|
||||||
|
|
Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Operating Activities
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
38,647
|
|
|
$
|
63,269
|
|
|
$
|
(127,110
|
)
|
Income (loss) from discontinued operations
|
|
(8,194
|
)
|
|
1,318
|
|
|
(20
|
)
|
|||
Income (loss) from continuing operations
|
|
46,841
|
|
|
61,951
|
|
|
(127,090
|
)
|
|||
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|||
Gain on sale of properties
|
|
(33,377
|
)
|
|
—
|
|
|
—
|
|
|||
Net gain on derivative contracts
|
|
2,494
|
|
|
(25,217
|
)
|
|
(19,301
|
)
|
|||
Derivative contract settlements
|
|
(5,035
|
)
|
|
361
|
|
|
9,495
|
|
|||
Monetization of derivative contracts
|
|
—
|
|
|
152
|
|
|
4,610
|
|
|||
Depreciation, depletion, and amortization
|
|
25,588
|
|
|
43,139
|
|
|
38,721
|
|
|||
Proved property impairment
|
|
—
|
|
|
—
|
|
|
128,573
|
|
|||
Accretion of future site restoration
|
|
615
|
|
|
559
|
|
|
565
|
|
|||
Amortization of deferred financing fees
|
|
1,367
|
|
|
934
|
|
|
643
|
|
|||
Stock-based compensation
|
|
2,114
|
|
|
2,703
|
|
|
3,912
|
|
|||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|||
Accounts receivable - net of allowance
|
|
(13,702
|
)
|
|
11,881
|
|
|
12,097
|
|
|||
Other assets and liabilities
|
|
(7
|
)
|
|
(2,737
|
)
|
|
1,466
|
|
|||
Accounts payable
|
|
27,514
|
|
|
1,596
|
|
|
(45,970
|
)
|
|||
Accrued expenses
|
|
(1,933
|
)
|
|
(860
|
)
|
|
(722
|
)
|
|||
Net cash provided by continuing operations
|
|
52,479
|
|
|
94,462
|
|
|
6,999
|
|
|||
Net cash (used in) provided by discontinued operations
|
|
(825
|
)
|
|
1,741
|
|
|
(20
|
)
|
|||
Net cash provided by operating activities
|
|
51,654
|
|
|
96,203
|
|
|
6,979
|
|
|||
|
|
|
|
|
|
|
||||||
Investing Activities
|
|
|
|
|
|
|
|
|
|
|||
Capital expenditures, including purchases
and development of properties
|
|
(92,489
|
)
|
|
(192,799
|
)
|
|
(69,391
|
)
|
|||
Proceeds from the sale of oil and gas properties
|
|
127,529
|
|
|
5,999
|
|
|
138
|
|
|||
Net cash provided by (used in) continuing operations
|
|
35,040
|
|
|
(186,800
|
)
|
|
(69,253
|
)
|
|||
Net cash ( used in) provided by discontinued operations
|
|
(2,554
|
)
|
|
332
|
|
|
—
|
|
|||
Net cash provided by (used in) investing activities
|
|
32,486
|
|
|
(186,468
|
)
|
|
(69,253
|
)
|
|||
|
|
|
|
|
|
|
||||||
Financing Activities
|
|
|
|
|
|
|
|
|
|
|||
Proceeds from exercise of stock options
|
|
83
|
|
|
255
|
|
|
168
|
|
|||
Proceeds from issuance of common stock, net of offering costs
|
|
—
|
|
|
53,755
|
|
|
—
|
|
|||
Proceeds from long-term borrowings
|
|
42,000
|
|
|
82,000
|
|
|
68,007
|
|
|||
Payments on long-term borrowings
|
|
(122,826
|
)
|
|
(47,143
|
)
|
|
(6,064
|
)
|
|||
Deferred financing fees
|
|
(110
|
)
|
|
(1,010
|
)
|
|
(69
|
)
|
|||
Other
|
|
(3,536
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash (used in) provided by continuing operations
|
|
(84,389
|
)
|
|
87,857
|
|
|
62,042
|
|
|||
Net cash provided by discontinued operations
|
|
3,375
|
|
|
975
|
|
|
—
|
|
|||
Net cash (used in) provided by financing activities
|
|
(81,014
|
)
|
|
88,832
|
|
|
62,042
|
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
||||||
|
|
Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Effect of exchange rate changes on cash - discontinued operations
|
|
18
|
|
|
—
|
|
|
—
|
|
|||
Increase (decrease) in cash
|
|
3,144
|
|
|
(1,433
|
)
|
|
(232
|
)
|
|||
Cash at beginning of year
|
|
2,061
|
|
|
5,205
|
|
|
3,772
|
|
|||
Cash at end of year
|
|
$
|
5,205
|
|
|
$
|
3,772
|
|
|
$
|
3,540
|
|
|
|
|
|
|
|
|
||||||
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
||||||
Interest paid
|
|
$
|
3,986
|
|
|
$
|
1,970
|
|
|
$
|
3,298
|
|
Income taxes paid
|
|
$
|
391
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Non-cash investing activities:
|
|
|
|
|
|
|
|
|
|
|||
Asset retirement obligation cost and liabilities
|
|
$
|
138
|
|
|
$
|
198
|
|
|
$
|
30
|
|
Asset retirement obligations associated with property acquisitions and dispositions
|
|
$
|
(1,890
|
)
|
|
$
|
(406
|
)
|
|
$
|
410
|
|
|
|
|
2014
|
|
2015
|
||||
|
|
(in thousands)
|
|||||||
Beginning asset retirement obligation
|
|
|
$
|
9,888
|
|
|
$
|
9,495
|
|
New wells placed on production and other
|
|
|
444
|
|
|
307
|
|
||
Deletions related to property disposals and plugging costs
|
|
|
(1,318
|
)
|
|
(793
|
)
|
||
Accretion expense
|
|
|
559
|
|
|
565
|
|
||
Revisions
|
|
|
198
|
|
|
105
|
|
||
Discontinued operations
|
|
|
(276
|
)
|
|
—
|
|
||
Ending asset retirement obligation
|
|
|
$
|
9,495
|
|
|
$
|
9,679
|
|
|
|
December 31,
2014 |
|
December 31,
2015 |
||||
|
|
(In thousands)
|
||||||
Senior secured credit facility
|
|
$
|
70,000
|
|
|
$
|
134,000
|
|
Rig loan agreement
|
|
4,456
|
|
|
2,620
|
|
||
Real estate lien note
|
|
4,333
|
|
|
4,112
|
|
||
|
|
78,789
|
|
|
140,732
|
|
||
Less current maturities
|
|
(2,235
|
)
|
|
(2,330
|
)
|
||
|
|
$
|
76,554
|
|
|
$
|
138,402
|
|
Year ending December 31, (In thousands)
|
|
||
2016
|
$
|
2,330
|
|
2017
|
786
|
|
|
2018
|
134,262
|
|
|
2019
|
273
|
|
|
2020
|
285
|
|
|
Thereafter
|
2,796
|
|
|
|
$
|
140,732
|
|
•
|
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.
|
|
|
Estimated Useful Life
|
|
December 31,
|
||||||
|
|
|
2014
|
|
2015
|
|||||
|
|
Years
|
|
(In thousands)
|
||||||
Oil and gas properties
|
|
—
|
|
$
|
716,922
|
|
|
$
|
787,683
|
|
Equipment and other
|
|
3-39
|
|
18,608
|
|
|
18,866
|
|
||
Drilling rig
|
|
15
|
|
22,075
|
|
|
22,578
|
|
||
|
|
|
|
$
|
757,605
|
|
|
$
|
829,127
|
|
|
|
2013
|
|
2014
|
|
2015
|
||||||
Weighted average value per option granted during the period
|
|
$
|
1.73
|
|
|
$
|
2.44
|
|
|
$
|
2.37
|
|
Assumptions:
|
|
|
|
|
|
|
|
|
|
|||
Forfeiture rate (1)
|
|
4.1
|
%
|
|
4.2
|
%
|
|
4.5
|
%
|
|||
Expected dividend yield (2)
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Volatility (3)
|
|
81.2
|
%
|
|
80.7
|
%
|
|
81.1
|
%
|
|||
Risk free interest rate (4)
|
|
1.24
|
%
|
|
2.05
|
%
|
|
1.92
|
%
|
|||
Expected life (years) (5)
|
|
6.5
|
|
|
6.6
|
|
|
7.0
|
|
|||
Fair value of options granted (in thousands)
|
|
$
|
1,444
|
|
|
$
|
2,666
|
|
|
$
|
3,792
|
|
(4)
|
The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted.
|
(5)
|
The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term.
|
|
|
Options
(000s)
|
|
Weighted average
exercise price
|
|
Weighted
average
remaining life
|
|
Intrinsic
value
per share
|
|||||
Options outstanding December 31, 2012
|
|
4,761
|
|
|
$
|
2.77
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|||||
Granted
|
|
836
|
|
|
2.43
|
|
|
|
|
|
|||
Exercised
|
|
(166
|
)
|
|
1.18
|
|
|
|
|
|
|||
Forfeited/Expired
|
|
(31
|
)
|
|
2.58
|
|
|
|
|
|
|||
Options outstanding December 31, 2013
|
|
5,400
|
|
|
$
|
2.77
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|||||
Granted
|
|
1,091
|
|
|
3.38
|
|
|
|
|
|
|||
Exercised
|
|
(410
|
)
|
|
2.71
|
|
|
|
|
|
|||
Forfeited/Expired
|
|
(196
|
)
|
|
3.08
|
|
|
|
|
|
|||
Options outstanding December 31, 2014
|
|
5,885
|
|
|
$
|
2.88
|
|
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|||||
Granted
|
|
1,601
|
|
|
$
|
3.22
|
|
|
|
|
|
||
Exercised
|
|
(164
|
)
|
|
1.03
|
|
|
|
|
|
|||
Forfeited/Expired
|
|
(514
|
)
|
|
4.36
|
|
|
|
|
|
|||
Options outstanding December 31, 2015
|
|
6,808
|
|
|
$
|
2.89
|
|
|
6.4
|
|
$
|
2.06
|
|
Exercisable at end of year
|
|
4,305
|
|
|
|
|
|
5.1
|
|
$
|
1.97
|
|
|
|
2013
|
|
2014
|
|
2015
|
||||||
Weighted average grant date fair value of stock options granted (per share)
|
|
$
|
1.73
|
|
|
$
|
2.44
|
|
|
$
|
2.37
|
|
Total fair value of options vested (000’s)
|
|
$
|
1,670
|
|
|
$
|
1,718
|
|
|
$
|
2,035
|
|
Total intrinsic value of options exercised (000’s)
|
|
$
|
275
|
|
|
$
|
932
|
|
|
$
|
124
|
|
|
|
Options outstanding
|
|
Exercisable
|
||||||||||||||
|
|
Number
outstanding
|
|
Weighted
average
remaining
life
|
|
Weighted
average
exercise
price
|
|
Number
exercisable
|
|
Weighted
average
remaining
life
|
|
Weighted
average
exercise
price
|
||||||
0.99 - 1.99
|
|
1,519,079
|
|
|
3.99
|
|
$
|
1.54
|
|
|
1,469,079
|
|
|
3.90
|
|
$
|
1.52
|
|
2.00 - 2.99
|
|
1,374,300
|
|
|
6.11
|
|
$
|
2.34
|
|
|
1,073,104
|
|
|
5.76
|
|
$
|
2.32
|
|
3.00 - 3.99
|
|
3,068,600
|
|
|
8.05
|
|
$
|
3.29
|
|
|
936,795
|
|
|
6.39
|
|
$
|
3.53
|
|
4.00 - 4.99
|
|
675,750
|
|
|
|
|
$
|
4.57
|
|
|
659,250
|
|
|
4.70
|
|
$
|
4.58
|
|
5.00 - 5.99
|
|
99,000
|
|
|
8.36
|
|
$
|
5.39
|
|
|
96,750
|
|
|
8.35
|
|
$
|
5.38
|
|
6.00 - 6.28
|
|
71,000
|
|
|
0.26
|
|
$
|
6.05
|
|
|
70,250
|
|
|
0.18
|
|
$
|
6.05
|
|
|
|
6,807,729
|
|
|
|
|
|
|
|
4,305,228
|
|
|
|
|
|
|
|
|
Number
of
Shares
|
|
Weighted
average
grant date
fair value
|
|||
Unvested December 31, 2012
|
|
482,025
|
|
|
$
|
3.09
|
|
Granted
|
|
48,222
|
|
|
2.69
|
|
|
Vested/Released
|
|
(169,700
|
)
|
|
2.66
|
|
|
Forfeited
|
|
(5,307
|
)
|
|
3.08
|
|
|
Unvested December 31, 2013
|
|
355,240
|
|
|
$
|
3.24
|
|
Granted
|
|
1,582,000
|
|
|
3.49
|
|
|
Vested/Released
|
|
(121,622
|
)
|
|
3.64
|
|
|
Forfeited
|
|
(39,528
|
)
|
|
3.44
|
|
|
Unvested December 31, 2014
|
|
1,776,090
|
|
|
$
|
3.43
|
|
Granted
|
|
—
|
|
|
—
|
|
|
Vested/Released
|
|
(127,729
|
)
|
|
3.38
|
|
|
Forfeited
|
|
(5,077
|
)
|
|
2.56
|
|
|
Unvested December 31, 2015
|
|
1,643,284
|
|
|
$
|
3.44
|
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Deferred tax liabilities:
|
|
|
|
|
|
|
||||||
Hedge contracts
|
|
$
|
—
|
|
|
$
|
8,114
|
|
|
$
|
9,578
|
|
Other
|
|
3,152
|
|
|
4,458
|
|
|
4,042
|
|
|||
Total deferred tax liabilities
|
|
3,152
|
|
|
12,572
|
|
|
13,620
|
|
|||
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
|||
U.S. full cost pool
|
|
11,725
|
|
|
3,352
|
|
|
35,689
|
|
|||
Canada full cost pool
|
|
4,081
|
|
|
—
|
|
|
—
|
|
|||
Capital loss carryforward
|
|
—
|
|
|
12,325
|
|
|
7,767
|
|
|||
Depletion carryforward
|
|
4,743
|
|
|
4,936
|
|
|
5,558
|
|
|||
U.S. net operating loss carryforward
|
|
49,667
|
|
|
50,941
|
|
|
67,531
|
|
|||
Canada net operating loss carryforward
|
|
5,736
|
|
|
—
|
|
|
—
|
|
|||
Alternative minimum tax credit
|
|
1,369
|
|
|
1,104
|
|
|
757
|
|
|||
Hedge contracts
|
|
1,397
|
|
|
—
|
|
|
—
|
|
|||
Total deferred tax assets
|
|
78,718
|
|
|
72,658
|
|
|
117,302
|
|
|||
Valuation allowance for deferred tax assets
|
|
(75,566
|
)
|
|
(60,086
|
)
|
|
(103,682
|
)
|
|||
Net deferred tax assets
|
|
3,152
|
|
|
12,572
|
|
|
13,620
|
|
|||
Net deferred tax
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|||
Federal
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Foreign
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Years ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Tax (expense) benefit at U.S. statutory rates (35%)
|
|
$
|
(13,771
|
)
|
|
$
|
(22,044
|
)
|
|
$
|
44,586
|
|
(Increase) decrease in deferred tax asset valuation allowance
|
|
14,146
|
|
|
15,480
|
|
|
(43,596
|
)
|
|||
Alternative minimum tax
|
|
—
|
|
|
—
|
|
|
568
|
|
|||
Rate differential for non US income
|
|
(574
|
)
|
|
(39
|
)
|
|
—
|
|
|||
State income taxes
|
|
(47
|
)
|
|
—
|
|
|
—
|
|
|||
Accrual of prior year federal taxes (2009 and 2013)
|
|
(81
|
)
|
|
287
|
|
|
37
|
|
|||
Permanent differences
|
|
(743
|
)
|
|
(950
|
)
|
|
(1,371
|
)
|
|||
Return to provision estimate revision
|
|
—
|
|
|
4,562
|
|
|
—
|
|
|||
Tax benefit related to the sale of Canadian subsidiary
|
|
—
|
|
|
3,501
|
|
|
—
|
|
|||
Increase in asset for partnership distribution
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Other
|
|
370
|
|
|
(510
|
)
|
|
55
|
|
|||
|
|
$
|
(700
|
)
|
|
$
|
287
|
|
|
$
|
279
|
|
|
|
Years ended December 31:
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands, except per share data)
|
||||||||||
Numerator:
|
|
|
|
|
|
|
||||||
Net income (loss) from continuing operations
|
|
$
|
46,841
|
|
|
$
|
61,951
|
|
|
$
|
(127,090
|
)
|
Net (loss) income from discontinued operations
|
|
(8,194
|
)
|
|
1,318
|
|
|
(20
|
)
|
|||
|
|
$
|
38,647
|
|
|
$
|
63,269
|
|
|
$
|
(127,110
|
)
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|||
Denominator for basic earnings per share – weighted-average common shares outstanding
|
|
92,451
|
|
|
98,835
|
|
|
104,605
|
|
|||
Effect of dilutive securities:
Stock options and restricted shares
|
|
1,087
|
|
|
2,633
|
|
|
—
|
|
|||
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options and restricted shares
|
|
93,538
|
|
|
101,468
|
|
|
104,605
|
|
|||
|
|
|
|
|
|
|
||||||
Net income (loss) per common share - basic
|
|
|
|
|
|
|
||||||
Continuing operations
|
|
$
|
0.51
|
|
|
$
|
0.63
|
|
|
$
|
(1.21
|
)
|
Discontinued operations
|
|
(0.09
|
)
|
|
0.01
|
|
|
—
|
|
|||
|
|
$
|
0.42
|
|
|
$
|
0.64
|
|
|
$
|
(1.21
|
)
|
|
|
|
|
|
|
|
||||||
Net income (loss) per common share - diluted
|
|
|
|
|
|
|
||||||
Continuing operations
|
|
$
|
0.50
|
|
|
$
|
0.61
|
|
|
$
|
(1.21
|
)
|
Discontinued operations
|
|
(0.09
|
)
|
|
0.01
|
|
|
—
|
|
|||
|
|
$
|
0.41
|
|
|
$
|
0.62
|
|
|
$
|
(1.21
|
)
|
|
|
1
st
Quarter
|
|
2
nd
Quarter
|
|
3
rd
Quarter
|
|
4
th
Quarter
|
||||||||
|
|
(In thousands, except per share data)
|
||||||||||||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
||||||||
Net revenue
|
|
$
|
25,518
|
|
|
$
|
33,192
|
|
|
$
|
43,874
|
|
|
$
|
31,192
|
|
Operating income
|
|
$
|
7,695
|
|
|
$
|
12,603
|
|
|
$
|
16,783
|
|
|
$
|
2,842
|
|
Net income
|
|
$
|
4,704
|
|
|
$
|
3,034
|
|
|
$
|
25,399
|
|
|
$
|
30,132
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net income per common share – basic
|
|
$
|
0.05
|
|
|
$
|
0.03
|
|
|
$
|
0.24
|
|
|
$
|
0.29
|
|
Net income per common share – diluted
|
|
$
|
0.05
|
|
|
$
|
0.03
|
|
|
$
|
0.24
|
|
|
$
|
0.28
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
||||||||
Net revenue
|
|
$
|
18,661
|
|
|
$
|
18,944
|
|
|
$
|
16,077
|
|
|
$
|
13,348
|
|
Operating loss
|
|
$
|
(4,535
|
)
|
|
$
|
(1,531
|
)
|
|
$
|
(63,438
|
)
|
|
$
|
(72,301
|
)
|
Net loss
|
|
$
|
(718
|
)
|
|
$
|
(6,601
|
)
|
|
$
|
(52,372
|
)
|
|
$
|
(67,419
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Net loss per common share – basic
|
|
$
|
(0.01
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.50
|
)
|
|
$
|
(0.64
|
)
|
Net loss per common share – diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.50
|
)
|
|
$
|
(0.64
|
)
|
|
|
Oil - WTI
|
|
|
Contract Periods
|
|
Daily Volume (Bbl)
|
|
Swap Price (per Bbl)
|
|
|
|||
2016
|
|
948
|
|
|
$
|
84.10
|
|
|
|
2017
|
|
608
|
|
|
$
|
78.55
|
|
|
|
|
|
Daily Volume (Bbl)
|
|
Floor (Long Put)
|
|
Ceiling (Short Call)
|
|
Short Put
|
|||||||
2016
|
|
1,000
|
|
|
$
|
60.00
|
|
|
$
|
71.00
|
|
|
$
|
45.00
|
|
Fair Value of Derivative Instruments as of December 31, 2015
|
||||||||||||
|
|
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
|
|
$
|
18,902
|
|
|
Derivatives – current
|
|
$
|
—
|
|
Commodity price derivatives
|
|
Derivatives – long-term
|
|
8,463
|
|
|
Derivatives – long-term
|
|
—
|
|
||
|
|
|
|
$
|
27,365
|
|
|
|
|
$
|
—
|
|
•
|
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.
|
|
|
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,
2014
|
||||||||
Assets:
|
|
|
|
|
|
|
|
|
||||||||
NYMEX Fixed Price Derivative contracts
|
|
$
|
—
|
|
|
$
|
23,195
|
|
|
$
|
—
|
|
|
$
|
23,195
|
|
Total Assets
|
|
$
|
—
|
|
|
$
|
23,195
|
|
|
$
|
—
|
|
|
$
|
23,195
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
NYMEX Fixed Price Derivative contracts
|
|
$
|
—
|
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
13
|
|
Total Liabilities
|
|
$
|
—
|
|
|
$
|
13
|
|
|
$
|
—
|
|
|
$
|
13
|
|
|
|
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,
2015
|
||||||||
Assets:
|
|
|
|
|
|
|
|
|
||||||||
NYMEX Fixed Price Derivative contracts
|
|
$
|
—
|
|
|
$
|
21,731
|
|
|
$
|
—
|
|
|
$
|
21,731
|
|
NYMEX Collars
|
|
—
|
|
|
—
|
|
|
5,634
|
|
|
5,634
|
|
||||
Total Assets
|
|
$
|
—
|
|
|
$
|
21,731
|
|
|
$
|
5,634
|
|
|
$
|
27,365
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
NYMEX Fixed Price Derivative contracts
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total Liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
(In thousands)
|
||
Unobservable inputs at January 1, 2015
|
|
$
|
—
|
|
Changes in market value
|
|
8,474
|
|
|
Settlements during the period
|
|
(2,840
|
)
|
|
Unobservable inputs at December 31, 2015
|
|
$
|
5,634
|
|
|
|
|
|
October 31, 2014
|
|
|
|
|
|
|
|||
Current assets
|
|
|
|
$
|
252
|
|
|
|
|
|
|
||
Oil and gas properties - net
|
|
|
|
659
|
|
|
|
|
|
|
|
||
Other assets
|
|
|
|
—
|
|
|
Total assets
|
|
|
|
911
|
|
|
|
|
|
|
|
||
Accounts payable
|
|
|
|
275
|
|
|
|
|
|
|
|
||
Accrued expenses
|
|
|
|
280
|
|
|
Total liabilities
|
|
|
|
555
|
|
|
|
|
|
|
|
||
Net assets of discontinued operation
|
|
|
|
$
|
356
|
|
Contract Periods
|
|
Daily Volume (Bbl)
|
|
Swap Price (per Bbl)
|
|||
2016 (October - December)
|
|
2,500
|
|
|
$
|
43.25
|
|
2017
|
|
1,300
|
|
|
$
|
44.55
|
|
2018
|
|
1,500
|
|
|
$
|
46.39
|
|
|
|
Years Ended December 31
|
||||||
|
|
2014
|
|
2015
|
||||
|
|
(In thousands)
|
||||||
Proved oil and gas properties
|
|
$
|
716,922
|
|
|
$
|
787,683
|
|
Unproved properties
|
|
—
|
|
|
—
|
|
||
Total
|
|
716,922
|
|
|
787,683
|
|
||
Accumulated depreciation, depletion, amortization and impairment
|
|
(423,819
|
)
|
|
(590,432
|
)
|
||
Net capitalized costs
|
|
$
|
293,103
|
|
|
$
|
197,251
|
|
|
|
Years Ended December 31
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Development costs
|
|
$
|
93,878
|
|
|
$
|
189,322
|
|
|
$
|
68,631
|
|
Exploration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Property acquisition costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Unproved
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
|
|
$
|
93,878
|
|
|
$
|
189,322
|
|
|
$
|
68,631
|
|
|
|
|
|||||||||||
|
|
Years Ended December 31,
|
|||||||||||
|
|
2013
|
|
2014
|
|
2015
|
|
||||||
|
|
(In thousands)
|
|||||||||||
Revenues
|
|
$
|
94,275
|
|
|
$
|
134,883
|
|
|
$
|
67,002
|
|
|
Production costs
|
|
(33,871
|
)
|
|
(38,146
|
)
|
|
(29,753
|
)
|
|
|||
Depreciation, depletion, and amortization
|
|
(26,072
|
)
|
|
(42,945
|
)
|
|
(38,040
|
)
|
|
|||
Proved property impairment
|
|
(6,025
|
)
|
|
—
|
|
|
(128,573
|
)
|
|
|||
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)
|
|
$
|
28,307
|
|
|
$
|
53,792
|
|
|
$
|
(129,364
|
)
|
|
Depletion rate per barrel of oil equivalent
|
|
$
|
16.59
|
|
|
$
|
20.39
|
|
|
$
|
17.44
|
|
|
|
|
Oil
|
|
NGL
|
|
Gas
|
|
Oil
Equivalents
|
|
||||
|
|
(MBbl)
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBoe)
|
|
||||
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
||||
Balance at December 31, 2012
|
|
17,342
|
|
|
2,614
|
|
|
61,184
|
|
|
30,152
|
|
|
Revisions of previous estimates
|
|
797
|
|
|
202
|
|
|
(5,123
|
)
|
|
145
|
|
|
Extensions and discoveries
|
|
10,411
|
|
|
335
|
|
|
3,610
|
|
|
11,348
|
|
|
Sales of minerals in place
|
|
(6,785
|
)
|
|
(963
|
)
|
|
(8,141
|
)
|
|
(9,105
|
)
|
|
Production
|
|
(850
|
)
|
|
(150
|
)
|
|
(3,421
|
)
|
|
(1,570
|
)
|
|
Balance at December 31, 2013
|
|
20,915
|
|
|
2,038
|
|
|
48,109
|
|
|
30,970
|
|
|
Revisions of previous estimates
|
|
2,697
|
|
|
1,021
|
|
|
7,383
|
|
|
4,950
|
|
|
Extensions and discoveries
|
|
7,780
|
|
|
868
|
|
|
6,893
|
|
|
9,797
|
|
|
Sales of minerals in place
|
|
(608
|
)
|
|
(12
|
)
|
|
(3,614
|
)
|
|
(1,223
|
)
|
|
Production
|
|
(1,394
|
)
|
|
(207
|
)
|
|
(2,918
|
)
|
|
(2,088
|
)
|
|
Balance at December 31, 2014
|
|
29,390
|
|
|
3,708
|
|
|
55,853
|
|
|
42,406
|
|
|
Revisions of previous estimates
|
|
(9,301
|
)
|
|
(389
|
)
|
|
(7,017
|
)
|
|
(10,859
|
)
|
|
Extensions and discoveries
|
|
5,495
|
|
|
3,475
|
|
|
29,387
|
|
|
13,867
|
|
|
Sales of minerals in place
|
|
(13
|
)
|
|
—
|
|
|
(181
|
)
|
|
(43
|
)
|
|
Production
|
|
(1,440
|
)
|
|
(238
|
)
|
|
(3,015
|
)
|
|
(2,181
|
)
|
|
Balance at December 31, 2015
|
|
24,131
|
|
|
6,556
|
|
|
75,027
|
|
|
43,190
|
|
|
|
|
Total
|
|
|
|
Oil
|
|
NGL
|
|
Gas
|
|
Oil
Equivalents
|
|
||||
|
|
(MBbl)
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBoe)
|
|
||||
|
|
(In thousands)
|
|||||||||||
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2013
|
|
6,846
|
|
|
1,464
|
|
|
31,572
|
|
|
13,572
|
|
|
December 31, 2014
|
|
10,162
|
|
|
2,006
|
|
|
34,677
|
|
|
17,948
|
|
|
December 31, 2015
|
|
10,022
|
|
|
1,956
|
|
|
31,298
|
|
|
17,194
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2013
|
|
14,068
|
|
|
572
|
|
|
16,537
|
|
|
17,397
|
|
|
December 31, 2014
|
|
19,228
|
|
|
1,702
|
|
|
21,176
|
|
|
24,459
|
|
|
December 31, 2015
|
|
14,109
|
|
|
4,599
|
|
|
43,729
|
|
|
25,996
|
|
|
|
|
|
|||||||||||
|
|
Years Ended December 31,
|
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
|
||||||
|
|
(In thousands)
|
|
||||||||||
Future cash inflows
|
|
$
|
2,244,846
|
|
|
$
|
2,988,464
|
|
|
$
|
1,241,334
|
|
|
Future production costs
|
|
(754,722
|
)
|
|
(921,977
|
)
|
|
(438,784
|
)
|
|
|||
Future development costs
|
|
(467,206
|
)
|
|
(557,782
|
)
|
|
(338,316
|
)
|
|
|||
Future income tax expense
|
|
(244,394
|
)
|
|
(373,095
|
)
|
|
—
|
|
|
|||
Future net cash flows
|
|
778,524
|
|
|
1,135,610
|
|
|
464,234
|
|
|
|||
Discount
|
|
(437,539
|
)
|
|
(623,053
|
)
|
|
(266,983
|
)
|
|
|||
Standardized Measure of discounted future net cash relating to proved reserves
|
|
$
|
340,985
|
|
|
$
|
512,557
|
|
|
$
|
197,251
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
|
|
(In thousands)
|
||||||||||
Standardized Measure, beginning of year
|
|
$
|
278,145
|
|
|
$
|
340,985
|
|
|
$
|
512,557
|
|
Sales and transfers of oil and gas produced, net of production costs
|
|
(60,403
|
)
|
|
(96,364
|
)
|
|
(37,249
|
)
|
|||
Net change in prices and development and production costs from prior year
|
|
169,969
|
|
|
150,504
|
|
|
(488,160
|
)
|
|||
Extensions, discoveries, and improved recovery, less related costs
|
|
156,456
|
|
|
147,275
|
|
|
63,341
|
|
|||
Sales of minerals in place
|
|
(125,533
|
)
|
|
(15,042
|
)
|
|
(197
|
)
|
|||
Revisions of previous quantity estimates
|
|
2,930
|
|
|
74,390
|
|
|
(49,602
|
)
|
|||
Change in timing and other
|
|
(62,861
|
)
|
|
(82,653
|
)
|
|
20,419
|
|
|||
Change in future income tax expense
|
|
(45,532
|
)
|
|
(40,636
|
)
|
|
124,886
|
|
|||
Accretion of discount
|
|
27,814
|
|
|
34,098
|
|
|
51,256
|
|
|||
Standardized Measure, end of year
|
|
$
|
340,985
|
|
|
$
|
512,557
|
|
|
$
|
197,251
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2014
|
|
2015
|
||||||
Oil (per Bbl) (1)
|
|
$
|
97.33
|
|
|
$
|
95.28
|
|
|
$
|
50.12
|
|
Gas (per MMbtu) (2)
|
|
$
|
3.67
|
|
|
$
|
4.35
|
|
|
$
|
2.63
|
|
Oil (per Bbl) (3)
|
|
$
|
95.90
|
|
|
$
|
87.11
|
|
|
$
|
41.25
|
|
Gas (per MMBtu) (4)
|
|
$
|
3.65
|
|
|
$
|
5.15
|
|
|
$
|
2.36
|
|
NGL’s (per Bbl) (5)
|
|
$
|
31.98
|
|
|
$
|
37.91
|
|
|
$
|
10.52
|
|
(1)
|
The quoted oil price for the year ended December 31 of each year, 2013, 2014 and 2015 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2013, 2014 and 2015.
|
(2)
|
The quoted gas price for the year ended December 31, 2013, 2014 and 2015 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2013, 2014 and 2015.
|
(3)
|
The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
|
(4)
|
The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
|
(5)
|
The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.
|
21.1
|
Subsidiaries of Abraxas Petroleum Corporation (Filed herewith).
|
23.1
|
Consent of BDO USA, LLP. (Filed herewith).
|
23.2
|
Consent of DeGolyer & MacNaughton. (Filed herewith).
|
31.1
|
Certification – Chief Executive Officer. (Filed herewith).
|
31.2
|
Certification – Chief Financial Officer. (Filed herewith).
|
32.1
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
|
32.2
|
Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
|
99.1
|
Report of DeGolyer and MacNaughton with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).
|
Name and address of Subsidiary
|
Jurisdiction of Incorporation/
Type of Entity |
Abraxas Properties Incorporated
18803 Meisner Drive San Antonio, Texas 78258 |
Texas/
Corporation |
Sandia Operating Corp.
18803 Meisner Drive San Antonio, Texas 78258 |
Texas/
Corporation |
Raven Drilling, LLC
18803 Meisner Drive San Antonio, Texas 78258 |
Texas/
Limited Liability Company |
1.
|
I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.
|
2.
|
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
1.
|
I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.
|
2.
|
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
|
Net Reserves
Estimated by
DeGolyer and MacNaughton
as of December 31, 2015
|
||||||||
|
|
Oil and
Condensate
(Mbbl)
|
|
NGL
(Mbbl)
|
|
Sales
Gas
(MMcf)
|
|
Oil
Equivalent
(Mboe)
|
||
|
|
|
|
|
|
|
|
|
||
Proved
|
|
|
|
|
|
|
|
|
||
Developed Producing
|
|
7,091
|
|
1,537
|
|
24,632
|
|
12,734
|
||
Developed Nonproducing
|
|
2,477
|
|
305
|
|
4,388
|
|
3,513
|
||
Undeveloped
|
|
14,109
|
|
4,598
|
|
43,729
|
|
25,995
|
||
|
|
|
|
|
|
|
|
|
||
Total Proved
|
|
23,677
|
|
6,440
|
|
72,749
|
|
42,242
|
||
|
|
|
|
|
|
|
|
|
||
Probable
|
|
|
|
|
|
|
|
|
||
Developed Nonproducing
|
|
66
|
|
0
|
|
345
|
|
123
|
||
Undeveloped
|
|
4,498
|
|
2,707
|
|
43,582
|
|
14,469
|
||
|
|
|
|
|
|
|
|
|
||
Total Probable
|
|
4,564
|
|
2,707
|
|
43,927
|
|
14,592
|
||
|
|
|
|
|
|
|
|
|
||
Possible
|
|
|
|
|
|
|
|
|
||
Undeveloped
|
|
0
|
|
0
|
|
9,054
|
|
1,509
|
||
|
|
|
|
|
|
|
|
|
||
Total Possible
|
|
0
|
|
0
|
|
9,054
|
|
1,509
|
||
|
|
|
|
|
|
|
|
|
||
Notes:
1. Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.
2. Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
|
|
|
Possible
Undeveloped
|
|
Total
Possible
|
|
|
|
|
|
Future Gross Revenue, M$
|
|
20,622
|
|
20,622
|
Production and Ad Valorem Taxes, M$
|
|
2,220
|
|
2,220
|
Operating Expenses, M$
|
|
2,820
|
|
2,820
|
Capital Costs, M$
|
|
5,200
|
|
5,200
|
Abandonment Costs, M$
|
|
60
|
|
60
|
Future Net Revenue, M$
|
|
10,322
|
|
10,322
|
Present Worth at 10 Percent, M$
|
|
2,575
|
|
2,575
|
|
|
|
|
|
Notes:
1. Future income taxes have not been taken into account in the preparation of these estimates.
2. Values for possible reserves have not been risk adjusted to make them comparable to values for proved reserves.
|
1.
|
That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Abraxas dated February 8, 2016, and that I, as Senior Vice President, was responsible for the preparation of this letter report.
|
2.
|
That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 41 years of experience in oil and gas reservoir studies and reserves evaluations.
|