x |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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r |
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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Preferred Stock Purchase Rights
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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 2013 Annual Meeting of Stockholders to be held on May 14, 2013.
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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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5
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Item 1A.
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15
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Item 1B.
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29
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Item 2.
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29
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Item 3.
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37
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Item 4.
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37
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Part II
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Item 5.
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38
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Item 6.
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40
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Item 7.
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40
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Item 7A.
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57
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Item 8.
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58
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Item 9.
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58
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Item 9A.
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58
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Item 9B.
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59
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Part III
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Item 10.
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59
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Item 11.
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59
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Item 12.
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59
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Item 13.
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60
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Item 14.
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60
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Part IV
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||
Item 15.
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61
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·
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the availability of capital;
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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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our ability to procure services and equipment for our drilling and completion activities;
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·
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our ability to make planned capital expenditures;
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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 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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|||||||||||||||||||||||||||
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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1,065 | 10.26 | % | 60,016 | 14,980.4 | 81.6 | % | 560.0 | 76.1 | % | ||||||||||||||||||
Mid-Continent
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147 | 22.53 | % | 5,820 | 392.7 | 37.1 | % | 53.3 | 16.8 | % | ||||||||||||||||||
Permian Basin
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220 | 74.81 | % | 42,093 | 7,130.1 | 39.2 | % | 472.1 | 41.5 | % | ||||||||||||||||||
Onshore Gulf Coast
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64 | 87.52 | % | 11,468 | 7,264.7 | 63.2 | % | 297.7 | 29.6 | % | ||||||||||||||||||
Total United States
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1,496 | 24.26 | % | 119,397 | 29,767.9 | 66.4 | % | 1,383.1 | 52.0 | % | ||||||||||||||||||
Alberta, Canada (1)
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8 | 100.00 | % | 29,440 | 385.9 | 53.1 | % | 54.0 | 64.6 | % | ||||||||||||||||||
Total
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1,504 | 24.67 | % | 148,837 | 30,153.8 | 66.2 | % | 1,437.1 | 52.5 | % |
(1)
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Excludes approximately 22,000 acres subject to a farmout agreement.
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2013 Budget and Drilling Activities
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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 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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restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities;
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·
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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species and other protected areas;
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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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restrict injection of liquids into subsurface strata that may contaminate groundwater; and
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·
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impose substantial penalties for pollution resulting from our operations.
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·
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effecting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes which may be impaired or not available on favorable terms;
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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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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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prevailing and anticipated prices for oil and gas;
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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 drilling locations; and
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·
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lease expirations and continuing development obligations.
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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 flows of oil or gas or well fluids.
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·
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, shoreline contamination, underground migration and surface spills or mishandling of fracturing fluids, including chemical additives;
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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, natural gas liquids and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, including hydraulic fracturing, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment or processing or other facilities in the Company’s operations or at delivery points to third parties;
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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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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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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;
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·
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price and level of foreign imports;
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·
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terrorist activity;
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·
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availability of pipeline and other secondary capacity;
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·
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general economic conditions;
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·
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domestic and foreign governmental regulation; and
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·
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the price and availability of alternative fuel sources.
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·
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fluctuations in commodity prices;
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·
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variations in results of operations;
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·
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legislative or regulatory changes;
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·
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general trends in the oil and gas industry;
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·
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sales of common stock or other actions by our stockholders;
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·
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additions or departures of key management personnel;
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·
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commencement of or involvement in litigation;
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·
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speculation in the press or investment community regarding our business;
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·
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an inability to maintain the listing of our common stock on a national securities exchange;
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·
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market conditions; and
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·
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analysts’ estimates and other events in the oil and gas industry.
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Item 1B. Unresolved Staff Comments
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Developed
Acreage
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Undeveloped Acreage
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Fee Mineral
Acreage (1)
|
||||||||||||||||||||||||||
Gross
Acres
|
Net
Acres
|
Gross
Acres
|
Net
Acres
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Gross
Acres
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Net
Acres
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Total
Net
Acres (2)
|
||||||||||||||||||||||
Rocky Mountain
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72,194 | 33,496 | 85,957 | 36,396 | 1,721 | 851 | 70,743 | |||||||||||||||||||||
Mid-Continent
|
24,1080 | 5,524 | 5,878 | 296 | — | — | 5,820 | |||||||||||||||||||||
Permian Basin
|
24,408 | 17,441 | 21,430 | 19,379 | 12,007 | 5,272 | 42,092 | |||||||||||||||||||||
Onshore Gulf Coast
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10,652 | 6,181 | 6,824 | 5,287 | — | — | 11,468 | |||||||||||||||||||||
Total United States
|
131,362 | 62,642 | 120,089 | 61,358 | 13,728 | 6,123 | 130,123 | |||||||||||||||||||||
Alberta, Canada (3)
|
2,240 | 2,240 | 27,200 | 27,200 | — | — | 29,440 | |||||||||||||||||||||
Total
|
133,602 | 64,882 | 147,289 | 88,558 | 13,728 | 6,123 | 159,563 |
|
_______________
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|
(1)
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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 3,981 acres in the Permian Basin region that are included in both developed and undeveloped gross acres.
|
|
(3)
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Excludes approximately 22,000 acres subject to a farmout agreement.
|
Productive Wells
|
||||||||||||||||
Oil
|
Gas
|
|||||||||||||||
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||
Rocky Mountain
|
558.0 | 93.4 | 507.0 | 15.9 | ||||||||||||
Mid-Continent
|
6.0 | 3.5 | 141.0 | 29.6 | ||||||||||||
Permian Basin
|
161.0 | 133.4 | 59.0 | 31.2 | ||||||||||||
Onshore Gulf Coast
|
33.5 | 33.5 | 30.5 | 22.5 | ||||||||||||
Total United States
|
758.5 | 263.8 | 737.5 | 99.2 | ||||||||||||
Alberta, Canada
|
8.0 | 8.0 | — | — | ||||||||||||
Total
|
766.5 | 271.8 | 737.5 | 99.2 |
Summary of Oil, NGL and Gas Reserves
As of December 31, 2012
|
||||||||||||||||
Reserve Category
|
Oil
(MBbls)
|
NGL
(MBbls)
|
Gas
(MMcf)
|
Oil
Equivalents (MBoe)
|
||||||||||||
Proved
|
||||||||||||||||
Developed
|
7,331.9 | 1,318.2 | 41,220.3 | 15,520.1 | ||||||||||||
Undeveloped
|
10,009.8 | 1,296.5 | 19,964.0 | 14,633.7 | ||||||||||||
Total Proved
|
17,341.7 | 2,614.7 | 61,184.3 | 30,153.8 | ||||||||||||
Probable
|
||||||||||||||||
Developed Producing
|
16.8 | 4.0 | 24.3 | 24.8 | ||||||||||||
Developed Non-producing
|
66.3 | 0.7 | 369.6 | 128.6 | ||||||||||||
Undeveloped
|
12,265.2 | 2,594.8 | 58,394.4 | 24,592.5 | ||||||||||||
Total Probable
|
12,348.3 | 2,599.5 | 58,788.3 | 24,745.9 | ||||||||||||
Possible
|
||||||||||||||||
Undeveloped
|
10,554.9 | 1,176.8 | 17,577.6 | 14,661.3 | ||||||||||||
Total
|
40,244.9 | 6,391.0 | 137,550.2 | 69,561.0 |
MMBoe
|
||||
PUDs at December 31, 2011
|
11,376 | |||
Revisions of prior estimates
|
(313 | ) | ||
Extensions, discoveries, and other additions
|
5,968 | |||
Conversion to developed
|
(1,030 | ) | ||
Sales
|
(1,368 | ) | ||
PUDs at December 31, 2012
|
14,633 |
December 31,
|
||||||||
(in thousands)
|
2011
|
2012
|
||||||
PV-10
|
$ | 298,001 | $ | 316,862 | ||||
Present value of future income taxes discounted at 10%
|
(28,919 | ) | (38,717 | ) | ||||
Standardized measure of discounted future net cash flows
|
$ | 269,082 | $ | 278,145 |
2010
|
2011
|
2012
|
||||||
Oil production (Bbls)
|
||||||||
Rocky Mountain
|
286,114
|
310,819
|
402,869
|
|||||
Permian Basin
|
107,763
|
113,151
|
113,691
|
|||||
Onshore Gulf Coast
|
75,571
|
93,182
|
86,107
|
|||||
Other (4)
|
29,260
|
22,738
|
40,825
|
|||||
Total
|
498,708
|
539,890
|
643,492
|
|||||
Gas production (Mcf)
|
||||||||
Rocky Mountain
|
570,736
|
474,269
|
802,001
|
|||||
Permian Basin
|
2,135,918
|
1,891,333
|
1,657,165
|
|||||
Onshore Gulf Coast
|
1,757,901
|
1,482,260
|
1,257,124
|
|||||
Other (4)
|
1,014,347
|
373,970
|
380,789
|
|||||
Total
|
5,478,902
|
4,221,832
|
4,097,079
|
|||||
NGL production (Bbls)
|
||||||||
Rocky Mountain
|
4,228
|
11,451
|
23,468
|
|||||
Permian Basin
|
278
|
15,171
|
82,200
|
|||||
Onshore Gulf Coast
|
79
|
231
|
2,036
|
|||||
Other (4)
|
5,624
|
1,271
|
3,047
|
|||||
Total
|
10,209
|
28,124
|
110,751
|
|||||
Total production (MBoe) (1)
|
1,422
|
1,272
|
1,437
|
|||||
Average sales price per Bbl of oil (2)
|
||||||||
Rocky Mountain
|
$
|
68.79
|
$
|
85.73
|
$
|
81.61
|
||
Permian Basin
|
$
|
75.94
|
$
|
91.07
|
$
|
87.97
|
||
Onshore Gulf Coast
|
$
|
77.32
|
$
|
97.09
|
$
|
100.31
|
||
Other (4)
|
$
|
76.13
|
$
|
91.62
|
$
|
79.66
|
||
Composite
|
$
|
71.37
|
$
|
89.06
|
$
|
85.11
|
Average sales price per Mcf of gas (2)
|
||||||||
Rocky Mountain
|
$
|
4.28
|
$
|
3.77
|
$
|
2.71
|
||
Permian Basin
|
$
|
4.00
|
$
|
3.81
|
$
|
2.45
|
||
Onshore Gulf Coast
|
$
|
3.62
|
$
|
3.31
|
$
|
2.14
|
||
Other (4)
|
$
|
4.32
|
$
|
3.28
|
$
|
2.00
|
||
Composite
|
$
|
3.97
|
$
|
3.58
|
$
|
2.36
|
||
Average sales price per Bbl of NGL
|
||||||||
Rocky Mountain
|
$
|
42.03
|
$
|
49.71
|
$
|
37.27
|
||
Permian Basin
|
$
|
34.48
|
$
|
48.27
|
$
|
35.45
|
||
Onshore Gulf Coast
|
$
|
38.03
|
$
|
45.75
|
$
|
27.52
|
||
Other (4)
|
$
|
34.79
|
$
|
75.69
|
$
|
67.28
|
||
Composite
|
$
|
37.81
|
$
|
50.08
|
$
|
36.57
|
||
Average sales price per Boe (2)
|
$
|
40.82
|
$
|
50.81
|
$
|
47.67
|
||
Average cost of production per Boe produced (3)
|
||||||||
Rocky Mountain
|
$
|
17.34
|
$
|
19.58
|
$
|
17.41
|
||
Permian Basin
|
$
|
11.88
|
$
|
13.16
|
$
|
13.11
|
||
Onshore Gulf Coast
|
$
|
6.06
|
$
|
7.81
|
$
|
8.55
|
||
Other (4)
|
$
|
9.36
|
$
|
16.89
|
$
|
18.90
|
||
Composite
|
$
|
13.81
|
$
|
16.94
|
$
|
14.27
|
|
(1)
|
Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil.
|
|
(2)
|
Before the impact of hedging activities.
|
|
(3)
|
Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.
|
|
(4)
|
Includes Canada and Mid-Continent comprising approximately 7.5% of total production.
|
2010 (1)
|
2011 (2)
|
2012
|
||||||||||||||||||||||
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
Exploratory
|
||||||||||||||||||||||||
Productive
|
||||||||||||||||||||||||
Rocky Mountain
|
1.0 | 1.0 | 2.0 | 1.1 | — | — | ||||||||||||||||||
Permian Basin
|
1.0 | 0.4 | 1.0 | 1.0 | — | — | ||||||||||||||||||
Onshore Gulf Coast
|
— | — | — | — | — | — | ||||||||||||||||||
Other (3)
|
— | — | — | —- | — | —- | ||||||||||||||||||
Total
|
2.0 | 1.4 | 3.0 | 2.1 | — | — | ||||||||||||||||||
Dry wells
|
||||||||||||||||||||||||
Permian Basin
|
— | — | 1.0 | 1.0 | — | — | ||||||||||||||||||
Onshore Gulf Coast
|
1.0 | 1.0 | — | — | — | — | ||||||||||||||||||
Total
|
1.0 | 1.0 | 1.0 | 1.0 | — | — | ||||||||||||||||||
Development
|
||||||||||||||||||||||||
Productive
|
||||||||||||||||||||||||
Rocky Mountain
|
16.0 | 1.8 | 12.0 | 1.2 | 22.0 | 2.6 | ||||||||||||||||||
Permian Basin
|
2.0 | 2.0 | 2.0 | 2.0 | 1.0 | 1.0 | ||||||||||||||||||
Onshore Gulf Coast
|
3.0 | 3.0 | 7.0 | 7.0 | 2.0 | 0.5 | ||||||||||||||||||
Other (3)
|
3.0 | 2.0 | 4.0 | 4.0 | — | — | ||||||||||||||||||
Total
|
24.0 | 8.8 | 25.0 | 14.2 | 25.0 | 4.1 |
|
__________________
|
(1)
|
Excludes 1.0 gross (1.0 net) well drilled by Blue Eagle.
|
(2)
|
Excludes 2.0 gross (1.4 net) wells drilled by Blue Eagle.
|
(3)
|
Includes drilling activities in Canada and Mid-Continent.
|
Present Activities
|
·
|
In the Bakken/Three Forks play in the Williston Basin, in the fourth quarter of 2012 we completed the drilling of our first multi-well pad with our Company owned drilling rig. The Jore Federal 02-11 3H was the first completion off this pad and was turned to sales in October 2012. We own a 76% working interest in the Jore Federal 02-11 3H. Two additional wells on this pad, the Ravin 26-35 2H and Ravin 26-35 3H, suffered third party equipment failures during the completion process. Post remediation, the Ravin 26-35 2H and Ravin 26-35 3H were completed and turned to sales in February 2013.
|
·
|
In October 2012, we mobilized our Company owned rig to the Lillibridge East pad to commence a four well drilling program. Surface and intermediate casing have been set on all four Lillibridge wells. We also drilled and cased the lateral on the Lillibridge 20-17 4H. The rig is currently mobilizing to drill the lateral of the Lillibridge 20-17 3H, which will be followed by laterals of the Lillibridge 20-17 2H and Lillibridge 20-17 1H. We own an approximate 34% working interest across all four wells on the Lillibridge East pad.
|
·
|
In the non-operated portion of the Company’s Bakken/Three Forks position in the Williston Basin, we have participated in 15 gross (.8 net) non-operated wells since the fourth quarter of 2012.
|
·
|
In the WyCross area of McMullen County, Texas, we drilled and completed two gross (.44 net) wells targeting the Eagle Ford Shale during the fourth quarter of 2012. Subsequent to the fourth quarter of 2012, we drilled and completed an additional two gross (.44 net) wells. Our sixth well at WyCross, the Mustang 3H is currently in the latter stages of completion. Abraxas owns an approximate 18.75% working interest in the Mustang 3H. The Company recently reached total depth on our seventh well at WyCross, the Mustang 2H, in which we hold an 18.75% working interest. We anticipate maintaining a one rig program at WyCross throughout 2013.
|
·
|
In Ward County, Texas, we recently drilled and cased two gross (two net) shallow Yates wells, the Wilkes No.1 and Wilkes No.2, since the fourth quarter of 2012. Early logs on these wells have been encouraging and we expect to complete these wells in the near future.
|
·
|
In the Eastern Shale Basin of Alberta Canada, since the fourth quarter of 2012, we entered into a farmout option arrangement with a large independent whereby we have the option to earn up to approximately 22,000 acres of land targeting the Duvernay Shale upon satisfying various drilling commitments. This farmout arrangement is incremental to our established 20,000 net acre position in the play. We recently drilled, cored and cased a vertical well to analyze the rock properties and determine the pressure regime of the Duvernay Shale in the Eastern Shale Basin. The core from this well is currently under evaluation at a laboratory in Calgary, Alberta, Canada.
|
|
Period
|
High
|
Low
|
|||||||
2011
|
|||||||||
First Quarter
|
$
|
6.16
|
$
|
4.06
|
|||||
Second Quarter
|
5.97
|
3.01
|
|||||||
Third Quarter
|
5.18
|
2.50
|
|||||||
Fourth Quarter
|
4.45
|
1.86
|
|||||||
2012
|
|||||||||
First Quarter
|
$
|
4.39
|
$
|
3.03
|
|||||
Second Quarter
|
3.45
|
2.49
|
|||||||
Third Quarter
|
3.38
|
1.91
|
|||||||
Fourth Quarter
|
2.42
|
1.56
|
|||||||
2013
|
First Quarter (Through March 12, 2013)
|
$
|
2.37
|
$
|
1.93
|
12/31/2007
|
12/31/2008
|
12/31/2009
|
12/31/2010
|
12/31/2011
|
12/31/2012
|
|||||||||||||||||||
S&P 500
|
$ | 100.00 | $ | 61.51 | $ | 75.94 | $ | 85.65 | $ | 85.65 | $ | 97.13 | ||||||||||||
Small Cap Index
|
$ | 100.00 | $ | 53.57 | $ | 60.44 | $ | 92.07 | $ | 73.39 | $ | 52.50 | ||||||||||||
AXAS
|
$ | 100.00 | $ | 18.65 | $ | 49.74 | $ | 118.39 | $ | 85.49 | $ | 56.74 |
Item 6.
Selected Financial Dat
a
|
Year Ended December 31,
|
||||||||||||||||||||
2008
|
2009
|
2010
|
2011
|
2012
|
||||||||||||||||
(In thousands, except per share data)
|
||||||||||||||||||||
Total revenue
|
$ | 99,100 | $ | 51,836 | $ | 58,060 | $ | 64,622 | $ | 68,573 | ||||||||||
Net income (loss)
|
$ | (52,403 | ) | (1) | $ | (18,780 | ) | $ | 1,766 | (2) | $ | 13,743 | $ | (18,791 | ) | (3) | ||||
Net income (loss) per common share – diluted
|
$ | (1.07 | ) | $ | (0.34 | ) | $ | 0.02 | $ | 0.15 | $ | (0.20 | ) | |||||||
Weighted average shares outstanding – diluted
|
49,005 | 55,499 | 77,224 | 92,244 | 91,914 | |||||||||||||||
Total assets
|
$ | 211,839 | $ | 176,236 | $ | 182,909 | $ | 241,150 | $ | 240,607 | ||||||||||
Long-term debt, excluding current maturities
|
$ | 130,835 | $ | 143,592 | $ | 140,940 | $ | 126,258 | $ | 124,101 | ||||||||||
Total stockholders’ equity (deficit)
|
$ | 4,658 | $ | (18,363 | ) | $ | (14,976 | ) | $ | 62,651 | $ | 46,700 |
|
(1)
|
Includes proved property impairment of $116.4 million.
|
|
(2)
|
Includes proved property impairment of $4.8 million related to our Canadian properties.
|
|
(3)
|
Includes proved property impairment of $19.8 million related to our Canadian properties.
|
Item 7
. Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
|
·
|
commodity prices and the effectiveness of our hedging arrangements;
|
|
·
|
the level of total sales volumes of oil and gas;
|
|
·
|
the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;
|
|
·
|
the level of and interest rates on borrowings; and
|
|
·
|
the level and success of exploration and development activity.
|
|
·
|
basis differentials which are dependent on actual delivery location;
|
|
·
|
adjustments for BTU content; and
|
|
·
|
gathering, processing and transportation costs.
|
The following table sets forth our average differentials for the years ended December 31, 2010, 2011 and 2012:
|
Oil
|
Gas
|
|||||||||||||||||||||||
2010
|
2011
|
2012
|
2010
|
2011
|
2012
|
|||||||||||||||||||
Average realized price
|
$ | 71.37 | $ | 89.06 | $ | 85.11 | $ | 3.97 | $ | 3.58 | $ | 2.36 | ||||||||||||
Average NYMEX price
|
$ | 79.51 | $ | 95.06 | $ | 94.16 | $ | 4.38 | $ | 4.14 | $ | 2.83 | ||||||||||||
Differential
|
$ | (8.14 | ) | $ | (6.00 | ) | $ | (9.05 | ) | $ | (0.41 | ) | $ | (0.56 | ) | $ | (0.47 | ) |
Oil
|
||||||||
Contract Periods
|
Daily Volume (Bbl)
|
Swap Price (per Bbl)
|
||||||
2013
|
1,341 | $ | 86.70 | |||||
2014
|
1,100 | $ | 92.58 | |||||
2015
|
933 | $ | 85.00 | |||||
2016
|
883 | $ | 84.00 |
Year Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
Total production (MBoe)
|
1,422 | 1,272 | 1,437 | |||||||||
Average daily production (Boepd)
|
3,896 | 3,484 | 3,926 | |||||||||
% Oil/ NGL
|
36 | % | 45 | % | 52 | % |
Year Ended December 31,
|
||||||||||||
(In thousands, except per unit data)
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
Operating revenue (1):
|
||||||||||||
Oil sales
|
$ | 35,935 | $ | 48,080 | $ | 54,770 | ||||||
Gas sales
|
21,729 | 15,127 | 9,679 | |||||||||
NGL sales
|
386 | 1,408 | 4,050 | |||||||||
Total operating revenues
|
$ | 58,050 | $ | 64,615 | $ | 68,499 | ||||||
Operating income (loss) (2)
|
$ | 2,807 | $ | 11,648 | $ | (16,348 | ) | |||||
Oil sales (MBbls)
|
498.7 | 539.9 | 643.5 | |||||||||
Gas sales (MMcf)
|
5,478.9 | 4,221.8 | 4,097.1 | |||||||||
NGL sales (MBbls)
|
10.2 | 28.1 | 110.8 | |||||||||
Oil equivalents (MBoe)
|
1,422.1 | 1,271.6 | 1,437.1 | |||||||||
Average oil sales price (per Bbl)(1)
|
$ | 71.37 | $ | 89.05 | $ | 85.11 | ||||||
Average gas sales price (per Mcf)(1)
|
$ | 3.97 | $ | 3.58 | $ | 2.36 | ||||||
Average NGL sales price (per Bbl)
|
$ | 37.81 | $ | 50.07 | $ | 36.57 | ||||||
Average oil equivalent sales price (Boe)
|
$ | 40.82 | $ | 50.81 | $ | 47.67 |
|
(1)
|
Revenue and average sales prices are before the impact of hedging activities.
|
|
(2)
|
Operating income includes a proved property impairment of $4.8 million and $19.8 million in 2010 and 2012, respectively related to our Canadian properties.
|
|
·
|
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,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Expenditure category:
|
||||||||||||
Acquisition of producing properties
|
$ | — | $ | — | $ | 7,200 | ||||||
Exploration/Development
|
36,172 | 56,245 | 57,307 | |||||||||
Facilities and other
|
276 | 22,767 | 4,045 | |||||||||
Total
|
$ | 36,448 | $ | 79,012 | $ | 68,552 |
Year Ended December 31,
|
||||||||||
2010
|
2011
|
2012
|
||||||||
(In thousands)
|
||||||||||
Net cash provided by operating activities
|
$
|
24,102
|
$
|
24,495
|
$
|
51,375
|
||||
Net cash used in investing activities
|
(15,048
|
)
|
(70,555
|
)
|
(47,003
|
)
|
||||
Net cash (used in) provided by financing activities
|
(10,816
|
)
|
45,966
|
(2,311
|
)
|
|||||
Total
|
$
|
(1,762
|
)
|
$
|
(94
|
)
|
$
|
2,061
|
|
·
|
Long-term debt, and
|
|
·
|
Operating leases for office facilities.
|
|
____________
|
|
(1)
|
These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These payments assume that we will not borrow additional funds.
|
|
(2)
|
Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.
|
|
(3)
|
Lease on office space in Calgary, Alberta, which expires on January 31, 2014 and office space in Dickinson, North Dakota, which expires on August 31, 2013.
|
December 31,2011
|
December 31, 2012
|
|||||||
(In thousands)
|
||||||||
Credit facility
|
$ | 115,000 | $ | 113,000 | ||||
Rig loan agreement
|
6,500 | 7,000 | ||||||
Real estate lien note
|
4,939 | 4,758 | ||||||
126,439 | 124,758 | |||||||
Less current maturities
|
(181 | ) | (657 | ) | ||||
$ | 126,258 | $ | 124,101 |
·
|
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.
|
Oil
|
||||||||
Contract Periods
|
Daily Volume (Bbl)
|
Swap Price (per Bbl)
|
||||||
2013
|
1,341 | $ | 86.70 | |||||
2014
|
1,100 | $ | 92.58 | |||||
2015
|
933 | $ | 85.00 | |||||
2016
|
883 | $ | 84.00 |
Derivative Instrument Sensitivity
|
Oil
|
||||||||
Contract Periods
|
Daily Volume (Bbl)
|
Swap Price (per Bbl)
|
||||||
2013
|
1,341 | $ | 86.70 | |||||
2014
|
1,100 | $ | 92.58 | |||||
2015
|
933 | $ | 85.00 | |||||
2016
|
883 | $ | 84.00 |
Item 8.
Financial Statements
and Supplementary Data
|
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|
|
Item 15.
Exhibits Financial Statement
Schedules
|
Page
|
||||
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
|
F-2 | |||
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting
|
F-3 | |||
Consolidated Balance Sheets at December 31, 2011 and 2012
|
F-4 | |||
Consolidated Statements of Operations for the years ended December 31, 2010, 2011 and 2012
|
F-6 | |||
Consolidated Statements of Other Comprehensive Income (Loss) for the years ended
December 31, 2010, 2011 and 2012
|
F-7 | |||
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended
December 31, 2010, 2011 and 2012
|
F-8 | |||
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2011 and 2012
|
F-9 | |||
Notes to Consolidated Financial Statements
|
F-11 |
(a)2.
|
Financial Statement Schedules
|
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 herewith).3.7Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on November 17, 2008).
|
3.8
|
Certificate of Designation of Series 2010 Junior Participating Preferred Stock. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on March 17, 2010).
|
4.1
|
Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement).
|
4.2
|
Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our Annual Report on Form 10-K filed on March 31, 1995).
|
4.3
|
Rights Agreement, dated March 17, 2010 by and between Abraxas and American Stock Transfer and Trust Company. (Filed as Exhibit 4.1 to our Registration Statement on Form 8-A filed on March 17, 2010).
|
*10.1
|
Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-18673 filed on December 24, 1996).
|
*10.2
|
Abraxas Petroleum Corporation Amended and Restated 1994 Long Term Incentive Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-120989 filed on January 12, 2005).
|
*10.3
|
Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filed March 14, 2007).
|
*10.4
|
Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the Registration Statement on Form S-1, No. 333-95281 filed on January 24, 2000 (the “2000 S-1 Registration Statement”)).
|
*10.5
|
Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the Registration Statement on Form S-3, No. 333-127480 filed on September 16, 2005 (the “S-3 Registration Statement”)).
|
*10.6
|
Employment Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27 to the S-3 Registration Statement).
|
*10.7
|
Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as Exhibit 10.28 to the S-3 Registration Statement).
|
*10.8
|
Employment Agreement between Abraxas and G. William Krog, Jr. (Filed as Exhibit 10.9 to our Annual report on Form 10-K filed March 15, 2012).
|
*10.9
|
Employment Agreement between Abraxas and Geoffrey R. King (Filed herewith)
|
*10.10
|
Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Appendix A to our Proxy Statement filed on April 15, 2010).
|
*10.11
|
Form of Stock Option Agreement under the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed June 6, 2005).
|
*10.12
|
Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed as Exhibit 10.17 to our Annual Report on Form 10-K filed March 23, 2006).
|
*10.13
|
Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan. (Filed as Annex E to our Proxy Statement filed on September 8, 2009).
|
*10.14
|
Form of Employee Stock Option Agreement under the Abraxas 2005 Employee Long-Term Equity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed August 26, 2006).
|
10.15
|
Amended and Restated Credit Agreement dated as of June 30, 2011 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société Générale, as Administrative Agent and as Issuing Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 6, 2011).
|
10.16
|
Amendment No. 2 to Second Amended and Restated Credit Agreement dated as of June 29, 2012 among Abraxas, the guarantors named therein, the lenders named therein and Société Générale, as administrative agent (Filed as Exhibit 10.1 to our Quarterly Report on Form 10-Q filed on August 9, 2012).
|
10.17
|
Loan Agreement dated as of September 19, 2011 between Raven Drilling, LLC, as Borrower, and RBS Asset Finance, Inc., as Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on September 23, 2011).
|
14.1
|
Abraxas Petroleum Corporation Code of Business Conduct and Ethics. (Filed as Exhibit 14.1 to our Annual Report on Form 10-K filed March 22, 2006).
|
21.1
|
Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to our Annual Report on Form 10-K filed on March 15, 2012).
|
23.1
|
Consent of BDO USA, LLP. (Filed herewith).
|
23.2
|
Consent of DeGolyer and MacNaughton. (Filed herewith).
|
31.1
|
Certification – Chief Executive Officer. (Filed herewith).
|
31.2
|
Certification – Chief Financial Officer. (Filed herewith).
|
32.1
|
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed herewith).
|
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).
|
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 18, 2013
|
||
/s/ Geoffrey R. King
Geoffrey R. King
|
Vice President, CFO (Principal Financial Officer)
|
March 18, 2013
|
||
/s/ G. William Krog, Jr.
G. William Krog, Jr.
|
Chief Accounting Officer (Principal Accounting Officer)
|
March 18, 2013
|
||
/s/ C. Scott. Bartlett, Jr.
C. Scott Bartlett, Jr.
|
Director
|
March 18, 2013
|
||
/s/ Harold D. Carter
Harold D. Carter
|
Director
|
March 18, 2013
|
||
/s/ Ralph F. Cox
Ralph F. Cox
|
Director
|
March 18, 2013
|
||
/s/ W. Dean Karrash
W. Dean Karrash
|
Director
|
March 18, 2013
|
||
/s/ Dennis E. Logue
Dennis E. Logue
|
Director
|
March 18, 2013
|
||
/s/ Brian L. Melton
Brian L. Melton
|
Director
|
March 18, 2013
|
||
/s/ Paul A. Powell, Jr.
Paul A. Powell, Jr.
|
Director
|
March 18, 2013
|
||
/s/ Edward P. Russell
Edward P. Russell
|
Director
|
March 18, 2013
|
Page
|
||||
Abraxas Petroleum Corporation and Subsidiaries
|
||||
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
|
F-2 | |||
Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting
|
F-3 | |||
Consolidated Balance Sheets at December 31, 2011 and 2012
|
F-4 | |||
Consolidated Statements of Operations for the years ended December 31, 2010, 2011 and 2012
|
F-6 | |||
Consolidated Statements of Other Comprehensive Income (Loss) for the years ended December 31, 2010,
2011 and 2012
|
F-7 | |||
Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2010,
2011 and 2012
|
F-8 | |||
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2011 and 2012
|
F-9 | |||
Notes to Consolidated Financial Statements
|
F-11 |
December 31,
|
||||||||
2011
|
2012
|
|||||||
(In thousands)
|
||||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | — | $ | 2,061 | ||||
Accounts receivable:
|
||||||||
Joint owners
|
3,354 | 8,883 | ||||||
Oil and gas production sales
|
8,897 | 10,887 | ||||||
Other
|
655 | 661 | ||||||
12,906 | 20,431 | |||||||
Derivative asset
|
11,416 | 41 | ||||||
Other current assets
|
391 | 488 | ||||||
Total current assets
|
24,713 | 23,021 | ||||||
Property and equipment:
|
||||||||
Oil and gas properties, full cost method of accounting:
|
||||||||
Proved
|
490,908 | 563,317 | ||||||
Unproved properties excluded from depletion
|
1,100 | 2,089 | ||||||
Other property and equipment
|
33,783 | 37,833 | ||||||
Total
|
525,791 | 603,239 | ||||||
Less accumulated depreciation, depletion, and amortization
|
(346,239 | ) | (390,407 | ) | ||||
Total property and equipment, net
|
179,552 | 212,832 | ||||||
Investment in joint venture
|
26,215 | — | ||||||
Deferred financing fees, net
|
3,490 | 3,397 | ||||||
Derivative asset
|
6,412 | 594 | ||||||
Other assets
|
768 | 763 | ||||||
Total assets
|
$ | 241,150 | $ | 240,607 |
|
See accompanying notes to consolidated financial statements
|
December 31,
|
||||||||
2011
|
2012
|
|||||||
(In thousands, except number of shares)
|
||||||||
Current liabilities:
|
||||||||
Accounts payable
|
$ | 21,373 | $ | 42,387 | ||||
Joint interest oil and gas production payable
|
5,835 | 6,947 | ||||||
Accrued interest
|
209 | 75 | ||||||
Other accrued expenses
|
284 | 962 | ||||||
Derivative liability
|
11,640 | 3,462 | ||||||
Current maturities of long-term debt
|
181 | 657 | ||||||
Total current liabilities
|
39,522 | 54,490 | ||||||
Long-term debt – less current maturities
|
126,258 | 124,101 | ||||||
Other liabilities
|
— | 367 | ||||||
Derivative liability
|
4,307 | 3,568 | ||||||
Future site restoration
|
8,412 | 11,381 | ||||||
Total liabilities
|
178,499 | 193,907 | ||||||
Commitments and contingencies (Note 8)
|
||||||||
Stockholders’ Equity:
|
||||||||
Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding
|
— | — | ||||||
Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 92,261,057 and 92,733,448
|
923 | 927 | ||||||
Additional paid-in capital
|
248,480 | 250,998 | ||||||
Accumulated deficit
|
(186,465 | ) | (205,256 | ) | ||||
Accumulated other comprehensive income (loss)
|
(287 | ) | 31 | |||||
Total stockholders’ equity
|
62,651 | 46,700 | ||||||
Total liabilities and stockholders’ equity
|
$ | 241,150 | $ | 240,607 |
Years Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands except per share data)
|
||||||||||||
Revenues:
|
||||||||||||
Oil and gas production revenues
|
$ | 58,050 | $ | 64,615 | $ | 68,499 | ||||||
Other
|
10 | 7 | 74 | |||||||||
58,060 | 64,622 | 68,573 | ||||||||||
Operating costs and expenses:
|
||||||||||||
Lease operating
|
19,475 | 21,581 | 24,806 | |||||||||
Production taxes
|
5,910 | 5,766 | 6,613 | |||||||||
Depreciation, depletion, and amortization
|
16,212 | 16,194 | 23,016 | |||||||||
Impairment
|
4,787 | — | 19,774 | |||||||||
General and administrative (including stock-based compensation of $1,560, $1,987 and $2,091, respectively)
|
8,869 | 9,433 | 10,712 | |||||||||
55,253 | 52,974 | 84,921 | ||||||||||
Operating income (loss)
|
2,807 | 11,648 | (16,348 | ) | ||||||||
Other (income) expense:
|
||||||||||||
Interest income
|
(8 | ) | (7 | ) | (4 | ) | ||||||
Interest expense
|
9,106 | 4,898 | 5,520 | |||||||||
Amortization of deferred financing fees
|
2,479 | 1,762 | 937 | |||||||||
Gain on derivative contracts (unrealized $(10,285), $(7,476) and $(2,669))
|
(10,811 | ) | (6,800 | ) | (2,210 | ) | ||||||
Equity in loss (income) of joint venture
|
473 | (2,187 | ) | (2,207 | ) | |||||||
Other
|
(119 | ) | 316 | 97 | ||||||||
1,120 | (2,018 | ) | 2,133 | |||||||||
Income (loss) before income tax
|
1,687 | 13,666 | (18,481 | ) | ||||||||
Income tax benefit (expense)
|
79 | 77 | (310 | ) | ||||||||
Net income (loss)
|
$ | 1,766 | $ | 13,743 | $ | (18,791 | ) | |||||
Net income (loss) - per common share - basic
|
$ | 0.02 | $ | 0.15 | $ | (0.20 | ) | |||||
Net income (loss) - per common share - diluted
|
$ | 0.02 | $ | 0.15 | $ | (0.20 | ) |
|
Years Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Consolidated net income (loss)
|
$ | 1,766 | $ | 13,743 | $ | (18,791 | ) | |||||
Other comprehensive income (loss):
|
||||||||||||
Change in unrealized value of investments
|
(27 | ) | (76 | ) | (25 | ) | ||||||
Foreign currency translation adjustment
|
70 | (456 | ) | 343 | ||||||||
Other comprehensive income (loss)
|
43 | (532 | ) | 318 | ||||||||
Comprehensive income (loss)
|
$ | 1,809 | $ | 13,211 | $ | (18,473 |
Common Stock
|
||||||||||||||||||||||||
Shares
|
Amount
|
Additional
Paid in
Capital
|
Accumulated
Deficit
|
Accumulated
Other
Comprehensive
Income(Loss)
|
Total
|
|||||||||||||||||||
Balance at December 31, 2009
|
76,231,751 | $ | 762 | $ | 182,647 | $ | (201,974 | ) | $ | 202 | (18,363 | ) | ||||||||||||
Net income
|
— | — | — | 1,766 | — | 1,766 | ||||||||||||||||||
Change in unrealized gain (loss) on fair value of investments
|
— | — | — | — | (27 | ) | (27 | ) | ||||||||||||||||
Foreign currency translation adjustment
|
— | — | — | — | 70 | 70 | ||||||||||||||||||
Stock-based compensation
|
— | — | 1,560 | — | — | 1,560 | ||||||||||||||||||
Shares issued for compensation
|
11,480 | — | 24 | — | — | 24 | ||||||||||||||||||
Stock options exercised
|
163,705 | 2 | 67 | — | — | 69 | ||||||||||||||||||
Warrants exercised
|
15,534 | — | — | — | — | — | ||||||||||||||||||
Other
|
— | — | (75 | ) | — | — | (75 | ) | ||||||||||||||||
Restricted stock issued, net of cancellations
|
5,091 | — | — | — | — | — | ||||||||||||||||||
Balance December 31, 2010
|
76,427,561 | 764 | 184,223 | (200,208 | ) | 245 | (14,976 | ) | ||||||||||||||||
Net income
|
— | — | — | 13,743 | — | 13,743 | ||||||||||||||||||
Change in unrealized gain (loss) on fair value of investments
|
— | — | — | — | (76 | ) | (76 | ) | ||||||||||||||||
Foreign currency translation adjustment
|
— | — | — | — | (456 | ) | (456 | ) | ||||||||||||||||
Stock-based compensation
|
— | — | 1,987 | — | — | 1,987 | ||||||||||||||||||
Shares issuance
|
15,075,502 | 151 | 62,195 | — | — | 62,346 | ||||||||||||||||||
Stock options exercised
|
371,632 | 4 | 79 | — | — | 83 | ||||||||||||||||||
Restricted stock issued, net of cancellations
|
386,362 | 4 | (4 | ) | — | — | — | |||||||||||||||||
Balance December 31, 2011
|
92,261,057 | 923 | 248,480 | (186,465 | ) | (287 | ) | 62,651 | ||||||||||||||||
Net income
|
— | — | — | (18,791 | ) | — | (18,791 | ) | ||||||||||||||||
Change in unrealized gain (loss) on fair value of investments
|
— | — | — | — | (25 | ) | (25 | ) | ||||||||||||||||
Foreign currency translation adjustment
|
— | — | — | — | 343 | 343 | ||||||||||||||||||
Stock-based compensation
|
— | — | 2,091 | — | — | 2,091 | ||||||||||||||||||
Stock options exercised
|
390,957 | 4 | 427 | — | — | 431 | ||||||||||||||||||
Restricted stock issued, net of cancellations
|
81,434 | — | — | — | — | — | ||||||||||||||||||
Balance December 31, 2012
|
92,733,448 | $ | 927 | $ | 250,998 | $ | (205,256 | ) | $ | 31 | $ | 46,700 |
Years Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Operating Activities
|
||||||||||||
Net income (loss) income
|
$ | 1,766 | $ | 13,743 | $ | (18,791 | ) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
||||||||||||
Equity in loss (income) of joint venture
|
473 | (2,187 | ) | (2,207 | ) | |||||||
Change in derivative fair value
|
(10,451 | ) | (7,680 | ) | (4,088 | ) | ||||||
Monetization of derivative contracts
|
— | — | 12,364 | |||||||||
Depreciation, depletion, and amortization
|
16,212 | 16,194 | 23,016 | |||||||||
Impairment
|
4,787 | — | 19,774 | |||||||||
Accretion of future site restoration
|
516 | 452 | 474 | |||||||||
Amortization of deferred financing fees
|
2,479 | 1,762 | 937 | |||||||||
Stock-based compensation
|
1,560 | 1,987 | 2,091 | |||||||||
Other non-cash transactions
|
24 | — | — | |||||||||
Changes in operating assets and liabilities:
|
||||||||||||
Accounts receivable
|
(3,976 | ) | (182 | ) | (7,506 | ) | ||||||
Other assets and liabilities
|
(113 | ) | (17 | ) | 250 | |||||||
Accounts payable
|
14,210 | 756 | 22,024 | |||||||||
Accrued expenses
|
(3,385 | ) | (333 | ) | 3,037 | |||||||
Net cash provided by operating activities
|
24,102 | 24,495 | 51,375 | |||||||||
Investing Activities
|
||||||||||||
Capital expenditures, including purchases
and development of properties
|
(36,448 | ) | (79,012 | ) | (68,552 | ) | ||||||
Proceeds from the sale of oil and gas properties
|
21,400 | 8,457 | 21,549 | |||||||||
Net cash used in investing activities
|
(15,048 | ) | (70,555 | ) | (47,003 | ) | ||||||
Financing Activities
|
||||||||||||
Proceeds from exercise of stock options and warrants
|
69 | 83 | 431 | |||||||||
Proceeds from issuance of common stock, net of offering costs
|
— | 62,346 | — | |||||||||
Proceeds from long-term borrowings
|
3,000 | 50,500 | 30,500 | |||||||||
Payments on long-term borrowings
|
(13,641 | ) | (65,153 | ) | (32,181 | ) | ||||||
Deferred financing fees
|
(169 | ) | (1,758 | ) | (844 | ) | ||||||
Other
|
(75 | ) | (52 | ) | (217 | ) | ||||||
Net cash (used in) provided by financing activities
|
(10,816 | ) | 45,966 | (2,311 | ) | |||||||
Effect of exchange rate changes on cash
|
— | (5 | ) | — | ||||||||
(Decrease) increase in cash
|
(1,762 | ) | (99 | ) | 2,061 | |||||||
Cash at beginning of year
|
1,861 | 99 | — | |||||||||
Cash at end of year
|
$ | 99 | $ | — | $ | 2,061 |
Years Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Supplemental disclosures of cash flow information:
|
||||||||||||
Interest paid
|
$ | 8,876 | $ | 4,514 | $ | 5,180 | ||||||
Non-Cash Investing Activities:
|
||||||||||||
Asset retirement obligation cost and liabilities
|
$ | (83 | ) | $ | (8 | ) | $ | 2,588 | ||||
Non-cash transfer of investment in joint venture
|
— | — | 28,531 | |||||||||
Asset retirement obligations associated with property acquisitions and dispositions
|
$ | (2,735 | ) | $ | 306 | $ | 324 | |||||
Properties contributed to joint venture
|
$ | 24,500 | $ | — | $ | — |
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Beginning asset retirement obligation
|
$ | 10,326 | $ | 7,734 | $ | 8,412 | ||||||
New wells placed on production and other
|
64 | 318 | 330 | |||||||||
Deletions related to property disposals and plugging costs
|
(3,089 | ) | (84 | ) | (423 | ) | ||||||
Accretion expense
|
516 | 452 | 474 | |||||||||
Revisions
|
(83 | ) | (8 | ) | 2,588 | |||||||
Ending asset retirement obligation
|
$ | 7,734 | $ | 8,412 | $ | 11,381 |
Balance Sheets:
|
As of
December 31,
2011
|
As of
August 31,
2012
|
||||||
Assets:
|
||||||||
Current assets
|
$ | 11,910 | $ | 7,921 | ||||
Oil and gas properties
|
66,663 | 75,741 | ||||||
Other assets
|
36 | 30 | ||||||
Total assets
|
$ | 78,609 | $ | 83,692 | ||||
Liabilities and Members’ Capital:
|
||||||||
Current liabilities
|
$ | 3,070 | $ | 1,474 | ||||
Other liabilities
|
41 | 48 | ||||||
Members’ capital
|
75,498 | 82,170 | ||||||
Total liabilities and members’ capital
|
$ | 78,609 | $ | 83,692 |
Statement of Operations:
|
Year Ended
December 31,
2011
|
Year Ended
December 31,
2012 (1)
|
||||||
(In thousands)
|
||||||||
Revenue
|
$ | 12,579 | $ | 12,106 | ||||
Operating expenses
|
7,138 | 7,144 | ||||||
Other income
|
(11 | ) | (4 | ) | ||||
Net income
|
$ | 5,452 | $ | 4,966 | ||||
(1)
Through August 31, 2012
|
December 31,
2011
|
December 31,
2012
|
|||||||
(In thousands)
|
||||||||
Senior secured credit facility
|
$ | 115,000 | $ | 113,000 | ||||
Rig loan agreement
|
6,500 | 7,000 | ||||||
Real estate lien note
|
4,939 | 4,758 | ||||||
126,439 | 124,758 | |||||||
Less current maturities
|
(181 | ) | (657 | ) | ||||
$ | 126,258 | $ | 124,101 |
Year ending December 31, (In thousands)
|
||||
2013
|
$ | 657 | ||
2014
|
2,117 | |||
2015
|
119,364 | |||
2016
|
2,085 | |||
2017
|
535 | |||
Thereafter
|
— | |||
$ | 124,758 |
·
|
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
|
December 31,
|
|||||||||||
Useful Life
|
2011
|
2012
|
||||||||||
Years
|
(In thousands)
|
|||||||||||
Oil and gas properties
|
— | $ | 492,008 | $ | 565,406 | |||||||
Equipment and other
|
3-39 | 16,330 | 19,052 | |||||||||
Drilling rig
|
15 | 17,453 | 18,781 | |||||||||
$ | 525,791 | $ | 603,239 |
2010
|
2011
|
2012
|
||||||||||
Weighted average value per option granted during the period
|
$ | 1.61 | $ | 3.11 | $ | 2.17 | ||||||
Assumptions: (1)(2)
|
||||||||||||
Expected dividend yield
|
0 | % | 0 | % | 0 | % | ||||||
Volatility
|
84.0 | % | 80.0 | % | 81.4 | % | ||||||
Risk free interest rate
|
2.87 | % | 2.21 | % | 1.19 | % | ||||||
Expected life (years)
|
9.0 years
|
6.4 years
|
6.7 years
|
|||||||||
Fair value of options granted (in thousands)
|
$ | 1,553 | $ | 2,506 | $ | 1,324 |
(1)
|
The estimated future forfeiture rate is based on the Company’s historical forfeiture rate.
|
|
(2)
|
The Company does not pay dividends on its common stock.
|
Options
(000s)
|
Weighted average
exercise price
|
Weighted
average
remaining life
|
Intrinsic
value
per share
|
||||||||
Options outstanding December 31, 2009
|
4,090
|
$
|
2.18
|
||||||||
Granted
|
964
|
2.12
|
|||||||||
Exercised
|
(213
|
)
|
0.89
|
||||||||
Forfeited/Expired
|
(21
|
)
|
2.93
|
||||||||
Options outstanding December 31, 2010
|
4,820
|
$
|
2.23
|
||||||||
Granted
|
807
|
4.37
|
|||||||||
Exercised
|
(530
|
)
|
1.54
|
||||||||
Forfeited/Expired
|
(341
|
)
|
3.01
|
||||||||
Options outstanding December 31, 2011
|
4,756
|
$
|
2.61
|
||||||||
Granted
|
610
|
$
|
3.01
|
||||||||
Exercised
|
(391
|
)
|
1.11
|
||||||||
Forfeited/Expired
|
(214
|
)
|
2.80
|
||||||||
Options outstanding December 31, 2012
|
4,761
|
$
|
2.77
|
6.5 years
|
$
|
1.98
|
|||||
Exercisable at end of year
|
2,992
|
$
|
2.75
|
5.7 years
|
$
|
1.95
|
|
2010
|
2011
|
2012
|
|||||||||
Weighted average grant date fair value of stock options granted (per share)
|
$ | 1.61 | $ | 3.11 | $ | 2.17 | ||||||
Total fair value of options vested (000’s)
|
$ | 949 | $ | 1,230 | $ | 1,497 | ||||||
Total intrinsic value of options exercised (000’s)
|
$ | 373 | $ | 1,584 | $ | 414 |
Options outstanding
|
Exercisable
|
|||||||||||||||||||||||||
Number
outstanding
|
Weighted
average
remaining
life
|
Weighted
average
exercise
price
|
Number
exercisable
|
Weighted
average
remaining
life
|
Weighted
average
exercise
price
|
|||||||||||||||||||||
$ | 0.68 – 0.99 | 743,793 | 5.68 | $ | 0.96 | 548,293 | 5.50 | $ | 0.95 | |||||||||||||||||
$ | 1.00 – 1.99 | 1,130,629 | 7.27 | $ | 1.75 | 696,677 | 6.75 | $ | 1.68 | |||||||||||||||||
$ | 2.00 – 2.99 | 924,225 | 7.17 | $ | 2.26 | 563,159 | 7.13 | $ | 2.36 | |||||||||||||||||
$ | 3.00 – 3.99 | 719,763 | 7.61 | $ | 3.65 | 276,713 | 5.41 | $ | 3.60 | |||||||||||||||||
$ | 4.00 – 4.99 | 1,168,500 | 5.47 | $ | 4.58 | 833,625 | 4.38 | $ | 4.53 | |||||||||||||||||
$ | 5.00 – 6.05 | 74,000 | 3.15 | $ | 6.05 | 74,000 | 3.15 | $ | 6.05 | |||||||||||||||||
4,760,910 | 2,992,467 |
Number
of
Shares
|
Weighted
average
grant date
fair value
|
|||||||
Unvested December 31, 2009
|
548,908 | $ | 2.05 | |||||
Granted
|
20,000 | 2.45 | ||||||
Vested/Released
|
(155,268 | ) | 2.22 | |||||
Forfeited
|
(13,345 | ) | 1.85 | |||||
Unvested December 31, 2010
|
400,295 | $ | 2.02 | |||||
Granted
|
408,676 | 3.67 | ||||||
Vested/Released
|
(156,890 | ) | 2.24 | |||||
Forfeited
|
(22,310 | ) | 2.27 | |||||
Unvested December 31, 2011
|
629,771 | $ | 3.03 | |||||
Granted
|
89,860 | 2.12 | ||||||
Vested/Released
|
(229,172 | ) | 2.57 | |||||
Forfeited
|
(8,434 | ) | 2.42 | |||||
Unvested December 31, 2012
|
482,025 | $ | 3.09 |
Years Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Deferred tax liabilities:
|
||||||||||||
Marketable securities
|
$ | 57 | $ | 36 | $ | 28 | ||||||
Canada full cost pool
|
— | 377 | — | |||||||||
Investment in Blue Eagle
|
7,107 | 7,527 | — | |||||||||
Hedge contracts
|
— | 345 | — | |||||||||
Total deferred tax liabilities
|
7,164 | 8,285 | 28 | |||||||||
Deferred tax assets:
|
||||||||||||
U.S. full cost pool
|
37,464 | 29,976 | 13,837 | |||||||||
Canada full cost pool
|
1,238 | — | 3,720 | |||||||||
Depletion carryforward
|
4,667 | 4,842 | 4,930 | |||||||||
U.S. net operating loss carryforward
|
49,621 | 52,564 | 59,362 | |||||||||
Canada net operating loss carryforward
|
301 | 2,151 | 4,196 | |||||||||
Alternative minimum tax credit
|
422 | 422 | 422 | |||||||||
Hedge contracts
|
1,904 | — | 2,231 | |||||||||
Other
|
3,447 | 1,811 | 1,042 | |||||||||
Total deferred tax assets
|
99,064 | 91,766 | 89,740 | |||||||||
Valuation allowance for deferred tax assets
|
(91,900 | ) | (83,481 | ) | (89,712 | ) | ||||||
Net deferred tax assets
|
7,164 | 8,285 | 28 | |||||||||
Net deferred tax
|
$ | — | $ | — | $ | — |
Years ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Current:
|
||||||||||||
Federal
|
$ | — | $ | (77 | ) | $ | 310 | |||||
State
|
(79 | ) | — | — | ||||||||
Foreign
|
— | — | — | |||||||||
$ | (79 | ) | $ | (77 | ) | $ | 310 | |||||
Deferred:
|
||||||||||||
Federal
|
$ | — | $ | — | $ | — | ||||||
Foreign
|
— | — | — | |||||||||
$ | — | $ | — | $ | — |
Years ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Tax (expense) benefit at U.S. statutory rates (35%)
|
$ | (591 | ) | $ | (4,809 | ) | $ | 6,468 | ||||
(Increase) decrease in deferred tax asset valuation allowance
|
(412 | ) | 5,408 | (6,231 | ) | |||||||
Basis difference in hedge liability
|
1,890 | — | — | |||||||||
Rate differential for non U.S. income
|
(385 | ) | (46 | ) | (1,533 | ) | ||||||
State income taxes
|
— | — | ||||||||||
Accrual of prior year federal taxes (2009)
|
— | — | (310 | ) | ||||||||
Permanent differences
|
(409 | ) | (533 | ) | (732 | ) | ||||||
Increase in asset for partnership distribution
|
— | — | 1,945 | |||||||||
Other
|
(14 | ) | 57 | 83 | ||||||||
$ | 79 | $ | 77 | $ | (310 | ) |
Years ended December 31:
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands, except per share data)
|
||||||||||||
Numerator:
|
||||||||||||
Net income (loss)
|
$ | 1,766 | $ | 13,743 | $ | (18,791 | ) | |||||
Denominator:
|
||||||||||||
Denominator for basic earnings per share – weighted-average common shares outstanding
|
75,923 | 90,151 | 91,914 | |||||||||
Effect of dilutive securities:
Stock options, restricted shares and warrants
|
1,301 | 2,093 | — | |||||||||
Dilutive potential common shares:
Denominator for diluted earnings per share – adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants
|
77,224 | 92,244 | 91,914 | |||||||||
Net income (loss) per common share – basic
|
$ | 0.02 | $ | 0.15 | $ | (0.20 | ) | |||||
Net income (loss) per common share – diluted
|
$ | 0.02 | $ | 0.15 | $ | (0.20 | ) |
10. Quarterly Results of Operations (Unaudited)
|
1
st
Quarter
|
2
nd
Quarter
|
3
rd
Quarter
|
4
th
Quarter
|
||||||||||
(In thousands, except per share data)
|
|||||||||||||
Year Ended December 31, 2011
|
|||||||||||||
Net revenue
|
$
|
13,847
|
$
|
16,656
|
$
|
17,666
|
$
|
16,453
|
|||||
Operating income
|
$
|
2,503
|
$
|
3,438
|
$
|
4,225
|
$
|
1,482
|
|||||
Net (loss) income
|
$
|
(10,019
|
)
|
$
|
8,937
|
$
|
20,085
|
$
|
(5,260
|
)
|
|||
Net (loss) income per common share – basic
|
$
|
(0.12
|
)
|
$
|
0.10
|
$
|
0.22
|
$
|
(0.06
|
)
|
|||
Net (loss) income per common share – diluted
|
$
|
(0.12
|
)
|
$
|
0.10
|
$
|
0.21
|
$
|
(0.06
|
)
|
|||
Year Ended December 31, 2012
|
|||||||||||||
Net revenue
|
$
|
16,396
|
$
|
15,938
|
$
|
17,170
|
$
|
19,069
|
|||||
Operating income (loss)
|
$
|
2,224
|
$
|
(23
|
)
|
$
|
(11,359
|
)
|
$
|
(7,190
|
)
|
||
Net income (loss) income
|
$
|
817
|
$
|
10,903
|
$
|
(18,644
|
)
|
$
|
(11,867
|
)
|
|||
Net income (loss) per common share – basic
|
$
|
0.01
|
$
|
0.12
|
$
|
(0.20
|
)
|
$
|
(0.13
|
)
|
|||
Net income (loss) per common share – diluted
|
$
|
0.01
|
$
|
0.12
|
$
|
(0.20
|
)
|
$
|
(0.13
|
)
|
Year Ended December 31, 2010
|
||||||||||||||||
U.S.
|
Canada
|
Corporate
|
Total
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Revenues:
|
||||||||||||||||
Oil and gas production
|
$ | 57,990 | $ | 60 | $ | — | $ | 58,050 | ||||||||
Other
|
— | — | 10 | 10 | ||||||||||||
57,990 | 60 | 10 | 58,060 | |||||||||||||
Costs and expenses:
|
||||||||||||||||
Lease operating
|
19,459 | 16 | — | 19,475 | ||||||||||||
Production taxes
|
5,910 | — | — | 5,910 | ||||||||||||
Depreciation, depletion and amortization
|
15,603 | 66 | 543 | 16,212 | ||||||||||||
Impairment
|
— | 4,787 | — | 4,787 | ||||||||||||
General and administrative
|
1,635 | 688 | 6,546 | 8,869 | ||||||||||||
Net interest
|
— | — | 9,098 | 9,098 | ||||||||||||
Amortization of deferred financing fees
|
— | — | 2,479 | 2,479 | ||||||||||||
Equity in loss of joint venture
|
— | — | 473 | 473 | ||||||||||||
Other
|
— | — | (10,930 | ) | (10,930 | ) | ||||||||||
Income (loss) before tax
|
$ | 15,383 | $ | (5,497 | ) | $ | (8,199 | ) | $ | 1,687 |
Year Ended December 31, 2011
|
||||||||||||||||
U.S.
|
Canada
|
Corporate
|
Total
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Revenues:
|
||||||||||||||||
Oil and gas production
|
$ | 63,105 | $ | 1,510 | $ | — | $ | 64,615 | ||||||||
Other
|
— | — | 7 | 7 | ||||||||||||
63,105 | 1,510 | 7 | 64,622 | |||||||||||||
Costs and expenses:
|
||||||||||||||||
Lease operating
|
20,788 | 793 | — | 21,581 | ||||||||||||
Production taxes
|
5,764 | 2 | — | 5,766 | ||||||||||||
Depreciation, depletion and amortization
|
15,236 | 709 | 249 | 16,194 | ||||||||||||
General and administrative
|
1,698 | 654 | 7,081 | 9,433 | ||||||||||||
Net interest
|
448 | 4 | 4,439 | 4,891 | ||||||||||||
Amortization of deferred financing fees
|
— | — | 1,762 | 1,762 | ||||||||||||
Equity in (income) of joint venture
|
— | — | (2,187 | ) | (2,187 | ) | ||||||||||
Other
|
— | — | (6,484 | ) | (6,484 | ) | ||||||||||
Income (loss) before tax
|
$ | 19,171 | $ | (652 | ) | $ | (4,853 | ) | $ | 13,666 | ||||||
Year Ended December 31, 2012
|
||||||||||||||||
U.S.
|
Canada
|
Corporate
|
Total
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Revenues:
|
||||||||||||||||
Oil and gas production
|
$ | 65,590 | 2,909 | — | 68,499 | |||||||||||
Other
|
— | — | 74 | 74 | ||||||||||||
65,590 | 2,909 | 74 | 68,573 | |||||||||||||
Costs and expenses:
|
||||||||||||||||
Lease operating
|
22,578 | 2,228 | — | 24,806 | ||||||||||||
Production taxes
|
6,588 | 25 | — | 6,613 | ||||||||||||
Depreciation, depletion and amortization
|
20,704 | 2,063 | 249 | 23,016 | ||||||||||||
Impairment
|
— | 19,774 | — | 19,774 | ||||||||||||
General and administrative
|
1,980 | 699 | 8,033 | 10,712 | ||||||||||||
Net interest
|
457 | 17 | 5,042 | 5,516 | ||||||||||||
Amortization of deferred financing fees
|
— | — | 937 | 937 | ||||||||||||
Equity in (income) of joint venture
|
— | — | (2,207 | ) | (2,207 | ) | ||||||||||
Other
|
— | — | (2,113 | ) | (2,113 | ) | ||||||||||
Income (loss) before tax
|
$ | 13,283 | (21,897 | ) | (9,867 | ) | (18,481 | ) | ||||||||
Segment Assets:
|
December 31,
2011
|
December 31,
2012
|
||||||
(In thousands)
|
||||||||
United States
|
$ | 167,739 | $ | 223,253 | ||||
Canada
|
19,379 | 7,053 | ||||||
Corporate
|
54,032 | 10,301 | ||||||
$ | 241,150 | $ | 240,607 |
Oil
|
||||||||
Contract Periods
|
Daily Volume (Bbl)
|
Swap Price (per Bbl)
|
||||||
2013
|
1,341 | $ | 86.70 | |||||
2014
|
1,100 | $ | 92.58 | |||||
2015
|
933 | $ | 85.00 | |||||
2016
|
883 | $ | 84.00 |
|
·
|
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,
2011
|
|||||||||||||
Assets:
|
||||||||||||||||
Investment in common stock
|
$ | 104 | $ | — | $ | — | $ | 104 | ||||||||
NYMEX Fixed Price Derivative contracts
|
— | 17,828 | — | 17,828 | ||||||||||||
Total Assets
|
$ | 104 | $ | 17,828 | $ | — | $ | 17,932 | ||||||||
Liabilities:
|
||||||||||||||||
NYMEX Fixed Price Derivative contracts
|
$ | — | $ | 14,401 | $ | — | $ | 14,401 | ||||||||
Interest Rate Swaps
|
— | — | 1,546 | 1,546 | ||||||||||||
Total Liabilities
|
$ | — | $ | 14,401 | $ | 1,546 | $ | 15,947 |
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs (Level 3)
|
Balance as of
December 31,
2012
|
|||||||||||||
Assets:
|
||||||||||||||||
Investment in common stock
|
$ | 78 | $ | — | $ | — | $ | 78 | ||||||||
NYMEX Fixed Price Derivative contracts
|
— | 635 | — | 635 | ||||||||||||
Total Assets
|
$ | 78 | $ | 635 | $ | — | $ | 713 | ||||||||
Liabilities:
|
||||||||||||||||
NYMEX Fixed Price Derivative contracts
|
$ | — | $ | 7,030 | $ | — | $ | 7,030 | ||||||||
Total Liabilities
|
$ | — | $ | 7,030 | $ | — | $ | 7,030 |
Derivative Assets (Liabilities) - net
|
||||
Balance December 31, 2010
|
$ | (3,348 | ) | |
Total realized and unrealized losses included in change in net liability
|
(565 | ) | ||
Settlements during the period
|
2,367 | |||
Balance December 31, 2011
|
(1,546 | ) | ||
Total realized and unrealized losses included in change in net liability
|
(214 | ) | ||
Settlements during the period
|
1,760 | |||
Balance December 31, 2012
|
— |
Years Ended December 31
|
||||||||||||||||||||||||
2011
|
2012
|
|||||||||||||||||||||||
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
|||||||||||||||||||
(In thousands)
|
||||||||||||||||||||||||
Proved oil and gas properties
|
$ | 490,908 | $ | 468,218 | $ | 22,690 | $ | 563,317 | $ | 531,971 | $ | 31,346 | ||||||||||||
Unproved properties
|
1,100 | — | 1,100 | 2,089 | — | 2,089 | ||||||||||||||||||
Total
|
492,008 | 468,218 | 23,790 | 565,406 | 531,971 | 33,435 | ||||||||||||||||||
Accumulated depreciation, depletion, amortization and impairment
|
(341,264 | ) | (335,871 | ) | (5,393 | ) | (383,469 | ) | (356,255 | ) | (27,214 | ) | ||||||||||||
Net capitalized costs
|
$ | 150,744 | $ | 132,347 | $ | 18,397 | $ | 181,937 | $ | 175,716 | $ | 6,221 |
Years Ended December 31
|
||||||||||||||||||||||||||||||||||||
2010
|
2011
|
2012
|
||||||||||||||||||||||||||||||||||
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
||||||||||||||||||||||||||||
(In thousands)
|
||||||||||||||||||||||||||||||||||||
Development costs
|
$ | 31,278 | $ | 23,757 | $ | 7,521 | $ | 46,735 | $ | 32,471 | $ | 14,264 | $ | 56,318 | $ | 48,283 | $ | 8,035 | ||||||||||||||||||
Exploration costs
|
3,809 | 3,809 | — | 8,410 | 8,410 | — | — | — | — | |||||||||||||||||||||||||||
Property acquisition costs
|
— | — | — | — | — | — | 7,200 | 7,200 | — | |||||||||||||||||||||||||||
Unproved
|
1,085 | — | 1,085 | 1,100 | — | 1,100 | 989 | — | 989 | |||||||||||||||||||||||||||
$ | 36,172 | $ | 27,566 | $ | 8,606 | $ | 56,245 | $ | 40,881 | $ | 15,364 | $ | 64,507 | $ | 55,483 | $ | 9,024 |
Years Ended December 31,
|
||||||||||||||||||||||||||||||||||||
2010
|
2011
|
2012
|
||||||||||||||||||||||||||||||||||
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
||||||||||||||||||||||||||||
(In thousands)
|
||||||||||||||||||||||||||||||||||||
Revenues
|
$ | 58,050 | $ | 57,990 | $ | 60 | $ | 64,615 | $ | 63,105 | $ | 1,510 | $ | 68,499 | $ | 65,590 | $ | 2,909 | ||||||||||||||||||
Production costs
|
(25,790 | ) | (25,774 | ) | (16 | ) | (27,347 | ) | (26,552 | ) | (795 | ) | (31,419 | ) | (29,166 | ) | (2,253 | ) | ||||||||||||||||||
Depreciation, depletion, and amortization
|
(15,653 | ) | (15,603 | ) | (50 | ) | (15,595 | ) | (14,914 | ) | (681 | ) | (22,767 | ) | (20,704 | ) | (2,063 | ) | ||||||||||||||||||
Proved property impairment
|
(4,787 | ) | — | (4,787 | ) | — | — | — | (19,774 | ) | — | (19,774 | ) | |||||||||||||||||||||||
General and administrative
|
(2,323 | ) | (1,635 | ) | (688 | ) | (2,352 | ) | (1,698 | ) | (654 | ) | (2,679 | ) | (1,980 | ) | (699 | ) | ||||||||||||||||||
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)
|
$ | 9,497 | $ | 14,978 | $ | (5,481 | ) | $ | 19,321 | $ | 19,941 | $ | (620 | ) | $ | (8,140 | ) | $ | 13,740 | $ | (21,880 | ) | ||||||||||||||
Depletion rate per barrel of oil equivalent
|
$ | 11.00 | $ | 10.98 | $ | 59.97 | $ | 12.26 | $ | 11.96 | $ | 27.58 | $ | 15.59 | $ | 14.74 | $ | 37.48 |
Total
|
United States
|
Canada
|
|||||||||||||||||
Oil/NGL
|
Gas
|
Oil
Equivalents
|
Oil/NGL
|
Gas
|
Oil
Equivalents
|
Oil/NGL
|
Gas
|
Oil
Equivalents
|
|||||||||||
(MBbl)
|
(MMcf)
|
(MBoe)
|
(MBbl)
|
(MMcf)
|
(MBoe)
|
(MBbl)
|
(MMcf)
|
(MBoe)
|
|||||||||||
(In thousands)
|
|||||||||||||||||||
Proved developed and undeveloped reserves:
|
|||||||||||||||||||
Balance at December 31, 2009
|
8,832
|
96,525
|
24,919
|
8,832
|
96,525
|
24,919
|
—
|
—
|
—
|
||||||||||
Revisions of previous estimates
|
1,067
|
729
|
1,189
|
1,067
|
729
|
1,189
|
—
|
—
|
—
|
||||||||||
Extensions and discoveries
|
1,329
|
1,456
|
1,572
|
1,252
|
1,066
|
1,430
|
77
|
390
|
142
|
||||||||||
Sales of minerals in place
|
(925
|
)
|
(8,318
|
)
|
(2,311
|
)
|
(925
|
)
|
(8,318
|
)
|
(2,311
|
)
|
—
|
—
|
—
|
||||
Production
|
(509
|
)
|
(5,479
|
)
|
(1,422
|
)
|
(508
|
)
|
(5,479
|
)
|
(1,421
|
)
|
(1
|
)
|
—
|
(1
|
)
|
||
Balance at December 31, 2010
|
9,794
|
84,913
|
23,947
|
9,718
|
84,523
|
23,806
|
76
|
390
|
141
|
||||||||||
Revisions of previous estimates
|
2,290
|
(13,009
|
)
|
122
|
2,290
|
(13,009
|
)
|
122
|
—
|
—
|
—
|
||||||||
Extensions and discoveries
|
2,703
|
4,393
|
3,435
|
2,326
|
1,837
|
2,632
|
377
|
2,556
|
803
|
||||||||||
Production
|
(568
|
)
|
(4,222
|
)
|
(1,272
|
)
|
(554
|
)
|
(4,160
|
)
|
(1,247
|
)
|
(14
|
)
|
(62
|
)
|
(25
|
)
|
|
Balance at December 31, 2011
|
14,219
|
72,075
|
26,232
|
13,780
|
69,191
|
25,313
|
439
|
2,884
|
919
|
||||||||||
Revisions of previous estimates
|
1,574
|
(7,470
|
)
|
328
|
1,774
|
(5,786
|
)
|
809
|
(200
|
)
|
(1,684
|
)
|
(481
|
)
|
|||||
Extensions and discoveries
|
5,809
|
6,983
|
6,973
|
5,809
|
6,983
|
6,973
|
—
|
—
|
—
|
||||||||||
Purchases of minerals in place
|
1
|
69
|
13
|
1
|
69
|
13
|
—
|
—
|
—
|
||||||||||
Sales of minerals in place
|
(850
|
)
|
(6,376
|
)
|
(1,913
|
)
|
(850
|
)
|
(6,376
|
)
|
(1,913
|
)
|
—
|
—
|
—
|
||||
Production
|
(797
|
)
|
(4,097
|
)
|
(1,481
|
)
|
(763
|
)
|
(3,982
|
)
|
(1,427
|
)
|
(34
|
)
|
(115
|
)
|
(54
|
)
|
|
Balance at December 31, 2012
|
19,956
|
61,184
|
30,152
|
19,751
|
60,099
|
29,768
|
205
|
1,085
|
384
|
Total
|
United States
|
Canada
|
|||||||||||||||||
Oil/NGL
|
Gas
|
Oil
Equivalents
|
Oil/NGL
|
Gas
|
Oil
Equivalents
|
Oil/NGL
|
Gas
|
Oil
Equivalents
|
|||||||||||
(MBbl)
|
(MMcf)
|
(MBoe)
|
(MBbl)
|
(MMcf)
|
(MBoe)
|
(MBbl)
|
(MMcf)
|
(MBoe)
|
|||||||||||
(In thousands)
|
|||||||||||||||||||
Proved Developed Reserves:
|
|||||||||||||||||||
December 31, 2010
|
5,862
|
42,750
|
12,987
|
5,786
|
42,360
|
12,846
|
76
|
390
|
141
|
||||||||||
December 31, 2011
|
7,761
|
42,582
|
14,858
|
7,433
|
40,451
|
14,175
|
328
|
2,131
|
683
|
||||||||||
December 31, 2012
|
8,650
|
41,220
|
15,520
|
8,531
|
40,723
|
15,318
|
119
|
497
|
202
|
||||||||||
Proved Undeveloped Reserves:
|
|||||||||||||||||||
December 31, 2010
|
3,932
|
42,163
|
10,959
|
3,932
|
42,163
|
10,959
|
—
|
—
|
—
|
||||||||||
December 31, 2011
|
6,460
|
29,493
|
11,376
|
6,348
|
28,740
|
11,138
|
112
|
753
|
238
|
||||||||||
December 31, 2012
|
11,306
|
19,964
|
14,634
|
11,220
|
19,376
|
14,450
|
86
|
588
|
184
|
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
|
Years Ended December 31,
|
||||||||||||||||||||||||||||||||||||
2010
|
2011
|
2012
|
||||||||||||||||||||||||||||||||||
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
Total
|
U.S.
|
Canada
|
||||||||||||||||||||||||||||
(In thousands)
|
||||||||||||||||||||||||||||||||||||
Future cash inflows
|
$ | 1,020,286 | $ | 1,012,829 | $ | 7,457 | $ | 1,471,352 | $ | 1,420,013 | $ | 51,339 | $ | 1,784,920 | $ | 1,766,515 | $ | 18,405 | ||||||||||||||||||
Future production costs
|
(391,396 | ) | (389,395 | ) | (2,001 | ) | (544,970 | ) | (532,056 | ) | (12,914 | ) | (642,706 | ) | (634,903 | ) | (7,803 | ) | ||||||||||||||||||
Future development costs
|
(164,135 | ) | (163,085 | ) | (1,050 | ) | (228,804 | ) | (224,254 | ) | (4,550 | ) | (328,554 | ) | (324,704 | ) | (3,850 | ) | ||||||||||||||||||
Future income tax expense
|
— | — | — | (106,839 | ) | (104,279 | ) | (2,560 | ) | (149,625 | ) | (149,625 | ) | — | ||||||||||||||||||||||
Future net cash flows
|
464,755 | 460,349 | 4,406 | 590,739 | 559,424 | 31,315 | 664,035 | 657,283 | 6,752 | |||||||||||||||||||||||||||
Discount
|
(267,762 | ) | (266,041 | ) | (1,721 | ) | (321,657 | ) | (310,516 | ) | (11,141 | ) | (385,890 | ) | (383,271 | ) | (2,619 | ) | ||||||||||||||||||
Standardized Measure of discounted future net cash relating to proved reserves
|
$ | 196,993 | $ | 194,308 | $ | 2,685 | $ | 269,082 | $ | 248,908 | $ | 20,174 | $ | 278,145 | $ | 274,012 | $ | 4,133 |
|
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
|
|
The following is an analysis of the changes in the Standardized Measure:
|
Year Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
(In thousands)
|
||||||||||||
Standardized Measure, beginning of year
|
$ | 150,529 | $ | 196,993 | $ | 269,082 | ||||||
Sales and transfers of oil and gas produced, net of production costs
|
(32,261 | ) | (37,171 | ) | (37,080 | ) | ||||||
Net change in prices and development and production costs from prior year
|
70,311 | 92,886 | 60,710 | |||||||||
Extensions, discoveries, and improved recovery, less related costs
|
14,508 | 47,765 | 73,236 | |||||||||
Sales of minerals in place
|
(18,868 | ) | — | (20,089 | ) | |||||||
Purchased of minerals in place
|
— | — | 131 | |||||||||
Revisions of previous quantity estimates
|
9,694 | 1,329 | 3,355 | |||||||||
Change in timing and other
|
(11,973 | ) | (23,501 | ) | (88,309 | ) | ||||||
Change in future income tax expense
|
— | (28,918 | ) | (9,799 | ) | |||||||
Accretion of discount
|
15,053 | 19,699 | 26,908 | |||||||||
Standardized Measure, end of year
|
$ | 196,993 | $ | 269,082 | $ | 278,145 |
Year Ended December 31,
|
||||||||||||
2010
|
2011
|
2012
|
||||||||||
Oil (per Bbl) (1)
|
$ | 79.43 | $ | 96.19 | $ | 95.14 | ||||||
Gas (per MMbtu) (2)
|
4.45 | 4.16 | 2.86 | |||||||||
Oil (per Bbl) (3)
|
70.72 | 88.58 | 88.26 | |||||||||
Gas (per MMBtu) (4)
|
3.91 | 3.73 | 2.61 | |||||||||
NGL’s (per Bbl) (5)
|
55.60 | 50.21 | 36.76 |
|
(1)
|
The quoted oil price for the year ended December 31, 2010, 2011 and 2012 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2010, 2011 and 2012.
|
|
(2)
|
The quoted gas price for the year ended December 31, 2010, 2011 and 2012 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2010, 2011 and 2012.
|
|
(3)
|
The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
|
|
(4)
|
The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.
|
|
(5)
|
The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.
|
10.9
|
Employment Agreement between Abraxas and Geoffrey R. King (Filed herewith)
|
23.1
|
Consent of BDO USA, LLP. (Filed herewith).
|
23.2
|
Consent of DeGolyer & MacNaughton. (Filed herewith).
|
31.1
|
Certification – Chief Executive Officer. (Filed herewith).
|
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).
|
|
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.
|
U.S. Net Reserves
Estimated by
DeGolyer and MacNaughton
as of December 31, 2012
|
||||||||||||||||
Oil and
Condensate
(Mbbl)
|
NGL
(Mbbl)
|
Sales
Gas
(MMcf)
|
Oil
Equivalent
(Mboe)
|
|||||||||||||
Proved
|
||||||||||||||||
Developed Producing
|
6,426 | 1,243 | 38,039 | 14,009 | ||||||||||||
Developed Nonproducing
|
714 | 54 | 1,331 | 990 | ||||||||||||
Undeveloped
|
9,932 | 1,285 | 19,302 | 14,434 | ||||||||||||
Total Proved
|
17,072 | 2,582 | 58,672 | 29,433 |
Probable
|
||||||||||||||||
Developed Producing
|
17 | 4 | 21 | 24 | ||||||||||||
Developed Nonproducing
|
66 | 0 | 346 | 124 | ||||||||||||
Undeveloped
|
12,233 | 2,532 | 57,082 | 24,279 | ||||||||||||
Total Probable
|
12,316 | 2,536 | 57,449 | 24,427 |
Possible
|
||||||||||||||||
Developed Producing
|
0 | 0 | 0 | 0 | ||||||||||||
Developed Nonproducing
|
0 | 0 | 0 | 0 | ||||||||||||
Undeveloped
|
10,555 | 1,177 | 17,578 | 14,662 | ||||||||||||
Total Possible
|
10,555 | 1,177 | 17,578 | 14,662 | ||||||||||||
Notes:
1. Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.
2. Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per
1 barrel of oil equivalent.
|
Canada Net Reserves
Estimated by
DeGolyer and MacNaughton
as of December 31, 2012
|
||||||||||||||||
Oil and
Condensate
(Mbbl)
|
NGL
(Mbbl)
|
Sales
Gas
(MMcf)
|
Oil
Equivalent
(Mboe)
|
|||||||||||||
Proved
|
||||||||||||||||
Developed Producing
|
110 | 0 | 497 | 193 | ||||||||||||
Developed Nonproducing
|
0 | 0 | 0 | 0 | ||||||||||||
Undeveloped
|
74 | 0 | 588 | 172 | ||||||||||||
Total Proved
|
184 | 0 | 1,085 | 365 |
Probable
|
||||||||||||||||
Developed Producing
|
5 | 0 | 24 | 9 | ||||||||||||
Developed Nonproducing
|
0 | 0 | 0 | 0 | ||||||||||||
Undeveloped
|
0 | 0 | 0 | 0 | ||||||||||||
Total Probable
|
5 | 0 | 24 | 9 |
Possible
|
0 | 0 | 0 | 0 | ||||||||||||
Notes:
1. Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.
2. Gas is converted to oil equivalent using a factor of 6,000 cubic feet of gas per
1 barrel of oil equivalent.
|
1.
|
That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Abraxas dated February 26, 2013, and that I, as Senior Vice President, was responsible for the preparation of this report.
|
2.
|
That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 38 years of experience in oil and gas reservoir studies and reserves evaluations.
|