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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2016
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OR
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
(State or other jurisdiction of
incorporation or organization)
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61-1630631
(I.R.S. Employer Identification No.)
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410 17
th
Street, Suite 1400 Denver, Colorado
(Address of principal executive offices)
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80202
(Zip Code)
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(Title of Class)
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(Name of Exchange)
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Common Stock, par value $0.001 per share
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New York Stock Exchange
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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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PAGE
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|||
•
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the Company's business strategies and intent to maximize liquidity;
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•
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reserves estimates;
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•
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estimated sales volumes;
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•
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amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
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•
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ability to modify future capital expenditures;
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•
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ability to consummate the multiple transactions associated with the Company’s current bankruptcy court proceeding;
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•
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the Wattenberg Field being a premier oil and resource play in the United States;
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•
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anticipated costs;
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•
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compliance with debt covenants;
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•
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ability to fund and satisfy obligations related to ongoing operations;
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•
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compliance with government regulations, including environmental, health and safety regulations and liabilities thereunder;
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•
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adequacy of gathering systems and continuous improvement of such gathering systems;
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•
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impact from the lack of available gathering systems and processing facilities in certain areas;
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•
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natural gas, oil and natural gas liquid prices and factors affecting the volatility of such prices;
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•
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impact of lower commodity prices;
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•
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sufficiency of impairments;
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•
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the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
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•
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our drilling inventory and drilling intentions;
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•
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our estimated revenues and losses;
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•
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the timing and success of specific projects;
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•
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our implementation of long reach laterals in the Wattenberg Field;
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•
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our use of multi-well pads to develop the Niobrara and Codell formations;
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•
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intention to continue to optimize enhanced completion techniques and well design changes;
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•
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stated working interest percentages;
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•
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management and technical team;
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•
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outcomes and effects of litigation, claims and disputes;
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•
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primary sources of future production growth;
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•
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full delineation of the Niobrara B and C benches in our legacy acreage;
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•
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our ability to replace oil and natural gas reserves;
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•
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our ability to convert PUDs to producing properties within five years of their initial proved booking;
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•
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impact of recently issued accounting pronouncements;
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•
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impact of the loss a single customer or any purchaser of our products;
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•
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timing and ability to meet certain volume commitments related to purchase and transportation agreements;
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•
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the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes and other industry-related constraints;
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•
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our financial position;
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•
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our cash flow and liquidity;
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•
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the adequacy of our insurance; and
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•
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other statements concerning our operations, economic performance and financial condition.
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•
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the risk factors discussed in Part I, Item 1A of this Annual Report on Form 10-K;
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•
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further declines or volatility in the prices we receive for our oil, natural gas liquids and natural gas;
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•
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general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;
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•
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ability of our customers to meet their obligations to us;
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•
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our access to capital;
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•
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our ability to obtain in a timely manner confirmation of a successful plan of reorganization in the Company’s current bankruptcy court proceeding;
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•
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our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;
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•
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the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;
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•
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uncertainties associated with estimates of proved oil and gas reserves;
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•
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the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);
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•
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environmental risks;
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•
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seasonal weather conditions;
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•
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lease stipulations;
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•
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drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;
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•
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our ability to acquire adequate supplies of water for drilling and completion operations;
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•
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availability of oilfield equipment, services and personnel;
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•
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exploration and development risks;
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•
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competition in the oil and natural gas industry;
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•
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management’s ability to execute our plans to meet our goals;
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•
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our ability to attract and retain key members of our senior management and key technical employees;
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•
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our ability to maintain effective internal controls;
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•
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access to adequate gathering systems and pipeline take-away capacity to provide adequate infrastructure for the products of our drilling program;
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•
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our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
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•
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costs and other risks associated with perfecting title for mineral rights in some of our properties;
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•
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continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and
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•
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other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.
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(i)
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Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
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(ii)
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Same environment of deposition;
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(iii)
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Similar geological structure; and
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(iv)
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Same drive mechanism.
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(i)
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The area of the reservoir considered as proved includes:
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(a)
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The area identified by drilling and limited by fluid contacts, if any, and
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(b)
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Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
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(ii)
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In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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(iii)
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Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher potions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
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(iv)
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Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
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(a)
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Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and
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(b)
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The project has been approved for development by all necessary parties and entities, including governmental entities.
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(v)
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Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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Natural
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||||
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Crude
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Natural
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Gas
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Total
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Oil
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Gas
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Liquids
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Proved
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||||
Estimated Proved Reserves
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(MBbls)
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(MMcf)
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(MBbls)
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(MBoe)
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||||
Developed
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||||
Rocky Mountain
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18,735
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62,097
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8,792
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37,877
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Mid-Continent
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7,578
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23,875
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1,159
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12,716
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26,313
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85,972
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9,951
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50,593
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Undeveloped
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||||
Rocky Mountain
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23,783
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52,073
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7,596
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40,057
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Mid-Continent
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—
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—
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—
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—
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23,783
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52,073
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7,596
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40,057
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Total Proved
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50,096
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138,045
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17,547
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90,650
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Sales Volumes for
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|||||||||||
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the Year Ended
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Net Proved
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|||||||||||
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Estimated Proved Reserves at
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December 31,
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Undeveloped
|
||||||||||||||||||
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December 31, 2016
(1)
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2016
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Drilling
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||||||||||||||||||
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Average Net
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Projected
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Locations
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||||||||||
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Total
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Daily Sales
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2017 Capital
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as of
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||||||||||
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Proved
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% of
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% Proved
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PV-10
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Volumes
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% of
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Expenditures
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December 31,
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|||||||||||
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(MBoe)
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Total
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Developed
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($ in MM)
(2)
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(Boe/d)
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Total
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($ in millions)
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2016
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|||||||||||
Rocky Mountain
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77,934
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86
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%
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49
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%
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$
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201.4
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17,619
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|
81
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%
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$
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160-175
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163.4
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Mid-Continent
(3)
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12,716
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14
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%
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100
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%
|
|
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75.5
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4,063
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19
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%
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|
3-5
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—
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Total
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90,650
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100
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%
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56
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%
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$
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276.9
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21,682
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100
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%
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$
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163-180
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163.4
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(1)
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Proved reserves and related future net revenue and PV-10 were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices for each of the preceding twelve months, which were
$42.75
per Bbl WTI and
$2.48
per MMBtu HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of
$4.33
per Bbl of crude oil and a decrease of
$0.41
per MMBtu of natural gas.
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(2)
|
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil, natural gas, and natural gas liquid reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices, after adjustment for differentials in location and quality, for each of the preceding twelve months. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating the Company and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. PV-10 differs from Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) because it does not include the effect of future income taxes. Please refer to the
Reconciliation of PV-10 to Standardized Measure
presented in the “Reserves” subsection of Item 1 below.
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(3)
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Mid-Continent sales volumes were
4,063
Boe/d for
2016
, which is comprised of 3,653 Boe/d of production net to our interest and 410 Boe/d sales volumes from our percentage-of-proceeds contracts.
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At December 31,
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|||||||
Region/Field
|
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2016
|
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2015
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2014
|
|||
|
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(MMBoe)
|
|||||||
Rocky Mountain
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78.0
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|
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80.1
|
|
|
68.1
|
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Wattenberg
|
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77.8
|
|
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79.8
|
|
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67.8
|
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North Park
|
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0.2
|
|
|
0.3
|
|
|
0.3
|
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Mid-Continent
|
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12.7
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|
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21.2
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|
|
21.4
|
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Dorcheat Macedonia
|
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11.6
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|
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20.1
|
|
|
19.9
|
|
McKamie Patton
|
|
1.1
|
|
|
1.1
|
|
|
1.5
|
|
Total
|
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90.7
|
|
|
101.3
|
|
|
89.5
|
|
|
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At December 31,
|
|
|||||||
|
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2016
|
|
2015
|
|
2014
|
|
|||
Reserve Data
(1)
:
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|
|
|
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|
|||
Estimated proved reserves:
|
|
|
|
|
|
|
|
|||
Oil (MMBbls)
|
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50.1
|
|
|
57.4
|
|
|
54.7
|
|
|
Natural gas (Bcf)
|
|
138.0
|
|
|
144.2
|
|
|
188.6
|
|
|
Natural gas liquids (MMBbls)
|
|
17.5
|
|
|
19.9
|
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|
3.4
|
|
|
Total estimated proved reserves (MMBoe)
(2)
|
|
90.7
|
|
|
101.3
|
|
|
89.5
|
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Percent oil and liquids
|
|
75
|
%
|
|
76
|
%
|
|
65
|
%
|
|
Estimated proved developed reserves:
|
|
|
|
|
|
|
|
|||
Oil (MMBbls)
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|
26.3
|
|
|
28.9
|
|
|
28.3
|
|
|
Natural gas (Bcf)
|
|
86.0
|
|
|
77.5
|
|
|
94.5
|
|
|
Natural gas liquids (MMBbls)
|
|
10.0
|
|
|
10.4
|
|
|
2.2
|
|
|
Total estimated proved developed reserves (MMBoe)
(2)
|
|
50.6
|
|
|
52.2
|
|
|
46.3
|
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Percent oil and liquids
|
|
72
|
%
|
|
75
|
%
|
|
66
|
%
|
|
Estimated proved undeveloped reserves:
|
|
|
|
|
|
|
|
|||
Oil (MMBbls)
|
|
23.8
|
|
|
28.5
|
|
|
26.4
|
|
|
Natural gas (Bcf)
|
|
52.0
|
|
|
66.7
|
|
|
94.1
|
|
|
Natural gas liquids (MMBbls)
|
|
7.5
|
|
|
9.6
|
|
|
1.2
|
|
|
Total estimated proved undeveloped reserves (MMBoe)
(2)
|
|
40.1
|
|
|
49.2
|
|
|
43.2
|
|
|
Percent oil and liquids
|
|
78
|
%
|
|
77
|
%
|
|
64
|
%
|
|
(1)
|
Proved reserves were calculated using the preceding twelve month unweighted arithmetic average of the first-day-of-the-month prices, which were
$42.75
per Bbl WTI and
$2.48
per MMBtu HH,
$50.28
per Bbl WTI and
$2.59
per MMBtu HH, and
$94.99
per Bbl WTI and
$4.35
per MMBtu HH for the years ended
December 31, 2016
,
2015
and
2014
, respectively. Adjustments were made for location and grade.
|
(2)
|
Determined using the ratio of 6 Mcf of natural gas to one Bbl of crude oil.
|
|
|
December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in millions)
|
||||||||||
PV-10
|
|
$
|
276.9
|
|
|
$
|
327.8
|
|
|
$
|
1,340.5
|
|
Present value of future income taxes discounted at 10%
(1)
|
|
|
—
|
|
|
|
—
|
|
|
|
(233.1
|
)
|
Standardized Measure
|
|
$
|
276.9
|
|
|
$
|
327.8
|
|
|
$
|
1,107.4
|
|
|
|
Net Reserves, MBoe
|
|||||||
|
|
At December 31,
|
|||||||
|
|
2016
|
|
2015
|
|
2014
|
|||
Beginning of year
|
|
49,184
|
|
|
43,246
|
|
|
37,603
|
|
Converted to proved developed
|
|
(1,352
|
)
|
|
(6,994
|
)
|
|
(7,791
|
)
|
Additions from capital program
|
|
—
|
|
|
2,308
|
|
|
5,596
|
|
Acquisitions
|
|
—
|
|
|
1,541
|
|
|
—
|
|
Revisions
|
|
(7,775
|
)
|
|
9,083
|
|
|
7,838
|
|
End of year
|
|
40,057
|
|
|
49,184
|
|
|
43,246
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
(1)
|
||||||
Oil:
|
|
|
|
|
|
|
|
|
|
|||
Total Production (MBbls)
|
|
|
4,309.9
|
|
|
|
6,072.3
|
|
|
|
5,618.7
|
|
Wattenberg Field
|
|
|
3,470.7
|
|
|
|
5,029.6
|
|
|
|
4,486.4
|
|
Dorcheat Macedonia Field
|
|
|
750.0
|
|
|
|
923.2
|
|
|
|
1,025.6
|
|
Average sales price (per Bbl), including derivatives
(4)
|
|
$
|
39.68
|
|
|
$
|
62.10
|
|
|
$
|
84.00
|
|
Average sales price (per Bbl), excluding derivatives
(4)
|
|
$
|
35.42
|
|
|
$
|
40.98
|
|
|
$
|
81.95
|
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|||
Total Production (MMcf)
|
|
|
11,906.3
|
|
|
|
14,110.9
|
|
|
|
15,316.1
|
|
Wattenberg Field
|
|
|
9,574.8
|
|
|
|
11,020.8
|
|
|
|
11,372.7
|
|
Dorcheat Macedonia Field
|
|
|
2,331.4
|
|
|
|
3,090.5
|
|
|
|
4,030.6
|
|
Average sales price (per Mcf), including derivatives
(5)
|
|
$
|
1.88
|
|
|
$
|
2.01
|
|
|
$
|
5.16
|
|
Average sales price (per Mcf), excluding derivatives
(5)
|
|
$
|
1.88
|
|
|
$
|
1.82
|
|
|
$
|
5.11
|
|
Natural Gas Liquids:
|
|
|
|
|
|
|
|
|
|
|||
Total Production (MBbls)
|
|
|
1,491.1
|
|
|
|
1,675.9
|
|
|
|
260.6
|
|
Wattenberg Field
|
|
|
1,354.3
|
|
|
|
1,489.9
|
|
|
|
16.8
|
|
Dorcheat Macedonia Field
|
|
|
136.8
|
|
|
|
186
|
|
|
|
243.8
|
|
Average sales price (per Bbl), including derivatives
|
|
$
|
12.39
|
|
|
$
|
9.49
|
|
|
$
|
49.14
|
|
Average sales price (per Bbl), excluding derivatives
|
|
$
|
12.39
|
|
|
$
|
9.49
|
|
|
$
|
49.14
|
|
Oil Equivalents:
|
|
|
|
|
|
|
|
|
|
|||
Total Production (MBoe)
|
|
|
7,785.4
|
|
|
|
10,100.0
|
|
|
|
8,365.6
|
|
Wattenberg Field
|
|
|
6,420.8
|
|
|
|
8,356.3
|
|
|
|
6,398.6
|
|
Dorcheat Macedonia Field
|
|
|
1,275.4
|
|
|
|
1,624.2
|
|
|
|
1,874.7
|
|
Average Daily Production (Boe/d)
|
|
|
21,271.7
|
|
|
|
27,671.2
|
|
|
|
22,919.3
|
|
Wattenberg Field
|
|
|
17,543.4
|
|
|
|
22,894.1
|
|
|
|
17,530.5
|
|
Dorcheat Macedonia Field
|
|
|
3,484.5
|
|
|
|
4,450
|
|
|
|
5,136.3
|
|
Average Production Costs (per Boe)
(3)(2)
|
|
$
|
7.25
|
|
|
$
|
7.56
|
|
|
$
|
8.66
|
|
(1)
|
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold during 2014.
|
(2)
|
Excludes ad valorem and severance taxes.
|
(3)
|
Represents lease operating expense and gas plant and midstream operating expense per Boe using total production volumes of 7,785.4 MBoe, 10,100.0 MBoe and 8,365.6 MBoe for 2016, 2015 and 2014, respectively. Total production volumes exclude volumes from our percentage-of-proceeds contracts in our Mid-Continent region of 150.1 MBoe, 219.4 MBoe and 215.3 MBoe for 2016, 2015 and 2014, respectively.
|
(4)
|
Crude oil sales includes $0.5 million and $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2016 and 2015, respectively. There was no oil transportation revenues for the year ended December 31, 2014.
|
(5)
|
Natural gas sales includes $1.5 million and $0.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2016 and 2015, respectively. There was no gas gathering transportation revenues for the year ended December 31, 2014.
|
|
|
Oil
(2)
|
|
Natural Gas
(1)
|
|
Total
(2)
|
|
Operated
(2)
|
|||||||||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|||||||||||
Rocky Mountain
|
|
681
|
|
|
567.6
|
|
|
—
|
|
|
—
|
|
|
681
|
|
|
567.6
|
|
|
594
|
|
|
551.6
|
|
|||
Mid-Continent
|
|
308
|
|
|
264.5
|
|
|
—
|
|
|
—
|
|
|
308
|
|
|
264.5
|
|
|
308
|
|
|
264.5
|
|
|||
Total
(2)
|
|
989
|
|
|
832.1
|
|
|
—
|
|
|
—
|
|
|
989
|
|
|
832.1
|
|
|
902
|
|
|
816.1
|
|
(1)
|
All gas production is associated gas from producing oil wells.
|
(2)
|
Count came from internal production reporting system.
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|||||||||
|
|
Developed Acres
|
|
Acres
|
|
Total Acres
|
|
|
|
|||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
PV-10
|
||||||||
Rocky Mountain
|
|
74,856
|
|
|
61,200
|
|
|
40,409
|
|
|
20,914
|
|
|
115,265
|
|
|
82,114
|
|
|
$
|
201,434
|
|
Wattenberg Field
|
|
60,173
|
|
|
49,378
|
|
|
35,505
|
|
|
17,949
|
|
|
95,678
|
|
|
67,327
|
|
|
|
201,245
|
|
Other Rocky Mountain
|
|
14,683
|
|
|
11,822
|
|
|
4,904
|
|
|
2,965
|
|
|
19,587
|
|
|
14,787
|
|
|
|
189
|
|
Mid-Continent
|
|
11,795
|
|
|
10,036
|
|
|
2,505
|
|
|
1,285
|
|
|
14,300
|
|
|
11,321
|
|
|
|
75,521
|
|
Dorcheat Macedonia Field
|
|
4,919
|
|
|
3,443
|
|
|
1,481
|
|
|
684
|
|
|
6,400
|
|
|
4,127
|
|
|
|
61,561
|
|
Other Mid-Continent
|
|
6,876
|
|
|
6,593
|
|
|
1,024
|
|
|
601
|
|
|
7,900
|
|
|
7,194
|
|
|
|
13,960
|
|
Total
|
|
86,651
|
|
|
71,236
|
|
|
42,914
|
|
|
22,199
|
|
|
129,565
|
|
|
93,435
|
|
|
$
|
276,955
|
|
|
|
Expiring 2017
|
|
Expiring 2018
|
|
Expiring 2019
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Rocky Mountain
|
|
6,241
|
|
|
4,597
|
|
|
7,047
|
|
|
4,071
|
|
|
1,659
|
|
|
444
|
|
Mid-Continent
|
|
260
|
|
|
212
|
|
|
42
|
|
|
8
|
|
|
40
|
|
|
9
|
|
Total
|
|
6,501
|
|
|
4,809
|
|
|
7,089
|
|
|
4,079
|
|
|
1,699
|
|
|
453
|
|
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive Wells
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry Wells
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1.8
|
|
|
—
|
|
|
—
|
|
Total Exploratory
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1.8
|
|
|
—
|
|
|
—
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive Wells
|
|
4
|
|
|
3.9
|
|
|
92
|
|
|
76.1
|
|
|
142
|
|
|
124.3
|
|
Dry Wells
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1.4
|
|
|
—
|
|
|
—
|
|
Total Development
|
|
4
|
|
|
3.9
|
|
|
94
|
|
|
77.5
|
|
|
142
|
|
|
124.3
|
|
Total
|
|
4
|
|
|
3.9
|
|
|
96
|
|
|
79.3
|
|
|
142
|
|
|
124.3
|
|
|
|
As of December 31, 2016
|
||||
|
|
Gross
|
|
Net
|
||
Exploratory
|
|
|
|
|
||
Rocky Mountain
|
|
—
|
|
|
—
|
|
Mid-Continent
|
|
—
|
|
|
—
|
|
Total Exploratory
|
|
—
|
|
|
—
|
|
Development
|
|
|
|
|
||
Rocky Mountain
|
|
6
|
|
|
4.5
|
|
Mid-Continent
|
|
—
|
|
|
—
|
|
Total Development
|
|
6
|
|
|
4.5
|
|
Total
|
|
6
|
|
|
4.5
|
|
•
|
our ability to prosecute, confirm and consummate a plan of reorganization with respect to the Chapter 11 cases;
|
•
|
the high costs of bankruptcy cases and related fees;
|
•
|
our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;
|
•
|
our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;
|
•
|
our ability to maintain contracts that are critical to our operations;
|
•
|
our ability to safely and efficiently re-start operations after a protracted period of minimal activity;
|
•
|
our ability to execute competitive contracts with third party contractors while tainted with a bankruptcy legacy;
|
•
|
our ability to execute our business plan in the current commodity price environment;
|
•
|
our ability to attract, motivate and retain key employees;
|
•
|
the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;
|
•
|
our ability to retain our current management team if a trustee is appointed;
|
•
|
the ability of third parties to seek and obtain court approval to convert the Chapter 11 cases to a Chapter 7 proceeding; and
|
•
|
the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 cases that may be inconsistent with our plans.
|
•
|
worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
|
•
|
the actions from members of the Organization of Petroleum Exporting Countries and other oil producing nations;
|
•
|
the price and quantity of imports of foreign oil and natural gas;
|
•
|
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
|
•
|
the level of global oil and natural gas exploration and production;
|
•
|
the level of global oil and natural gas inventories;
|
•
|
localized supply and demand fundamentals and transportation availability;
|
•
|
weather conditions and natural disasters;
|
•
|
domestic and foreign governmental regulations;
|
•
|
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
|
•
|
the price and availability of competitors' supplies of oil and natural gas;
|
•
|
technological advances affecting energy consumption;
|
•
|
variability in subsurface reservoir characteristics, particularly in areas with immature development history;
|
•
|
the availability of pipeline capacity and infrastructure; and
|
•
|
the price and availability of alternative fuels.
|
•
|
reduction of our revenues, profit margins, operating income and cash flows;
|
•
|
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically and may lead to reduced liquidity and the inability to pay our liabilities as they come due;
|
•
|
certain properties in our portfolio becoming economically unviable;
|
•
|
delay or postponement of some of our capital projects;
|
•
|
significant reductions in future capital programs, resulting in a reduced ability to develop our reserves;
|
•
|
limitations on our financial condition, liquidity and/or ability to finance planned capital expenditures and operations;
|
•
|
reduction to the borrowing base under our revolving credit facility or limitations in our access to sources of capital, such as equity or debt;
|
•
|
declines in our stock price;
|
•
|
refinery industry demand for crude oil;
|
•
|
storage availability for crude oil;
|
•
|
the ability of our vendors, suppliers, and customers to continue operations due to the prevailing adverse market conditions;
|
•
|
asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment.
|
•
|
shortages of or delays in obtaining equipment and qualified personnel;
|
•
|
facility or equipment malfunctions;
|
•
|
unexpected operational events;
|
•
|
unanticipated environmental liabilities;
|
•
|
pressure or irregularities in geological formations;
|
•
|
adverse weather conditions, such as blizzards, ice storms, tornadoes, floods, and fires;
|
•
|
reductions in oil and natural gas prices;
|
•
|
delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays;
|
•
|
proximity to and capacity of transportation facilities;
|
•
|
title problems;
|
•
|
safety concerns, and
|
•
|
limitations in the market for oil and natural gas.
|
•
|
actual prices we receive for oil and natural gas and hedging instruments;
|
•
|
actual cost of development and production expenditures;
|
•
|
the amount and timing of actual production;
|
•
|
the amount and timing of future development costs;
|
•
|
wellbore productivity realizations above or below type curve forecast models;
|
•
|
the supply and demand of oil and natural gas; and
|
•
|
changes in governmental regulations or taxation.
|
•
|
landing our well bore in the desired drilling zone;
|
•
|
effectively controlling the level of pressure flowing from particular wells;
|
•
|
staying in the desired drilling zone while drilling horizontally through the formation;
|
•
|
running our casing the entire length of the wellbore;
|
•
|
running tools and other equipment consistently through the horizontal wellbore;
|
•
|
fracture stimulating the planned number of stages;
|
•
|
preventing downhole communications with other wells;
|
•
|
successfully cleaning out the well bore after completion of the final fracture stimulation stage; and
|
•
|
designing and maintaining efficient forms of artificial lift throughout the life of the well.
|
•
|
environmental hazards, such as spills, uncontrollable flows of oil, natural gas, brine, well fluids, natural gas, hazardous air pollutants or other pollution into the environment, including groundwater and shoreline contamination;
|
•
|
releases of natural gas and hazardous air pollutants or other substances into the atmosphere (including releases at our gas processing facilities);
|
•
|
hazards resulting from the presence of hydrogen sulfide (H
2
S) or other contaminants in natural gas we produce;
|
•
|
abnormally pressured formations resulting in well blowouts, fires or explosions;
|
•
|
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
|
•
|
cratering (catastrophic failure);
|
•
|
downhole communication leading to migration of contaminants;
|
•
|
personal injuries and death; and
|
•
|
natural disasters.
|
•
|
injury or loss of life;
|
•
|
damage to and destruction of property, natural resources and equipment;
|
•
|
pollution and other environmental damage;
|
•
|
regulatory investigations and penalties;
|
•
|
suspension of our operations; and
|
•
|
repair and remediation costs.
|
•
|
delay or denial of drilling permits;
|
•
|
shortening of lease terms or reduction in lease size;
|
•
|
restrictions on installation or operation of production, gathering or processing facilities;
|
•
|
restrictions on the use of certain operating practices, such as hydraulic fracturing, or the disposal of related waste materials, such as hydraulic fracturing fluids and produced water;
|
•
|
increased severance and/or other taxes;
|
•
|
cyber-attacks;
|
•
|
legal challenges or lawsuits;
|
•
|
negative publicity about us or the oil and gas industry in general;
|
•
|
increased costs of doing business;
|
•
|
reduction in demand for our products; and
|
•
|
other adverse effects on our ability to develop our properties and expand production.
|
•
|
production is less than the volume covered by the derivative instruments;
|
•
|
the counterparty to the derivative instrument defaults on its contract obligations; or
|
•
|
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
|
•
|
a classified board of directors, so that only approximately one-third of our directors are elected each year;
|
•
|
advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and
|
•
|
limitations on the ability of our stockholders to call special meetings or act by written consent.
|
|
|
High
|
|
Low
|
||||
2015
|
|
|
|
|
|
|
||
1st Quarter
|
|
$
|
30.81
|
|
|
$
|
20.23
|
|
2nd Quarter
|
|
|
30.69
|
|
|
|
17.35
|
|
3rd Quarter
|
|
|
18.18
|
|
|
|
3.93
|
|
4th Quarter
|
|
|
9.54
|
|
|
|
3.72
|
|
2016
|
|
|
|
|
|
|
||
1st Quarter
|
|
$
|
5.50
|
|
|
$
|
0.88
|
|
2nd Quarter
|
|
|
4.67
|
|
|
|
1.25
|
|
3rd Quarter
|
|
|
2.35
|
|
|
|
0.60
|
|
4th Quarter
|
|
|
2.35
|
|
|
|
0.67
|
|
|
|
|
|
|
|
|
Maximum
|
|||||
|
|
|
|
|
Total Number of
|
|
Number of
|
|||||
|
Total
|
|
|
|
Shares
|
|
Shares that May
|
|||||
|
Number of
|
|
Average Price
|
|
Purchased as Part of
|
|
Be Purchased
|
|||||
|
Shares
|
|
Paid per
|
|
Publicly Announced
|
|
Under Plans or
|
|||||
|
Purchased
(1)
|
|
Share
|
|
Plans or Programs
|
|
Programs
|
|||||
January 1, 2016 - March 31, 2016
|
109,433
|
|
|
$
|
2.02
|
|
|
—
|
|
|
—
|
|
April 1, 2016 - June 30, 2016
|
5,762
|
|
|
$
|
2.65
|
|
|
—
|
|
|
—
|
|
July 1, 2016 - September 30, 2016
|
7,916
|
|
|
$
|
1.13
|
|
|
—
|
|
|
—
|
|
October 1, 2016 - October 31, 2016
|
421
|
|
|
$
|
1.06
|
|
|
—
|
|
|
—
|
|
November 1, 2016 - November 30, 2016
|
3,226
|
|
|
$
|
0.99
|
|
|
—
|
|
|
—
|
|
December 1, 2016 - December 31, 2016
|
1,146
|
|
|
$
|
1.59
|
|
|
—
|
|
|
—
|
|
Total
|
127,904
|
|
|
$
|
1.96
|
|
|
—
|
|
|
—
|
|
(1)
|
Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced plan or program to repurchase shares of our common stock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
||||||||||
|
|
(in thousands, except per share amounts)
|
||||||||||||||||||
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total operating net revenues
(1)
|
|
$
|
231,205
|
|
|
$
|
421,860
|
|
|
$
|
558,633
|
|
|
$
|
292,679
|
|
|
$
|
195,295
|
|
Income (loss) from operations
(1)
|
|
|
77,903
|
|
|
|
146,995
|
|
|
|
(47,506
|
)
|
|
|
(907,444
|
)
|
|
|
(129,110
|
)
|
Net income (loss)
|
|
|
46,523
|
|
|
|
69,184
|
|
|
|
20,283
|
|
|
|
(745,547
|
)
|
|
|
(198,950
|
)
|
Basic net income (loss) per common share
|
|
$
|
1.17
|
|
|
$
|
1.72
|
|
|
$
|
0.50
|
|
|
$
|
(15.57
|
)
|
|
$
|
(4.04
|
)
|
Basic weighted-average common shares outstanding
|
|
|
39,052
|
|
|
|
39,337
|
|
|
|
40,139
|
|
|
|
47,874
|
|
|
|
49,268
|
|
Diluted net income (loss) per common share
|
|
$
|
1.17
|
|
|
$
|
1.71
|
|
|
$
|
0.49
|
|
|
$
|
(15.57
|
)
|
|
$
|
(4.04
|
)
|
Diluted weighted-average common shares outstanding
|
|
|
39,052
|
|
|
|
39,403
|
|
|
|
40,290
|
|
|
|
47,874
|
|
|
|
49,268
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Cash and cash equivalents
|
|
$
|
4,268
|
|
|
$
|
180,582
|
|
|
$
|
2,584
|
|
|
$
|
21,341
|
|
|
$
|
80,565
|
|
Property and equipment, net (excludes assets held for sale)
|
|
|
943,175
|
|
|
|
1,267,249
|
|
|
|
1,756,477
|
|
|
|
922,344
|
|
|
|
1,018,968
|
|
Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization
|
|
|
582
|
|
|
|
360
|
|
|
|
—
|
|
|
|
214,922
|
|
|
|
—
|
|
Total assets
|
|
|
1,002,490
|
|
|
|
1,541,812
|
|
|
|
1,990,086
|
|
|
|
1,259,641
|
|
|
|
1,134,478
|
|
Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Credit facility
|
|
|
158,000
|
|
|
|
—
|
|
|
|
33,000
|
|
|
|
79,000
|
|
|
|
191,667
|
|
Senior Notes, net of unamortized premium and deferred financing costs
|
|
|
—
|
|
|
|
504,724
|
|
|
|
791,616
|
|
|
|
792,666
|
|
|
|
793,698
|
|
Total stockholders’ equity
|
|
$
|
578,518
|
|
|
$
|
656,028
|
|
|
$
|
740,071
|
|
|
$
|
209,407
|
|
|
$
|
19,061
|
|
Selected Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Net cash provided by operating activities
|
|
$
|
156,911
|
|
|
$
|
295,685
|
|
|
$
|
339,958
|
|
|
$
|
226,023
|
|
|
$
|
14,563
|
|
Net cash used in investing activities
|
|
|
(304,552
|
)
|
|
|
(453,893
|
)
|
|
|
(837,232
|
)
|
|
|
(452,573
|
)
|
|
|
(67,401
|
)
|
Net cash provided by financing activities
|
|
$
|
149,819
|
|
|
$
|
334,522
|
|
|
$
|
319,276
|
|
|
$
|
245,307
|
|
|
$
|
112,062
|
|
Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MBbls)
|
|
|
2,191.0
|
|
|
|
3,887.2
|
|
|
|
5,618.7
|
|
|
|
6,072.3
|
|
|
|
4,309.9
|
|
Natural gas (MMcf)
|
|
|
5,473.2
|
|
|
|
9,975.9
|
|
|
|
15,395.8
|
|
|
|
14,551.1
|
|
|
|
12,231.3
|
|
Natural gas liquids (MBbls)
|
|
|
284.7
|
|
|
|
352.8
|
|
|
|
396.3
|
|
|
|
1,821.9
|
|
|
|
1,587.0
|
|
Estimated Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MMBbls)
|
|
|
30.2
|
|
|
|
43.6
|
|
|
|
54.7
|
|
|
|
57.4
|
|
|
|
50.1
|
|
Natural gas (Bcf)
|
|
|
118.5
|
|
|
|
139.6
|
|
|
|
188.6
|
|
|
|
144.2
|
|
|
|
138.0
|
|
Natural gas liquids (MMBbls)
|
|
|
3.1
|
|
|
|
2.9
|
|
|
|
3.4
|
|
|
|
19.9
|
|
|
|
17.5
|
|
Total proved reserves (MMBoe)
|
|
|
53.0
|
|
|
|
69.8
|
|
|
|
89.5
|
|
|
|
101.3
|
|
|
|
90.7
|
|
Average Sales Price (before derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MBbls)
|
|
$
|
89.08
|
|
|
$
|
91.84
|
|
|
$
|
81.95
|
|
|
$
|
40.98
|
|
|
$
|
35.42
|
|
Natural gas (MMcf)
|
|
$
|
3.62
|
|
|
$
|
4.66
|
|
|
$
|
5.11
|
|
|
$
|
1.82
|
|
|
$
|
1.88
|
|
Natural gas liquids (MBbls)
|
|
$
|
55.54
|
|
|
$
|
51.74
|
|
|
$
|
49.14
|
|
|
$
|
9.49
|
|
|
$
|
12.39
|
|
Average Sales Price (after derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MBbls)
|
|
$
|
88.40
|
|
|
$
|
88.82
|
|
|
$
|
84.00
|
|
|
$
|
62.10
|
|
|
$
|
39.68
|
|
Natural gas (MMcf)
|
|
$
|
3.76
|
|
|
$
|
4.70
|
|
|
$
|
5.16
|
|
|
$
|
2.01
|
|
|
$
|
1.88
|
|
Natural gas liquids (MBbls)
|
|
$
|
55.54
|
|
|
$
|
51.74
|
|
|
$
|
49.14
|
|
|
$
|
9.49
|
|
|
$
|
12.39
|
|
Expense per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Lease operating expense and gas plant and midstream operating expense
|
|
$
|
9.06
|
|
|
$
|
8.09
|
|
|
$
|
8.44
|
|
|
$
|
7.40
|
|
|
$
|
7.12
|
|
Severance and ad valorem taxes
|
|
$
|
4.04
|
|
|
$
|
4.61
|
|
|
$
|
5.88
|
|
|
$
|
1.81
|
|
|
$
|
1.93
|
|
Depreciation, depletion, and amortization
|
|
$
|
19.54
|
|
|
$
|
23.75
|
|
|
$
|
26.66
|
|
|
$
|
23.73
|
|
|
$
|
14.01
|
|
General and administrative
|
|
$
|
9.27
|
|
|
$
|
9.40
|
|
|
$
|
9.51
|
|
|
$
|
6.81
|
|
|
$
|
9.71
|
|
(1)
|
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or held for sale as of December 31, 2014, 2013 and 2012.
|
•
|
Total liquidity of
$38.9 million
at
December 31, 2016
, consisting of, year-end cash balance net of the borrowing base deficiency under the revolving credit facility, as compared with $405.3 million, consisting of, year-end cash balance plus funds available under our revolving credit facility at
December 31, 2015
. Please refer to
Liquidity and Capital Resources
below for additional discussion;
|
•
|
Lease operating expense in aggregate and on a per Boe basis was down
33%
and
13%
, respectively, from 2015 due to decreased operating costs and reduced activity levels;
|
•
|
Cash flows provided by operating activities of
$14.6 million
, as compared with
$226.0 million
in
2015
. Please refer to
Liquidity and Capital Resources
below for additional discussion;
|
•
|
Full year capital expenditures were $21.7 million;
|
•
|
Net loss of
$199.0 million
, as compared with a net loss of
$745.5 million
for
2015
;
|
•
|
Decreased sales volumes by
23%
to
7.9
MMBoe in
2016
from
10.3
MMBoe in
2015
, with oil and NGL production representing
74%
of total sales volumes;
|
•
|
Decreased proved reserves by
10%
to
90.7
MMBoe as of
December 31, 2016
, from 101.3 MMBoe as of
December 31, 2015
.
|
|
|
For the Years Ended December 31,
|
||||||||||||
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
Percent Change
|
||||
|
|
(In thousands, except percentages)
|
||||||||||||
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil sales
(1)
|
$
|
152,673
|
|
|
$
|
248,862
|
|
|
$
|
(96,189
|
)
|
|
(39
|
)%
|
Natural gas sales
(2)
|
|
22,962
|
|
|
|
26,528
|
|
|
|
(3,566
|
)
|
|
(13
|
)%
|
Natural gas liquids sales
|
|
19,660
|
|
|
|
17,289
|
|
|
|
2,371
|
|
|
14
|
%
|
Product revenue
|
$
|
195,295
|
|
|
$
|
292,679
|
|
|
$
|
(97,384
|
)
|
|
(33
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (MBbls)
|
|
4,309.9
|
|
|
|
6,072.3
|
|
|
|
(1,762.4
|
)
|
|
(29
|
)%
|
Natural gas (MMcf)
|
|
12,231.3
|
|
|
|
14,551.1
|
|
|
|
(2,319.8
|
)
|
|
(16
|
)%
|
Natural gas liquids (MBbls)
|
|
1,587.0
|
|
|
|
1,821.9
|
|
|
|
(234.9
|
)
|
|
(13
|
)%
|
Crude oil equivalent (MBoe)
(3)
|
|
7,935.5
|
|
|
|
10,319.4
|
|
|
|
(2,383.9
|
)
|
|
(23
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Average Sales Prices (before derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per Bbl)
|
$
|
35.42
|
|
|
$
|
40.98
|
|
|
$
|
(5.56
|
)
|
|
(14
|
)%
|
Natural gas (per Mcf)
|
$
|
1.88
|
|
|
$
|
1.82
|
|
|
$
|
0.06
|
|
|
3
|
%
|
Natural gas liquids (per Bbl)
|
$
|
12.39
|
|
|
$
|
9.49
|
|
|
$
|
2.90
|
|
|
31
|
%
|
Crude oil equivalent (per Boe)
(3)
|
$
|
24.61
|
|
|
$
|
28.36
|
|
|
$
|
(3.75
|
)
|
|
(13
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Average Sales Prices (after derivatives)
(4)
:
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
39.68
|
|
|
$
|
62.10
|
|
|
$
|
(22.42
|
)
|
|
(36
|
)%
|
Natural gas (per Mcf)
|
$
|
1.88
|
|
|
$
|
2.01
|
|
|
$
|
(0.13
|
)
|
|
(6
|
)%
|
Natural gas liquids (per Bbl)
|
$
|
12.39
|
|
|
$
|
9.49
|
|
|
$
|
2.90
|
|
|
31
|
%
|
Crude oil equivalent (per Boe)
(3)
|
$
|
26.92
|
|
|
$
|
41.06
|
|
|
$
|
(14.14
|
)
|
|
(34
|
)%
|
(1)
|
Crude oil sales includes $0.5 million and $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2016 and 2015, respectively.
|
(2)
|
Natural gas sales includes $1.5 million and $0.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2016 and 2015, respectively.
|
(3)
|
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
|
(4)
|
The derivatives economically hedge the price we receive for crude oil and natural gas. For the years ended
December 31, 2016
and
2015
, the derivative cash settlement gain for oil contracts was
$18.3 million
and
$128.3 million
, respectively, and the derivative cash settlement gain for gas contracts was
$2.7 million
for the year ended December 31, 2015. Please refer to
Part II, Item 8, Note 13 - Derivatives
for additional disclosures.
|
|
|
For the Years Ended December 31,
|
||||||||||||
|
|
2016
|
|
|
2015
|
|
|
Change
|
|
Percent Change
|
||||
|
|
(In thousands, except percentages)
|
||||||||||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
43,671
|
|
|
$
|
65,038
|
|
|
$
|
(21,367
|
)
|
|
(33
|
)%
|
Gas plant and midstream operating expense
|
|
12,826
|
|
|
|
11,368
|
|
|
|
1,458
|
|
|
13
|
%
|
Severance and ad valorem taxes
|
|
15,304
|
|
|
|
18,629
|
|
|
|
(3,325
|
)
|
|
(18
|
)%
|
Exploration
|
|
946
|
|
|
|
15,827
|
|
|
|
(14,881
|
)
|
|
(94
|
)%
|
Depreciation, depletion and amortization
|
|
111,215
|
|
|
|
244,921
|
|
|
|
(133,706
|
)
|
|
(55
|
)%
|
Impairment of oil and gas properties
|
|
10,000
|
|
|
|
740,478
|
|
|
|
(730,478
|
)
|
|
(99
|
)%
|
Abandonment and impairment of unproved properties
|
|
24,692
|
|
|
|
33,543
|
|
|
|
(8,851
|
)
|
|
(26
|
)%
|
Unused commitments
|
|
7,686
|
|
|
|
—
|
|
|
|
7,686
|
|
|
100
|
%
|
Contract settlement expense
|
|
21,000
|
|
|
|
—
|
|
|
|
21,000
|
|
|
100
|
%
|
General and administrative expense
|
|
77,065
|
|
|
|
70,319
|
|
|
|
6,746
|
|
|
10
|
%
|
Operating expenses
|
$
|
324,405
|
|
|
$
|
1,200,123
|
|
|
$
|
(875,718
|
)
|
|
(73
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Selected Costs ($ per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
5.50
|
|
|
$
|
6.30
|
|
|
$
|
(0.80
|
)
|
|
(13
|
)%
|
Gas plant and midstream operating expense
|
|
1.62
|
|
|
|
1.10
|
|
|
|
0.52
|
|
|
47
|
%
|
Severance and ad valorem taxes
|
|
1.93
|
|
|
|
1.81
|
|
|
|
0.12
|
|
|
7
|
%
|
Exploration
|
|
0.12
|
|
|
|
1.53
|
|
|
|
(1.41
|
)
|
|
(92
|
)%
|
Depreciation, depletion and amortization
|
|
14.01
|
|
|
|
23.73
|
|
|
|
(9.72
|
)
|
|
(41
|
)%
|
Impairment of oil and gas properties
|
|
1.26
|
|
|
|
71.76
|
|
|
|
(70.50
|
)
|
|
(98
|
)%
|
Abandonment and impairment of unproved properties
|
|
3.11
|
|
|
|
3.25
|
|
|
|
(0.14
|
)
|
|
(4
|
)%
|
Unused commitments
|
|
0.97
|
|
|
|
—
|
|
|
|
0.97
|
|
|
100
|
%
|
Contract settlement expense
|
|
2.65
|
|
|
|
—
|
|
|
|
2.65
|
|
|
100
|
%
|
General and administrative expense
|
|
9.71
|
|
|
|
6.81
|
|
|
|
2.90
|
|
|
43
|
%
|
Operating expenses
|
$
|
40.88
|
|
|
$
|
116.29
|
|
|
$
|
(75.41
|
)
|
|
(65
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating expenses, excluding impairments and abandonments, unused commitments and contract settlement expense
|
$
|
32.89
|
|
|
$
|
41.28
|
|
|
|
(8.39
|
)
|
|
(20
|
)%
|
|
|
For the Years Ended December 31,
|
||||||||||||
|
|
2015
(1)
|
|
|
2014
(4)
|
|
|
Change
|
|
Percent Change
|
||||
|
|
(In thousands, except percentages)
|
||||||||||||
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil sales
(5)
|
$
|
248,862
|
|
|
$
|
460,442
|
|
|
$
|
(211,580
|
)
|
|
(46
|
)%
|
Natural gas sales
(6)
|
|
26,528
|
|
|
|
78,714
|
|
|
|
(52,186
|
)
|
|
(66
|
)%
|
Natural gas liquids sales
|
|
17,289
|
|
|
|
19,470
|
|
|
|
(2,181
|
)
|
|
(11
|
)%
|
CO2 sales
|
|
—
|
|
|
|
7
|
|
|
|
(7
|
)
|
|
(100
|
)%
|
Product revenue
|
$
|
292,679
|
|
|
$
|
558,633
|
|
|
$
|
(265,954
|
)
|
|
(48
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Sales Volumes:
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (MBbls)
|
|
6,072.3
|
|
|
|
5,618.7
|
|
|
|
453.6
|
|
|
8
|
%
|
Natural gas (MMcf)
|
|
14,551.1
|
|
|
|
15,395.8
|
|
|
|
(844.7
|
)
|
|
(5
|
)%
|
Natural gas liquids (MBbls)
|
|
1,821.9
|
|
|
|
396.2
|
|
|
|
1,425.7
|
|
|
360
|
%
|
Crude oil equivalent (MBoe)
(2)
|
|
10,319.4
|
|
|
|
8,580.9
|
|
|
|
1,738.5
|
|
|
20
|
%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Average Sales Prices (before derivatives):
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
40.98
|
|
|
$
|
81.95
|
|
|
$
|
(40.97
|
)
|
|
(50
|
)%
|
Natural gas (per Mcf)
|
$
|
1.82
|
|
|
$
|
5.11
|
|
|
$
|
(3.29
|
)
|
|
(64
|
)%
|
Natural gas liquids (per Bbl)
|
$
|
9.49
|
|
|
$
|
49.14
|
|
|
$
|
(39.65
|
)
|
|
(81
|
)%
|
Crude oil equivalent (per Boe)
(2)
|
$
|
28.36
|
|
|
$
|
65.10
|
|
|
$
|
(36.74
|
)
|
|
(56
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Average Sales Prices (after derivatives)
(3)
:
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (per Bbl)
|
$
|
62.10
|
|
|
$
|
84.00
|
|
|
$
|
(21.90
|
)
|
|
(26
|
)%
|
Natural gas (per Mcf)
|
$
|
2.01
|
|
|
$
|
5.16
|
|
|
$
|
(3.15
|
)
|
|
(61
|
)%
|
Natural gas liquids (per Bbl)
|
$
|
9.49
|
|
|
$
|
49.14
|
|
|
$
|
(39.65
|
)
|
|
(81
|
)%
|
Crude oil equivalent (per Boe)
(2)
|
$
|
41.06
|
|
|
$
|
66.53
|
|
|
$
|
(25.47
|
)
|
|
(38
|
)%
|
(1)
|
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three-stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
|
(2)
|
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
|
(3)
|
The derivatives economically hedge the price we receive for crude oil and natural gas. For the years ended
December 31, 2015
and
2014
, the derivative cash settlement gain for oil contracts was
$128.3 million
and
$11.5 million
, respectively, and the derivative cash settlement gain for gas contracts was
$2.7 million
and
$0.7 million
, respectively. Please refer to Part II, Item 8
, Note 13 - Derivatives
for additional disclosures.
|
(4)
|
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non‑core properties in California sold or held for sale as of December 31, 2014.
|
(5)
|
Crude oil sales includes $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the year ended December 31, 2015. There was no oil transportation revenues for the year ended December 31, 2014.
|
(6)
|
Natural gas sales includes $0.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the year ended December 31, 2015. There was no gas gathering revenues for the year ended December 31, 2014.
|
|
|
For the Years Ended December 31,
|
||||||||||||
|
|
2015
|
|
|
2014
(2)
|
|
|
Change
|
|
Percent Change
|
||||
|
|
(In thousands, except percentages)
|
||||||||||||
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
$
|
65,038
|
|
|
$
|
59,884
|
|
|
$
|
5,154
|
|
|
9
|
%
|
Gas plant and midstream operating expense
|
|
11,368
|
|
|
|
12,527
|
|
|
|
(1,159
|
)
|
|
(9
|
)%
|
Severance and ad valorem taxes
|
|
18,629
|
|
|
|
50,430
|
|
|
|
(31,801
|
)
|
|
(63
|
)%
|
Exploration
|
|
15,827
|
|
|
|
5,346
|
|
|
|
10,481
|
|
|
196
|
%
|
Depreciation, depletion and amortization
|
|
244,921
|
|
|
|
228,789
|
|
|
|
16,132
|
|
|
7
|
%
|
Impairment of oil and gas properties
|
|
740,478
|
|
|
|
167,592
|
|
|
|
572,886
|
|
|
342
|
%
|
Abandonment and impairment of unproved properties
|
|
33,543
|
|
|
|
—
|
|
|
|
33,543
|
|
|
100
|
%
|
General and administrative expense
|
|
70,319
|
|
|
|
81,571
|
|
|
|
(11,252
|
)
|
|
(14
|
)%
|
Operating Expenses
|
$
|
1,200,123
|
|
|
$
|
606,139
|
|
|
$
|
593,984
|
|
|
98
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Selected Costs ($ per Boe)
(1)
:
|
|
|
|
|
|
|
|
|
|
|
||||
Lease operating expense
|
$
|
6.30
|
|
|
$
|
6.98
|
|
|
$
|
(0.68
|
)
|
|
(10
|
)%
|
Gas plant and midstream operating expense
|
|
1.10
|
|
|
|
1.46
|
|
|
|
(0.36
|
)
|
|
(25
|
)%
|
Severance and ad valorem taxes
|
|
1.81
|
|
|
|
5.88
|
|
|
|
(4.07
|
)
|
|
(69
|
)%
|
Exploration
|
|
1.53
|
|
|
|
0.62
|
|
|
|
0.91
|
|
|
147
|
%
|
Depreciation, depletion and amortization
|
|
23.73
|
|
|
|
26.66
|
|
|
|
(2.93
|
)
|
|
(11
|
)%
|
Impairment of oil and gas properties
|
|
71.76
|
|
|
|
19.53
|
|
|
|
52.23
|
|
|
267
|
%
|
Abandonment and impairment of unproved properties
|
|
3.25
|
|
|
|
—
|
|
|
|
3.25
|
|
|
100
|
%
|
General and administrative expense
|
|
6.81
|
|
|
|
9.51
|
|
|
|
(2.70
|
)
|
|
(28
|
)%
|
Operating Expenses
|
$
|
116.29
|
|
|
$
|
70.64
|
|
|
$
|
45.65
|
|
|
65
|
%
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating expenses, excluding impairments and abandonments
|
$
|
41.28
|
|
|
$
|
51.11
|
|
|
$
|
(9.83
|
)
|
|
(19
|
)%
|
(1)
|
Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
|
(2)
|
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or held for sale as of December 31, 2014.
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
|
|
||||||||
Net cash provided by operating activities
|
$
|
14,563
|
|
|
$
|
226,023
|
|
|
$
|
339,958
|
|
Net cash used in investing activities
|
(67,401
|
)
|
|
(452,573
|
)
|
|
(837,232
|
)
|
|||
Net cash provided by financing activities
|
112,062
|
|
|
245,307
|
|
|
319,276
|
|
|||
Cash and cash equivalents
|
80,565
|
|
|
21,341
|
|
|
2,584
|
|
|||
Acquisition of oil and gas properties
|
98
|
|
|
16,270
|
|
|
179,566
|
|
|||
Exploration and development of oil and gas properties
|
52,344
|
|
|
425,918
|
|
|
641,204
|
|
•
|
grant or assume liens;
|
•
|
incur or assume indebtedness;
|
•
|
grant negative pledges or agree to restrict dividends or distributions from subsidiaries;
|
•
|
sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;
|
•
|
make certain distributions;
|
•
|
make certain loans, advances and investments;
|
•
|
engage in transactions with affiliates;
|
•
|
enter into sale and leaseback, take-or-pay or hydrocarbon prepayment transactions; or
|
•
|
enter into certain swap agreements.
|
•
|
a current ratio (
i.e.
, the ratio of current assets to current liabilities, excluding unsettled derivatives and the current portion of long-term debt) of not less than 1.0 to 1.0 (current assets include, as of the date of calculation, the aggregate of all lenders’ unused commitment amounts);
|
•
|
a maximum senior secured debt (defined as borrowings under the revolving credit facility, balances drawn under letters of credit, and any outstanding second lien debt) to trailing twelve-month earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense and other non-cash charges (“EBITDAX”) covenant that must not exceed 2.50 to 1.00; and
|
•
|
a minimum interest coverage ratio calculated by dividing trailing twelve-month EBITDAX by trailing twelve-month interest expense that must exceed 2.50 to 1.00.
|
•
|
failure to pay any principal, interest, fees, expenses or other amounts when due;
|
•
|
the failure of any representation or warranty to be materially true and correct when made;
|
•
|
failure to observe any agreement, obligation or covenant in the credit agreement, subject to cure periods for certain failures;
|
•
|
a cross-default for the payment of any other indebtedness of at least $2 million;
|
•
|
bankruptcy or insolvency;
|
•
|
judgments against us or our subsidiaries, in excess of $2 million, that are not stayed;
|
•
|
certain ERISA events involving us or our subsidiaries; and
|
•
|
a change in control (as defined in the revolving credit facility), including the ownership by a “person” or “group” (as defined under the Securities and Exchange Act of 1934, as amended, but excluding certain permitted stockholders) directly or indirectly, of more than 35% of our common stock, other than certain of our current stockholders.
|
|
|
|
|
|
Less than
|
|
|
|
|
|
|
|
More than
|
|||||||
|
|
Total
|
|
1 Year
|
|
1 - 3 Years
|
|
3 - 5 Years
|
|
5 Years
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
Contractual Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Senior Notes
|
|
$
|
800,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
500,000
|
|
|
$
|
300,000
|
|
Interest on Senior Notes
(1)
|
|
|
249,829
|
|
|
|
51,000
|
|
|
|
102,000
|
|
|
|
78,094
|
|
|
|
18,735
|
|
Revolving credit facility
(2)
|
|
|
191,667
|
|
|
|
191,667
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Delivery commitments
(3)
|
|
|
437,069
|
|
|
|
89,611
|
|
|
|
179,222
|
|
|
|
99,250
|
|
|
|
68,986
|
|
Operating leases
(3)
|
|
|
10,725
|
|
|
|
2,767
|
|
|
|
5,659
|
|
|
|
2,299
|
|
|
|
—
|
|
Asset retirement obligations
(4)
|
|
|
136,971
|
|
|
|
2,673
|
|
|
|
3,724
|
|
|
|
7,909
|
|
|
|
122,665
|
|
Total
|
|
$
|
1,826,261
|
|
|
$
|
337,718
|
|
|
$
|
290,605
|
|
|
$
|
687,552
|
|
|
$
|
510,386
|
|
(1)
|
Amounts represent the interest to be paid on the Company's Senior Notes up through their contractual maturities of 2021 and 2023.
|
(2)
|
The revolving credit facility matures in September 2017.
|
(3)
|
The Company has two purchase and transportation agreements, one of which has been terminated and the other's terms have been amended subsequent to year end and subject to confirmation. Please refer to
Note 8 - Commitments and Contingencies
to our consolidated financial statements for additional discussion on these agreements and for a description of our operating leases.
|
(4)
|
Amounts represent our estimated future retirement obligations on an undiscounted basis. The discounted obligations are recorded as liabilities on our accompanying balance sheets as of December 31, 2016. Because these costs typically extend many years into the future, management prepares estimates and makes judgments that are subject to future revisions based upon numerous factors. Please see
Note 11 - Asset Retirement Obligation
, for additional discussion.
|
•
|
the remaining amount of unexpired term under our leases;
|
•
|
our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;
|
•
|
our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
|
•
|
our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
|
•
|
our evaluation of the continuing successful results from the application of completion technology in the Wattenberg Field by us or by other operators in areas adjacent to or near our unproved properties.
|
•
|
In August 2015, the FASB issued
Update No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date
. This update deferred the effective date of Update 2014-09 by one year.
|
•
|
In March 2016, the FASB issued
Update No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
. This update amends the principal versus agent guidance in Update No. 2014-09.
|
•
|
In April 2016, the FASB issued
Update No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing
. This update amends the identification of performance obligations and accounting for licenses in Update 2014-09.
|
•
|
In May 2016, the FASB issued
Update No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients
. This update amends certain issues in Update 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.
|
•
|
In May 2016, the FASB issued Update
No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.
This update amends certain issues in Update 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.
|
•
|
In December 2016, the FASB issued
Update No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers
. This update is meant to improve and clarify or to correct unintended application of narrow aspects of the guidance in Update 2014-09.
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands, except share data)
|
||||||
ASSETS
|
|
|
|
|
|
||
Current assets:
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
80,565
|
|
|
$
|
21,341
|
|
Accounts receivable:
|
|
|
|
|
|
||
Oil and gas sales
|
14,479
|
|
|
25,322
|
|
||
Joint interest and other
|
6,784
|
|
|
31,224
|
|
||
Prepaid expenses and other
|
5,915
|
|
|
4,078
|
|
||
Inventory of oilfield equipment
|
4,685
|
|
|
8,543
|
|
||
Derivative asset
|
—
|
|
|
29,566
|
|
||
Total current assets
|
112,428
|
|
|
120,074
|
|
||
Property and equipment
(
successful efforts method), at cost:
|
|
|
|
|
|
||
Proved properties
|
2,525,587
|
|
|
1,618,970
|
|
||
Less: accumulated depreciation, depletion and amortization
|
(1,694,483
|
)
|
|
(943,081
|
)
|
||
Total proved properties, net
|
831,104
|
|
|
675,889
|
|
||
Unproved properties
|
163,369
|
|
|
185,530
|
|
||
Wells in progress
|
18,250
|
|
|
51,196
|
|
||
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 (note 3)
|
—
|
|
|
214,922
|
|
||
Other property and equipment, net of accumulated depreciation of $11,206 in 2016 and $9,407 in 2015
|
6,245
|
|
|
9,729
|
|
||
Total property and equipment, net
|
1,018,968
|
|
|
1,137,266
|
|
||
Other noncurrent assets
|
3,082
|
|
|
2,301
|
|
||
Total assets
|
$
|
1,134,478
|
|
|
$
|
1,259,641
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
||
Current liabilities:
|
|
|
|
|
|
||
Accounts payable and accrued expenses (note 6)
|
$
|
61,328
|
|
|
$
|
96,360
|
|
Oil and gas sales distribution payable
|
23,773
|
|
|
27,613
|
|
||
Contractual obligation for land acquisition
|
—
|
|
|
12,000
|
|
||
Revolving credit facility - current portion (note 7)
|
191,667
|
|
|
—
|
|
||
Senior Notes - current portion (note 7)
|
793,698
|
|
|
—
|
|
||
Total current liabilities
|
1,070,466
|
|
|
135,973
|
|
||
Long-term liabilities:
|
|
|
|
|
|
||
Long-term debt (note 7)
|
—
|
|
|
871,666
|
|
||
Ad valorem taxes
|
14,118
|
|
|
17,069
|
|
||
Asset retirement obligations for oil and gas properties
|
30,833
|
|
|
14,935
|
|
||
Asset retirement obligations for oil and gas properties assets held for sale
|
—
|
|
|
10,591
|
|
||
Total liabilities
|
1,115,417
|
|
|
1,050,234
|
|
||
Commitments and contingencies (note 8)
|
|
|
|
|
|
||
Stockholders’ equity:
|
|
|
|
|
|
||
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding
|
—
|
|
|
—
|
|
||
Common stock, $.001 par value, 225,000,000 shares authorized, 49,660,683 and 49,754,408 issued and outstanding in 2016 and 2015, respectively
|
49
|
|
|
49
|
|
||
Additional paid-in capital
|
814,990
|
|
|
806,386
|
|
||
Retained deficit
|
(795,978
|
)
|
|
(597,028
|
)
|
||
Total stockholders’ equity
|
19,061
|
|
|
209,407
|
|
||
Total liabilities and stockholders’ equity
|
$
|
1,134,478
|
|
|
$
|
1,259,641
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands, except per share data)
|
|||||||||||
Operating net revenues:
|
|
|
|
|
|
|
|
|
||||
Oil and gas sales
|
|
$
|
195,295
|
|
|
$
|
292,679
|
|
|
$
|
558,633
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
||||
Lease operating expense
|
|
43,671
|
|
|
65,038
|
|
|
59,884
|
|
|||
Gas plant and midstream operating expense
|
|
12,826
|
|
|
11,368
|
|
|
12,527
|
|
|||
Severance and ad valorem taxes
|
|
15,304
|
|
|
18,629
|
|
|
50,430
|
|
|||
Exploration
|
|
946
|
|
|
15,827
|
|
|
5,346
|
|
|||
Depreciation, depletion and amortization
|
|
111,215
|
|
|
244,921
|
|
|
228,789
|
|
|||
Impairment of oil and gas properties
|
|
10,000
|
|
|
740,478
|
|
|
167,592
|
|
|||
Abandonment and impairment of unproved properties
|
|
24,692
|
|
|
33,543
|
|
|
—
|
|
|||
Unused commitments
|
|
7,686
|
|
|
—
|
|
|
—
|
|
|||
Contract settlement expense (note 8)
|
|
21,000
|
|
|
—
|
|
|
—
|
|
|||
General and administrative expense (including $8,892, $14,552, and $20,716, respectively, of stock-based compensation)
|
|
77,065
|
|
|
70,319
|
|
|
81,571
|
|
|||
Total operating expenses
|
|
324,405
|
|
|
1,200,123
|
|
|
606,139
|
|
|||
Loss from operations
|
|
(129,110
|
)
|
|
(907,444
|
)
|
|
(47,506
|
)
|
|||
Other income (expense):
|
|
|
|
|
|
|
|
|
||||
Derivative gain (loss)
|
|
(11,234
|
)
|
|
56,558
|
|
|
121,615
|
|
|||
Interest expense
|
|
(62,058
|
)
|
|
(57,052
|
)
|
|
(46,447
|
)
|
|||
Gain on termination fee (note 3)
|
|
6,000
|
|
|
—
|
|
|
—
|
|
|||
Other income (loss)
|
|
(2,548
|
)
|
|
(2,503
|
)
|
|
345
|
|
|||
Total other income (expense)
|
|
(69,840
|
)
|
|
(2,997
|
)
|
|
75,513
|
|
|||
Income (loss) from continuing operations before taxes
|
|
(198,950
|
)
|
|
(910,441
|
)
|
|
28,007
|
|
|||
Current income tax expense (note 10)
|
|
—
|
|
|
(773
|
)
|
|
(149
|
)
|
|||
Deferred income tax benefit (expense) (note 10)
|
|
—
|
|
|
165,667
|
|
|
(10,876
|
)
|
|||
Income (loss) from continuing operations
|
|
$
|
(198,950
|
)
|
|
$
|
(745,547
|
)
|
|
$
|
16,982
|
|
Discontinued operations:
|
|
|
|
|
|
|
|
|
||||
Loss from operations associated with oil and gas properties
|
|
—
|
|
|
—
|
|
|
(85
|
)
|
|||
Gain on sale of oil and gas properties
|
|
—
|
|
|
—
|
|
|
5,496
|
|
|||
Income tax expense
|
|
—
|
|
|
—
|
|
|
(2,110
|
)
|
|||
Gain from discontinued operations
|
|
—
|
|
|
—
|
|
|
3,301
|
|
|||
Net income (loss)
|
|
$
|
(198,950
|
)
|
|
$
|
(745,547
|
)
|
|
$
|
20,283
|
|
Comprehensive income (loss)
|
|
$
|
(198,950
|
)
|
|
$
|
(745,547
|
)
|
|
$
|
20,283
|
|
Basic income (loss) per share:
|
|
|
|
|
|
|
|
|
||||
Income (loss) from continuing operations
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.42
|
|
Income from discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.08
|
|
Net income (loss) per common share
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.50
|
|
Diluted income (loss) per share:
|
|
|
|
|
|
|
|
|
||||
Income (loss) from continuing operations
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.41
|
|
Income from discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.08
|
|
Net income (loss) per common share
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.49
|
|
Basic weighted-average common shares outstanding
|
|
49,268
|
|
|
47,874
|
|
|
40,139
|
|
|||
Diluted weighted-average common shares outstanding
|
|
49,268
|
|
|
47,874
|
|
|
40,290
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
||||||
|
|
Common Stock
|
|
Paid-In
|
|
Retained
|
|
|
|
||||||||||
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Earnings
|
|
Total
|
|||||||||
|
|
(in thousands, except share data)
|
|||||||||||||||||
Balances, January 1, 2014
|
|
40,285,919
|
|
|
$
|
40
|
|
|
$
|
527,752
|
|
|
$
|
128,236
|
|
|
$
|
656,028
|
|
Restricted common stock issued, net of excess income tax benefit
|
|
309,458
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Restricted common stock forfeited
|
|
(31,597
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Restricted stock used for tax withholdings
|
|
(130,002
|
)
|
|
|
—
|
|
|
|
(6,007
|
)
|
|
|
—
|
|
|
|
(6,007
|
)
|
Stock-based compensation
|
|
—
|
|
|
|
—
|
|
|
|
20,716
|
|
|
|
—
|
|
|
|
20,716
|
|
Stock Issued upon acquisition of oil and gas properties
|
|
853,492
|
|
|
|
1
|
|
|
|
49,050
|
|
|
|
—
|
|
|
|
49,051
|
|
Net income
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
20,283
|
|
|
|
20,283
|
|
Balances, December 31, 2014
|
|
41,287,270
|
|
|
$
|
41
|
|
|
$
|
591,511
|
|
|
$
|
148,519
|
|
|
$
|
740,071
|
|
Restricted common stock issued,
|
|
601,282
|
|
|
|
1
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1
|
|
Restricted common stock forfeited
|
|
(123,574
|
)
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(1
|
)
|
Restricted stock used for tax withholdings
|
|
(108,070
|
)
|
|
|
—
|
|
|
|
(2,683
|
)
|
|
|
—
|
|
|
|
(2,683
|
)
|
Issuance of common stock
|
|
47,500
|
|
|
|
—
|
|
|
|
326
|
|
|
|
—
|
|
|
|
326
|
|
Sale of common stock
|
|
8,050,000
|
|
|
|
8
|
|
|
|
202,680
|
|
|
|
—
|
|
|
|
202,688
|
|
Stock-based compensation
|
|
—
|
|
|
|
—
|
|
|
|
14,552
|
|
|
|
—
|
|
|
|
14,552
|
|
Net loss
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(745,547
|
)
|
|
|
(745,547
|
)
|
Balances, December 31, 2015
|
|
49,754,408
|
|
|
$
|
49
|
|
|
$
|
806,386
|
|
|
$
|
(597,028
|
)
|
|
$
|
209,407
|
|
Restricted common stock issued
|
|
154,656
|
|
|
|
2
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
Restricted common stock forfeited
|
|
(120,477
|
)
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(1
|
)
|
Restricted stock used for tax withholdings
|
|
(127,904
|
)
|
|
|
(1
|
)
|
|
|
(288
|
)
|
|
|
—
|
|
|
|
(289
|
)
|
Stock-based compensation
|
|
—
|
|
|
|
—
|
|
|
|
8,892
|
|
|
|
—
|
|
|
|
8,892
|
|
Net loss
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(198,950
|
)
|
|
|
(198,950
|
)
|
Balances, December 31, 2016
|
|
49,660,683
|
|
|
$
|
49
|
|
|
$
|
814,990
|
|
|
$
|
(795,978
|
)
|
|
$
|
19,061
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|||
Net income (loss)
|
$
|
(198,950
|
)
|
|
$
|
(745,547
|
)
|
|
$
|
20,283
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization
|
111,215
|
|
|
244,921
|
|
|
228,856
|
|
|||
Deferred income tax (benefit) expense
|
—
|
|
|
(165,667
|
)
|
|
12,986
|
|
|||
Impairment of oil and gas properties
|
10,000
|
|
|
740,478
|
|
|
167,592
|
|
|||
Abandonment and impairment of unproved properties
|
24,692
|
|
|
33,543
|
|
|
—
|
|
|||
Dry hole expense
|
872
|
|
|
5,630
|
|
|
—
|
|
|||
Stock-based compensation
|
8,892
|
|
|
14,552
|
|
|
20,716
|
|
|||
Amortization of deferred financing costs and debt premium
|
3,180
|
|
|
2,280
|
|
|
1,588
|
|
|||
Accretion of contractual obligation for land acquisition
|
—
|
|
|
814
|
|
|
1,153
|
|
|||
Derivative (gain) loss
|
11,234
|
|
|
(56,558
|
)
|
|
(121,615
|
)
|
|||
Derivative cash settlements
|
18,333
|
|
|
130,996
|
|
|
12,238
|
|
|||
Gain on sale of oil and gas properties
|
—
|
|
|
—
|
|
|
(5,322
|
)
|
|||
Inventory adjustments
|
4,390
|
|
|
—
|
|
|
—
|
|
|||
Other
|
(323
|
)
|
|
1,429
|
|
|
(12
|
)
|
|||
Changes in current assets and liabilities:
|
|
|
|
|
|
|
|
||||
Accounts receivable
|
35,282
|
|
|
35,230
|
|
|
(21,376
|
)
|
|||
Prepaid expenses and other assets
|
(1,838
|
)
|
|
8,444
|
|
|
(10,884
|
)
|
|||
Accounts payable and accrued liabilities
|
(11,616
|
)
|
|
(23,655
|
)
|
|
35,392
|
|
|||
Settlement of asset retirement obligations
|
(800
|
)
|
|
(867
|
)
|
|
(1,637
|
)
|
|||
Net cash provided by operating activities
|
14,563
|
|
|
226,023
|
|
|
339,958
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|||
Acquisition of oil and gas properties
|
(98
|
)
|
|
(16,270
|
)
|
|
(179,566
|
)
|
|||
Deposits for acquisitions
|
—
|
|
|
1,549
|
|
|
(1,549
|
)
|
|||
Proceeds from sale of oil and gas properties
|
—
|
|
|
—
|
|
|
6,700
|
|
|||
Payments of contractual obligation
|
(12,000
|
)
|
|
(12,000
|
)
|
|
(12,000
|
)
|
|||
Exploration and development of oil and gas properties
|
(52,344
|
)
|
|
(425,918
|
)
|
|
(641,204
|
)
|
|||
Natural gas plant capital expenditures
|
—
|
|
|
(112
|
)
|
|
(282
|
)
|
|||
(Increase) decrease in restricted cash
|
(2,613
|
)
|
|
2,987
|
|
|
(3,062
|
)
|
|||
Additions to property and equipment - non oil and gas
|
(346
|
)
|
|
(2,809
|
)
|
|
(6,269
|
)
|
|||
Net cash used in investing activities
|
(67,401
|
)
|
|
(452,573
|
)
|
|
(837,232
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|||
Proceeds from credit facility
|
209,000
|
|
|
137,000
|
|
|
263,000
|
|
|||
Payments to credit facility
|
(96,333
|
)
|
|
(91,000
|
)
|
|
(230,000
|
)
|
|||
Proceeds from sale of common stock
|
—
|
|
|
209,308
|
|
|
—
|
|
|||
Offering costs related to sale of common stock
|
—
|
|
|
(6,620
|
)
|
|
—
|
|
|||
Proceeds from sale of Senior Notes
|
—
|
|
|
—
|
|
|
300,000
|
|
|||
Offering costs related to sale of Senior Notes
|
—
|
|
|
(99
|
)
|
|
(7,070
|
)
|
|||
Payment of employee tax withholdings in exchange for the return of common stock
|
(289
|
)
|
|
(2,683
|
)
|
|
(6,007
|
)
|
|||
Deferred financing costs
|
(316
|
)
|
|
(599
|
)
|
|
(647
|
)
|
|||
Net cash provided by financing activities
|
112,062
|
|
|
245,307
|
|
|
319,276
|
|
|||
Net change in cash and cash equivalents
|
59,224
|
|
|
18,757
|
|
|
(177,998
|
)
|
|||
Cash and cash equivalents:
|
|
|
|
|
|
|
|
|
|||
Beginning of period
|
21,341
|
|
|
2,584
|
|
|
180,582
|
|
|||
End of period
|
$
|
80,565
|
|
|
$
|
21,341
|
|
|
$
|
2,584
|
|
Supplemental cash flow disclosure:
|
|
|
|
|
|
|
|
|
|||
Cash paid for interest
|
$
|
58,900
|
|
|
$
|
54,566
|
|
|
$
|
36,325
|
|
Stock issued for the acquisition of oil and gas properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
49,050
|
|
Stock issued for litigation settlement
|
$
|
—
|
|
|
$
|
326
|
|
|
$
|
—
|
|
Cash paid for income taxes
|
$
|
—
|
|
|
$
|
820
|
|
|
$
|
1,400
|
|
Contractual obligation for land acquisition
|
$
|
—
|
|
|
$
|
12,000
|
|
|
$
|
22,033
|
|
Changes in working capital related to exploration, development and acquisition of oil and gas properties
|
$
|
(30,044
|
)
|
|
$
|
(50,385
|
)
|
|
$
|
1,873
|
|
•
|
the Company’s ability to comply with financial covenants and ratios in its revolving credit facility and indentures has been affected by continued low commodity prices. Among other things, the Company is required under its revolving credit facility to maintain a minimum interest coverage ratio that must exceed
2.50
to 1.00 and a maximum debt ratio that must not exceed
2.50
to 1.00. Absent a waiver, amendment or forbearance agreement, failure to meet these covenants and ratios would result in an Event of Default (as defined in the revolving credit agreement) and, to the extent the applicable lenders so elect, an acceleration of the Company’s existing indebtedness. As of December 31, 2016, and through the filing date of this report, the Company was no longer in compliance with its minimum interest coverage and maximum debt ratio requirements. The Company entered into a Restructuring Support Agreement (“RSA”) on December 23, 2016 and filed for bankruptcy under Chapter 11 of the Bankruptcy Code on January 4, 2017. The applicable lenders did not elect to accelerate the Company's debt prior to filing for bankruptcy. The Company was granted an automatic stay from collection efforts upon filing for bankruptcy. Please refer to
Note 19 - Subsequent Events
for more on our bankruptcy proceedings;
|
•
|
because the revolving credit facility borrowing base was reduced in May 2016 to
$200.0 million
, the Company was overdrawn by
$88.0 million
and made
six
mandatory monthly repayments of approximately
$14.7 million
. The borrowing base was further reduced on October 31, 2016 to
$150.0 million
, causing the Company to be overdrawn by
|
•
|
the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities is impacted by the Company’s liquidity. As of December 31, 2016, the Company faces a
$41.7 million
borrowing base deficiency under its revolving credit facility and has
$80.6 million
in cash and cash equivalents;
|
•
|
the Company has
two
purchase and transportation agreements to deliver fixed determinable quantities of crude oil. The first agreement with Silo Energy, LLC (“Silo”) went into effect during the second quarter of 2015 for
12,580
barrels per day over an initial
five
-year term. The Company has incurred
$3.4 million
in minimum volume commitment deficiency payments related to this agreement as of December 31, 2016. Based on current production estimates, assuming no future drilling and completion activity, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of
$44.8 million
for 2017 through April 2020, when the agreement expires. Subject to bankruptcy court confirmation, the Company terminated its purchase agreement with Silo on February 1, 2017 and entered into a settlement agreement pursuant to which Silo will receive value of approximately
$21.0 million
. The second purchase agreement with NGL Crude Logistics, LLC (“NGL”) became effective on November 1, 2016 for
15,000
barrels per day over an initial
seven
-year term. Based on current production estimates at December 31, 2016, assuming no future drilling and completion activity, the anticipated shortfall in delivering the minimum volume commitments could result in potential deficiency payments of
$165.2 million
for 2017 through October 2023, when the second agreement expires. The NGL purchase agreement is contemplated to be amended as part of the RSA. Please refer to
Note 8 - Commitments and Contingencies
for additional discussion; and
|
•
|
if the revolving credit facility is accelerated, then an Event of Default (as defined in the underlying indentures) under the Company's
6.75%
Senior Notes due 2021 (“
6.75%
Senior Notes”) and
5.75%
Senior Notes due 2023 (“
5.75%
Senior Notes”, and together with the
6.75%
Senior Notes referred to as the “Senior Notes”) would occur. If an Event of Default occurs, the trustee or the holders of at least
25%
in aggregate principal amount of the then outstanding notes, may declare the entire principal under the Senior Notes to be due and payable immediately. The revolving credit facility and Senior Notes have cross default clauses. Filing for protection under Chapter 11 of the Bankruptcy Code is an event of default under our revolving credit facility and Senior Notes. Upon filing for bankruptcy under Chapter 11, the Company was granted a stay from collection efforts. As of December 31, 2016, the revolving credit facility and Senior Notes had not been accelerated.
|
•
|
the remaining amount of unexpired term under leases;
|
•
|
its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;
|
•
|
its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
|
•
|
its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases;
|
•
|
its evaluation of the continuing successful results from the application of completion technology by the Company or by other operators in areas adjacent to or near its unproved properties;
|
•
|
its evaluation of the current fair market value of acreage; and
|
•
|
strategic shifts in development areas.
|
•
|
In August 2015, the FASB issued
Update No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date
. This update deferred the effective date of Update 2014-09 by one year.
|
•
|
In March 2016, the FASB issued
Update No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)
. This update amends the principal versus agent guidance in Update No. 2014-09.
|
•
|
In April 2016, the FASB issued
Update No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing
. This update amends the identification of performance obligations and accounting for licenses in Update 2014-09.
|
•
|
In May 2016, the FASB issued
Update No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients
. This update amends certain issues in Update 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.
|
•
|
In May 2016, the FASB issued Update
No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.
This update amends certain issues in Update 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes.
|
•
|
In December 2016, the FASB issued
Update No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers
. This update is meant to improve and clarify or to correct unintended application of narrow aspects of the guidance in Update 2014-09.
|
|
|
As of December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(in thousands)
|
||||||
Restricted cash
|
|
|
2,855
|
|
|
|
241
|
|
Deferred financing costs - revolving credit facility
|
|
|
227
|
|
|
|
2,060
|
|
Other noncurrent assets
|
|
$
|
3,082
|
|
|
$
|
2,301
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Drilling and completion costs
|
$
|
2,415
|
|
|
$
|
32,459
|
|
Accounts payable trade
|
1,140
|
|
|
1,085
|
|
||
Accrued general and administrative cost
|
17,539
|
|
|
10,643
|
|
||
Lease operating expense
|
2,895
|
|
|
4,731
|
|
||
Accrued reclamation cost
|
—
|
|
|
162
|
|
||
Accrued interest
|
14,209
|
|
|
14,231
|
|
||
Silo contract settlement accrual
|
7,228
|
|
|
—
|
|
||
Production and ad valorem taxes and other
|
15,902
|
|
|
33,049
|
|
||
Total accounts payable and accrued expenses
|
$
|
61,328
|
|
|
$
|
96,360
|
|
|
As of December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in thousands)
|
||||||
Revolving credit facility
|
$
|
191,667
|
|
|
$
|
79,000
|
|
6.75% Senior Notes due 2021
|
500,000
|
|
|
500,000
|
|
||
Unamortized premium on 6.75% Senior Notes
|
5,165
|
|
|
6,392
|
|
||
5.75% Senior Notes due 2023
|
300,000
|
|
|
300,000
|
|
||
Less debt issuance costs - Senior Notes
|
(11,467
|
)
|
|
(13,726
|
)
|
||
Total debt, net
|
985,365
|
|
|
871,666
|
|
||
Less current portion
(1)
|
(985,365
|
)
|
|
—
|
|
||
Total long-term debt
|
$
|
—
|
|
|
$
|
871,666
|
|
|
|
Commitments
|
||
|
|
(in thousands)
|
||
2017
|
|
$
|
92,378
|
|
2018
|
|
|
92,420
|
|
2019
|
|
|
92,462
|
|
2020
|
|
|
55,543
|
|
2021
|
|
|
46,006
|
|
2022 and thereafter
|
|
|
68,985
|
|
Total
|
|
$
|
447,794
|
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
Restricted
Stock
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Restricted
Stock
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Restricted
Stock
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|||||||||
Non-vested at beginning of year
|
731,818
|
|
|
$
|
29.47
|
|
|
589,529
|
|
|
$
|
37.66
|
|
|
836,002
|
|
|
$
|
25.11
|
|
Granted
|
113,044
|
|
|
$
|
0.98
|
|
|
601,282
|
|
|
$
|
24.04
|
|
|
309,949
|
|
|
$
|
45.87
|
|
Vested
|
(355,498
|
)
|
|
$
|
31.68
|
|
|
(335,419
|
)
|
|
$
|
32.09
|
|
|
(524,818
|
)
|
|
$
|
25.95
|
|
Forfeited
|
(120,477
|
)
|
|
$
|
27.34
|
|
|
(123,574
|
)
|
|
$
|
34.86
|
|
|
(31,604
|
)
|
|
$
|
32.73
|
|
Non-vested at end of year
|
368,887
|
|
|
$
|
19.45
|
|
|
731,818
|
|
|
$
|
29.47
|
|
|
589,529
|
|
|
$
|
37.66
|
|
|
|
For the Years Ended
|
|||
|
|
2015
|
|
2014
|
|
Expected term of award
|
|
3
|
|
|
3
|
Risk-free interest rate
|
|
0.15% - 0.99%
|
|
|
0.12% - 0.9%
|
Expected volatility
|
|
65
|
%
|
|
40% - 45%
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
|
PSU
|
|
Weighted-Average
Grant-Date Fair Value |
|
PSU
|
|
Weighted-Average
Grant-Date Fair Value |
|
PSU
|
|
Weighted-Average
Grant-Date Fair Value |
|||||||||
Non-vested at beginning of year
(1)
|
114,833
|
|
|
$
|
35.27
|
|
|
94,173
|
|
|
$
|
37.55
|
|
|
40,191
|
|
|
$
|
32.05
|
|
Granted
(1)
|
—
|
|
|
$
|
—
|
|
|
144,363
|
|
|
$
|
33.44
|
|
|
82,312
|
|
|
$
|
41.94
|
|
Vested
(1)
|
(59,725
|
)
|
|
$
|
36.61
|
|
|
(107,053
|
)
|
|
$
|
34.84
|
|
|
(28,330
|
)
|
|
$
|
42.50
|
|
Forfeited
(1)
|
(33,570
|
)
|
|
$
|
35.55
|
|
|
(16,650
|
)
|
|
$
|
37.00
|
|
|
—
|
|
|
$
|
—
|
|
Non-vested at end of year
(1)
|
21,538
|
|
|
$
|
33.31
|
|
|
114,833
|
|
|
$
|
35.27
|
|
|
94,173
|
|
|
$
|
37.55
|
|
(1)
|
The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from
zero
to
two
, depending on the level of satisfaction of the performance condition.
|
|
For the Year Ended
|
|||||
|
December 31, 2016
|
|||||
|
LTIP Units
|
|
Weighted-
Average Grant-Date Fair Value |
|||
Non-vested at beginning of year
|
—
|
|
|
$
|
—
|
|
Granted
|
2,958,558
|
|
|
$
|
0.99
|
|
Vested
|
—
|
|
|
$
|
—
|
|
Forfeited
|
(515,156
|
)
|
|
$
|
0.98
|
|
Non-vested at end of year
|
2,443,402
|
|
|
$
|
0.99
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Current tax expense (benefit)
|
|
|
|
|
|
|
|
|
|
|||
Federal
|
|
$
|
—
|
|
|
$
|
(192
|
)
|
|
$
|
165
|
|
State
|
|
|
—
|
|
|
|
965
|
|
|
|
(16
|
)
|
Deferred tax expense (benefit)
|
|
|
—
|
|
|
|
(165,667
|
)
|
|
|
12,986
|
|
Total income tax expense (benefit)
|
|
$
|
—
|
|
|
$
|
(164,894
|
)
|
|
$
|
13,135
|
|
|
|
As of December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(in thousands)
|
||||||
Deferred tax liabilities:
|
|
|
|
|
|
|
||
Oil and gas properties
|
|
$
|
4,136
|
|
|
$
|
—
|
|
Derivative asset
|
|
|
—
|
|
|
|
11,328
|
|
Total deferred tax liabilities
|
|
|
4,136
|
|
|
|
11,328
|
|
Deferred tax assets:
|
|
|
|
|
|
|
||
Federal and state tax net operating loss carryforward
|
|
|
234,544
|
|
|
|
82,013
|
|
Oil and gas properties
|
|
|
—
|
|
|
|
93,712
|
|
Reclamation costs
|
|
|
11,841
|
|
|
|
9,907
|
|
Stock compensation
|
|
|
6,694
|
|
|
|
3,907
|
|
Accrued compensation
|
|
|
2,228
|
|
|
|
—
|
|
Settlement liabilities
|
|
|
2,761
|
|
|
|
—
|
|
AMT credit
|
|
|
403
|
|
|
|
402
|
|
State bonus depreciation addback
|
|
|
1,481
|
|
|
|
1,613
|
|
Other long-term liabilities
|
|
|
406
|
|
|
|
322
|
|
Total deferred tax assets
|
|
|
260,358
|
|
|
|
191,876
|
|
Less: Valuation allowance
|
|
|
256,222
|
|
|
|
180,548
|
|
Total deferred tax assets after valuation allowance
|
|
|
4,136
|
|
|
|
11,328
|
|
Total non-current net deferred tax liability
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Federal statutory tax expense (benefit)
|
|
$
|
(69,633
|
)
|
|
$
|
(318,654
|
)
|
|
$
|
11,696
|
|
Increase (decrease) in tax resulting from:
|
|
|
|
|
|
|
|
|
|
|||
State tax expense net of federal benefit
|
|
|
(6,358
|
)
|
|
|
(30,178
|
)
|
|
|
1,106
|
|
Rate change and other
|
|
|
317
|
|
|
|
3,390
|
|
|
|
333
|
|
Valuation allowance
|
|
|
75,674
|
|
|
|
180,548
|
|
|
|
—
|
|
Total income tax expense (benefit)
|
|
$
|
—
|
|
|
$
|
(164,894
|
)
|
|
$
|
13,135
|
|
|
|
For the Years Ended December 31,
|
|||||||
|
|
2016
|
|
2015
|
|
2014
|
|||
Expected federal tax rate
|
|
35.00
|
%
|
|
35.00
|
%
|
|
35.00
|
%
|
State income taxes
|
|
3.2
|
%
|
|
3.31
|
%
|
|
3.29
|
%
|
Change in tax rate
|
|
(0.16
|
)%
|
|
(0.37
|
)%
|
|
1.01
|
%
|
Valuation allowance
|
|
(38.04
|
)%
|
|
(19.83
|
)%
|
|
—
|
%
|
Effective tax rate
|
|
—
|
%
|
|
18.11
|
%
|
|
39.30
|
%
|
|
|
As of December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(in thousands)
|
||||||
Beginning of year
|
|
$
|
25,688
|
|
|
$
|
21,626
|
|
Additional liabilities incurred
|
|
|
90
|
|
|
|
560
|
|
Accretion expense
|
|
|
2,601
|
|
|
|
1,944
|
|
Liabilities settled
|
|
|
(691
|
)
|
|
|
(469
|
)
|
Revisions to estimate
|
|
|
3,145
|
|
|
|
2,027
|
|
End of year
|
|
$
|
30,833
|
|
|
$
|
25,688
|
|
|
As of December 31, 2016
|
||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Unproved properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
162,682
|
|
Asset retirement obligations
(3)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,145
|
|
|
As of December 31, 2015
|
||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||
|
(in thousands)
|
||||||||||
Derivative assets
(1)
|
$
|
—
|
|
|
$
|
29,566
|
|
|
$
|
—
|
|
Unproved properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
185,530
|
|
Proved properties
(2)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
811,913
|
|
Asset retirement obligations
(3)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,027
|
|
(1)
|
This represents a financial asset or liability that is measured at fair value on a recurring basis.
|
(2)
|
This represents non-financial assets that are measured at fair value on a nonrecurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on
|
(3)
|
This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the
Asset Retirement Obligation
section below for additional discussion.
|
|
As of December 31, 2015
|
||||
|
Balance Sheet Location
|
|
Fair Value
|
||
|
|
|
(in thousands)
|
||
Derivative Assets:
|
|
|
|
|
|
Commodity contracts
|
Current assets
|
|
$
|
29,566
|
|
Commodity contracts
|
Noncurrent assets
|
|
—
|
|
|
Derivative Liabilities:
|
|
|
|
|
|
Commodity contracts
|
Current liabilities
|
|
—
|
|
|
Commodity contracts
|
Long-term liabilities
|
|
—
|
|
|
Total derivative asset
|
|
|
$
|
29,566
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in thousands)
|
|||||||||||
Derivative cash settlement gain (loss):
|
|
|
|
|
|
|
|
|
||||
Oil contracts
(1)
|
|
$
|
18,333
|
|
|
$
|
128,258
|
|
|
$
|
11,523
|
|
Gas contracts
|
|
—
|
|
|
2,738
|
|
|
715
|
|
|||
Total derivative cash settlement gain (loss)
(2)
|
|
$
|
18,333
|
|
|
$
|
130,996
|
|
|
$
|
12,238
|
|
|
|
|
|
|
|
|
||||||
Change in fair value gain (loss)
|
|
$
|
(29,567
|
)
|
|
$
|
(74,438
|
)
|
|
$
|
109,377
|
|
|
|
|
|
|
|
|
||||||
Total derivative gain (loss)
(2)
|
|
$
|
(11,234
|
)
|
|
$
|
56,558
|
|
|
$
|
121,615
|
|
(1)
|
During the year ended December 31, 2015, the Company paid
$10.5 million
to convert its
three
-way collars, that settled during the
third
and
fourth
quarters of
2015
, to
two
-way collars.
|
(2)
|
Total derivative gain (loss) and the derivative cash settlement gain for the years ended
December 31, 2016
,
2015
and
2014
is reported in the derivative (gain) loss and derivative cash settlements line items on the accompanying statements of cash flows within the net cash provided by operating activities.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands, except per share amounts)
|
||||||||||
Income (loss) from continuing operations:
|
|
|
|
|
|
|
|
|
||||
Income (loss) from continuing operations
|
|
$
|
(198,950
|
)
|
|
$
|
(745,547
|
)
|
|
$
|
16,982
|
|
Less: undistributed income to unvested restricted stock
|
|
—
|
|
|
—
|
|
|
315
|
|
|||
Undistributed income (loss) to common shareholders
|
|
(198,950
|
)
|
|
(745,547
|
)
|
|
16,667
|
|
|||
Basic income (loss) per common share from continuing operations
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.42
|
|
Diluted income (loss) per common share from continuing operations
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.41
|
|
|
|
|
|
|
|
|
||||||
Income from discontinued operations:
|
|
|
|
|
|
|
|
|
||||
Income from discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,301
|
|
Less: undistributed income to unvested restricted stock
|
|
—
|
|
|
—
|
|
|
62
|
|
|||
Undistributed income to common shareholders
|
|
—
|
|
|
—
|
|
|
3,239
|
|
|||
Basic income per common share from discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.08
|
|
Diluted income per common share from discontinued operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.08
|
|
|
|
|
|
|
|
|
||||||
Net income (loss):
|
|
|
|
|
|
|
|
|
||||
Net income (loss)
|
|
$
|
(198,950
|
)
|
|
$
|
(745,547
|
)
|
|
$
|
20,283
|
|
Less: undistributed income to unvested restricted stock
|
|
—
|
|
|
—
|
|
|
377
|
|
|||
Undistributed income (loss) to common shareholders
|
|
(198,950
|
)
|
|
(745,547
|
)
|
|
19,906
|
|
|||
Basic net income (loss) per common share
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.50
|
|
Diluted net income (loss) per common share
|
|
$
|
(4.04
|
)
|
|
$
|
(15.57
|
)
|
|
$
|
0.49
|
|
|
|
|
|
|
|
|
||||||
Weighted-average shares outstanding - basic
|
|
49,268
|
|
|
47,874
|
|
|
40,139
|
|
|||
Add: dilutive effect of contingent PSUs
|
|
—
|
|
|
—
|
|
|
151
|
|
|||
Weighted-average shares outstanding - diluted
|
|
49,268
|
|
|
47,874
|
|
|
40,290
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Acquisition
(1)
|
|
$
|
97
|
|
|
$
|
16,270
|
|
|
$
|
228,616
|
|
Development
(2)(3)
|
|
|
31,209
|
|
|
|
393,187
|
|
|
|
659,633
|
|
Exploration
|
|
|
74
|
|
|
|
6,284
|
|
|
|
5,345
|
|
Total
(4)
|
|
$
|
31,380
|
|
|
$
|
415,741
|
|
|
$
|
893,594
|
|
(1)
|
Acquisition costs for unproved properties for the years ended
December 31, 2016
,
2015
and
2014
were
$97,000
,
$15.3 million
and
$202.7 million
, respectively. There were
no
acquisition costs for proved properties for the year ended
December 31, 2016
and
$1.0 million
and
$25.9 million
, for the years ended December 31, 2015 and
2014
, respectively.
|
(2)
|
Development costs include workover costs of
$6.0 million
,
$10.0 million
and
$9.8 million
charged to lease operating expense during the years ended
December 31, 2016
,
2015
and
2014
, respectively.
|
(3)
|
Includes amounts relating to asset retirement obligations of
$3.1 million
,
$2.4 million
and
$6.3 million
for the years ended
December 31, 2016
,
2015
and
2014
, respectively.
|
|
|
|
|
Natural
|
|
Natural
|
|||
|
|
Oil
|
|
Gas
|
|
Gas Liquids
|
|||
|
|
(MBbl)
(1)
|
|
(MMcf)
|
|
(MBbl)
(1)
|
|||
Balance-December 31, 2013
|
|
46.482
|
|
|
139.614
|
|
|
—
|
|
Extensions and discoveries
(2)
|
|
13.222
|
|
|
41.963
|
|
|
—
|
|
Production
|
|
(6.018
|
)
|
|
(14.114
|
)
|
|
—
|
|
Sales of minerals in place
|
|
(0.043
|
)
|
|
(0.073
|
)
|
|
—
|
|
Purchases of minerals in place
|
|
0.709
|
|
|
1.214
|
|
|
—
|
|
Revisions to previous estimates
(3)
|
|
3.76
|
|
|
19.947
|
|
|
—
|
|
Balance-December 31, 2014
|
|
58.112
|
|
|
188.551
|
|
|
—
|
|
Three stream conversion adjustment
|
|
(3.352
|
)
|
|
—
|
|
|
3.352
|
|
Extensions and discoveries
(2)
|
|
6.936
|
|
|
15.849
|
|
|
2.43
|
|
Production
|
|
(6.072
|
)
|
|
(14.11
|
)
|
|
(1.676
|
)
|
Purchases of minerals in place
|
|
0.719
|
|
|
3.521
|
|
|
0.234
|
|
Revisions to previous estimates
(3)
|
|
1.05
|
|
|
(49.584
|
)
|
|
15.578
|
|
Balance-December 31, 2015
|
|
57.393
|
|
|
144.227
|
|
|
19.918
|
|
Extensions, discoveries and infills
(2)
|
|
6.133
|
|
|
15.128
|
|
|
2.142
|
|
Production
|
|
(4.31
|
)
|
|
(11.907
|
)
|
|
(1.491
|
)
|
Sales of minerals in place
|
|
(0.1
|
)
|
|
(0.343
|
)
|
|
(0.035
|
)
|
Revisions to previous estimates
(3)
|
|
(9.02
|
)
|
|
(9.06
|
)
|
|
(2.987
|
)
|
Balance-December 31, 2016
|
|
50.096
|
|
|
138.045
|
|
|
17.547
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|||
December 31, 2014
|
|
30.542
|
|
|
94.494
|
|
|
—
|
|
December 31, 2015
|
|
28.892
|
|
|
77.48
|
|
|
10.359
|
|
December 31, 2016
|
|
26.313
|
|
|
85.972
|
|
|
9.951
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|||
December 31, 2014
|
|
27.57
|
|
|
94.057
|
|
|
—
|
|
December 31, 2015
|
|
28.501
|
|
|
66.747
|
|
|
9.559
|
|
December 31, 2016
|
|
23.783
|
|
|
52.073
|
|
|
7.596
|
|
(1)
|
Natural gas liquid reserves were classified with oil reserves through December 31, 2014. Natural gas liquids are separately accounted for effective as of January 1, 2015, resulting in three-stream presentation. Effective January 1, 2015 the Company revised the agreements with its natural gas processors in the Rocky Mountain region to sell and report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in the Company's reporting of estimated reserve volumes. Prior period estimated reserve volumes have not been reclassified to conform to the current presentation given the prospective nature of the agreements.
|
(2)
|
At
December 31, 2016
, horizontal development in the Wattenberg Field resulted in additions of
1,632
MBoe and infill down-spacing within the Wattenberg Field resulted in
9,164
MBoe to the additions, extensions and infills category.
|
(3)
|
As of December 31, 2016, the Company revised its proved reserves downward by
13,517
MBoe. The commodity prices at December 31, 2016 decreased to
$42.75
per Bbl WTI and
$2.48
per MMBtu HH from
$50.28
per Bbl WTI and
$2.59
per MMBtu HH at
December 31, 2015
. The negative effects of commodity price reductions on reserves were offset by lower cost estimates to drill and complete future development locations in the Wattenberg Field along with lower operating cost estimates across the Company's operations to reflect a positive reserves adjustment (net of price reductions) of
4,652
MBoe. Also, all future proved undeveloped locations in the Mid-Continent region were demoted to non-proved reserves resulting in a negative revision of
7,761
MBoe. In the Wattenberg Field, certain proved undeveloped locations totaling
8,611
MBoe were demoted due to them not being centric to current infrastructure. The Company also had negative other engineering revisions of
1,797
MBoe in 2016.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Future cash flows
|
|
$
|
2,424,415
|
|
|
$
|
3,122,574
|
|
|
$
|
5,780,745
|
|
Future production costs
|
|
|
(1,365,765
|
)
|
|
|
(1,706,607
|
)
|
|
|
(2,257,572
|
)
|
Future development costs
|
|
|
(468,804
|
)
|
|
|
(697,045
|
)
|
|
|
(952,041
|
)
|
Future income tax expense
|
|
|
—
|
|
|
|
—
|
|
|
|
(457,625
|
)
|
Future net cash flows
|
|
|
589,846
|
|
|
|
718,922
|
|
|
|
2,113,507
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(312,891
|
)
|
|
|
(391,106
|
)
|
|
|
(1,006,131
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
276,955
|
|
|
$
|
327,816
|
|
|
$
|
1,107,376
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
|
(in thousands)
|
||||||||||
Beginning of period
|
|
$
|
327,816
|
|
|
$
|
1,107,376
|
|
|
$
|
925,283
|
|
Sale of oil and gas produced, net of production costs
|
|
|
(123,494
|
)
|
|
|
(197,643
|
)
|
|
|
(435,792
|
)
|
Net changes in prices and production costs
|
|
|
(126,536
|
)
|
|
|
(1,117,624
|
)
|
|
|
(331,930
|
)
|
Extensions, discoveries and improved recoveries
|
|
|
22,800
|
|
|
|
76,429
|
|
|
|
492,144
|
|
Development costs incurred
|
|
|
19,701
|
|
|
|
84,180
|
|
|
|
116,958
|
|
Changes in estimated development cost
|
|
|
281,062
|
|
|
|
178,003
|
|
|
|
(15,131
|
)
|
Purchases of minerals in place
|
|
|
—
|
|
|
|
(971
|
)
|
|
|
30,919
|
|
Sales of minerals in place
|
|
|
16
|
|
|
|
—
|
|
|
|
(1,173
|
)
|
Revisions of previous quantity estimates
|
|
|
(182,938
|
)
|
|
|
(170,277
|
)
|
|
|
122,169
|
|
Net change in income taxes
|
|
|
—
|
|
|
|
233,086
|
|
|
|
68,856
|
|
Accretion of discount
|
|
|
32,782
|
|
|
|
134,046
|
|
|
|
122,722
|
|
Changes in production rates and other
|
|
|
25,746
|
|
|
|
1,211
|
|
|
|
12,351
|
|
End of period
|
|
$
|
276,955
|
|
|
$
|
327,816
|
|
|
$
|
1,107,376
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Oil (per Bbl)
|
|
$
|
38.42
|
|
|
$
|
44.00
|
|
|
$
|
84.28
|
|
Gas (per Mcf)
|
|
$
|
2.07
|
|
|
$
|
2.33
|
|
|
$
|
5.24
|
|
Natural gas liquids (per Bbl)
|
|
$
|
12.12
|
|
|
|
12.90
|
|
|
|
N/A
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
|
|
(in thousands, except per share data)
|
||||||||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil and gas sales
|
|
$
|
44,174
|
|
|
$
|
54,530
|
|
|
$
|
49,325
|
|
|
$
|
47,266
|
|
Operating profit (loss)
(1)
|
|
|
(2,446
|
)
|
|
|
5,054
|
|
|
|
5,162
|
|
|
|
4,509
|
|
Net loss
|
|
|
(47,237
|
)
|
|
|
(49,477
|
)
|
|
|
(34,902
|
)
|
|
|
(67,334
|
)
|
Basic net loss per common share
|
|
$
|
(0.96
|
)
|
|
$
|
(1.00
|
)
|
|
$
|
(0.71
|
)
|
|
$
|
(1.37
|
)
|
Diluted net loss per common share
|
|
$
|
(0.96
|
)
|
|
$
|
(1.00
|
)
|
|
$
|
(0.71
|
)
|
|
$
|
(1.37
|
)
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil and gas sales
|
|
$
|
73,076
|
|
|
$
|
90,422
|
|
|
$
|
72,149
|
|
|
$
|
57,032
|
|
Operating loss
(1)
|
|
|
(11,688
|
)
|
|
|
(4,546
|
)
|
|
|
(9,133
|
)
|
|
|
(21,910
|
)
|
Net loss
|
|
|
(18,421
|
)
|
|
|
(41,164
|
)
|
|
|
(112,299
|
)
|
|
|
(573,663
|
)
|
Basic net loss per common share
|
|
$
|
(0.41
|
)
|
|
$
|
(0.83
|
)
|
|
$
|
(2.25
|
)
|
|
$
|
(12.08
|
)
|
Diluted net loss per common share
|
|
$
|
(0.41
|
)
|
|
$
|
(0.83
|
)
|
|
$
|
(2.25
|
)
|
|
$
|
(12.08
|
)
|
(1)
|
Oil and gas sales less lease operating expense, gas plant and midstream operating expense, severance and ad valorem taxes, depreciation, and depletion and amortization.
|
•
|
The Senior Notes and existing common shares of Bonanza (“Existing Common Shares”) will be canceled, and Reorganized Bonanza will issue (i) new common shares (the “New Common Shares”), (ii)
three
(3) year warrants (the “Warrants”) entitling their holders upon exercise thereof, on a pro rata basis, to
7.5%
of the total outstanding New Common Shares at a per share price based upon a total equity value of
$1,450,000,000
of the Reorganized Bonanza, and (iii) rights (the “Subscription Rights”) to acquire the New Common Shares offered in connection with the Rights Offering (“Rights Offering Equity”), each of which will be distributed as set forth below;
|
•
|
Holders of allowed claims (“RBL Claims”) on account of debt arising under the revolving credit facility shall be entitled to receive, in full and final satisfaction of its allowed RBL Claim;
|
•
|
Holders of allowed general unsecured claims against Bonanza shall be entitled to receive their ratable share of: (a)
29.4%
of the New Common Shares, subject to dilution by the Rights Offering Equity, the Management Incentive Plan (as defined in the Plan) and the Warrants and (b)
37.8%
of the Subscription Rights;
|
•
|
Holders of allowed general unsecured claims against Bonanza Creek Operating, shall receive their ratable share of
17.6%
of the New Common Shares subject to dilution by the Rights Offering Equity, the Management Incentive Plan and the Warrants.
|
•
|
Holders of allowed general unsecured claims against Debtors other than Bonanza and Bonanza Creek Operating, shall receive their ratable share of: (a)
48.5%
of the New Common Shares, subject to dilution by the Rights Offering Equity, the Management Incentive Plan (as defined in the Plan) and the Warrants and (b)
62.2%
of the Subscription Rights;
|
•
|
Holders of Existing Common Shares shall neither receive any distributions nor retain any property on account thereof pursuant to the Plan. Notwithstanding the foregoing, on or as soon as reasonably practicable after the Effective Date, holders of Existing Common Shares shall receive, in exchange for the releases by such holders of the Released Parties (as defined in the Plan), their ratable share of (i)
4.5%
of the New Common Shares, subject to dilution by the Rights Offering Equity, the Management Incentive Plan and the Warrants and (ii) the Warrants (the “Settlement Consideration”); provided, however, that any holder of Existing Common Shares that opts not to grant the voluntary releases contained in section 11.8 of the Plan shall not be entitled to receive its ratable share of the Settlement Consideration;
|
•
|
Holders of allowed Administrative Expense Claims, Priority Tax Claims, Other Priority Claims, and Unsecured Trade Claims (each as defined in the Plan) shall be entitled to payment in full in cash or other treatment that will render such claim unimpaired under section 1124 of the Bankruptcy Code;
|
•
|
Holders of allowed Other Secured Claims (as defined in the Plan) shall be entitled to payment in full in cash; reinstatement of the legal, equitable and contractual rights of the holder of such claim; a distribution of the proceeds of the sale or disposition of the collateral securing such claim, in each case, solely to the extent of the value of the holder’s secured interest in such collateral; return of collateral securing such claim; or other treatment that will render such claim unimpaired under section 1124 of the Bankruptcy Code.
|
(a)
|
The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:
|
(1)
|
Financial Statements:
|
(2)
|
Financial Statement Schedules:
|
(3)
|
Exhibits:
|
|
|
|
|
BONANZA CREEK ENERGY, INC.
|
|
|
By:
|
/s/ Richard J. Carty
|
|
|
Richard J. Carty,
President and Chief Executive Officer
(principal executive officer)
|
Date:
|
March 15, 2017
|
By:
|
/s/ Richard J. Carty
|
|
|
|
Richard J. Carty,
President, Chief Executive Officer, and Director
(principal executive officer)
|
Date:
|
March 15, 2017
|
By:
|
/s/ Scott A. Fenoglio
|
|
|
|
Scott A. Fenoglio,
Senior Vice President, Finance & Planning (principal financial officer)
|
Date:
|
March 15, 2017
|
By:
|
/s/ Wade E. Jaques
|
|
|
|
Wade E. Jaques,
Vice President and Chief Accounting Officer
(principal accounting officer)
|
Date:
|
March 15, 2017
|
By:
|
/s/ James A. Watt
|
|
|
|
James A. Watt,
Chairman of the Board
|
Date:
|
March 15, 2017
|
By:
|
/s/ Kevin A. Neveu
|
|
|
|
Kevin A. Neveu,
Director
|
Date:
|
March 15, 2017
|
By:
|
/s/ Gregory P. Raih
|
|
|
|
Gregory P. Raih,
Director
|
Date:
|
March 15, 2017
|
By:
|
/s/ Jeff E. Wojahn
|
|
|
|
Jeff E. Wojahn,
Director
|
Exhibit
Number
|
Description
|
|
3.1
|
|
Second Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc., filed with the Secretary of State of the State of Delaware on December 16, 2011 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8‑K filed on December 22, 2011)
|
3.2
|
|
Third Amended and Restated Bylaws of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8‑K filed on August 1, 2013)
|
4.1
|
|
Form of Senior Debt Indenture (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S‑3 filed on January 15, 2013)
|
4.2
|
|
Form of Subordinated Debt Indenture (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S‑3 filed on January 15, 2013)
|
4.3
|
|
Registration Rights Agreement, dated April 9, 2013, among Bonanza Creek Energy, Inc., the guarantors named therein and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.2 of the Current Report on Form 8‑K filed on April 11, 2013)
|
4.4
|
|
Indenture, dated as of April 9, 2013, among Bonanza Creek Energy, Inc., the guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8‑K filed on April 11, 2013)
|
4.5
|
|
Indenture, dated July 18, 2014, among Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 18, 2014)
|
4.6
|
|
First Supplemental Indenture, dated July 18, 2014, among Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 18, 2014)
|
4.7
|
|
First Supplemental Indenture, dated January 27, 2015, among Rocky Mountain Infrastructure, LLC, Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Annual Report on Form 10-K filed on February 27, 2015).
|
4.8
|
|
Second Supplemental Indenture, dated January 27, 2015, among Rocky Mountain Infrastructure, LLC, Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.8 to the Annual Report on Form 10-K filed on February 27, 2015).
|
10.1
|
|
Credit Agreement, dated as of March 29, 2011, among Bonanza Creek Energy, Inc., BNP Paribas, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S‑1 filed on June 7, 2011)
|
10.2
|
|
Amendment No. 1, dated as of April 29, 2011, to the Credit Agreement, among Bonanza Creek Energy, Inc., BNP Paribas, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S‑1 filed on June 7, 2011)
|
10.3
|
|
Amendment No. 2 & Agreement, dated as of September 15, 2011, to the Credit Agreement, among Bonanza Creek Energy, Inc., BNP Paribas, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.14 to the Registration Statement on Form S‑1/A filed on November 4, 2011)
|
10.4
|
|
Resignation, Consent and Appointment Agreement and Amendment Agreement, dated of April 6, 2012, by and among BNP Paribas, in its capacity as Administrative Agent and Issuing Lender, and the other parties thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10‑Q filed on May 11, 2012)
|
10.5
|
|
Amendment No. 3 & Agreement, dated as of May 8, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10‑Q filed on May 11, 2012)
|
10.6
|
|
Amendment No. 4, dated as of July 31, 2012 to the Credit Agreement among Bonanza Creek Energy, Inc., Key Bank National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10‑Q filed on August 13, 2012)
|
10.7
|
|
Amendment No. 5, dated as of October 30, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10‑Q filed on November 9, 2012)
|
10.8
|
|
Amendment No. 6, dated as of March 29, 2013, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10‑Q filed on May 10, 2013)
|
10.9
|
|
Amendment No. 7, dated as of May 16, 2013 to the Credit Agreement among Bonanza Creek Energy, Inc., Key Bank National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10‑Q filed on August 9, 2013)
|
10.10
|
|
Amendment No. 8, dated as of November 6, 2013, to the Credit Agreement, among Bonanza Creek Energy, Inc., the Guarantors, KeyBank National Association, as Administrative Agent and as Issuing Lender, and the lenders party thereto (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8‑K filed on November 8, 2013)
|
10.11
|
|
Amendment No. 9 and Agreement, dated as of May 14, 2014, to the Credit Agreement, among Bonanza Creek Energy, Inc., the Guarantors, KeyBank National Association, as Administrative Agent and as Issuing Lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on May 20, 2014)
|
10.12
|
|
Amendment No. 10 and Agreement, dated as of September 30, 2014, to the Credit Agreement, among Bonanza Creek Energy, Inc., the Guarantors, KeyBank National Association, as Administrative Agent and as Issuing Lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on October 3, 2014)
|
10.13
|
|
Amendment No. 11 and Agreement, dated as of May 13, 2015, to the Credit Agreement, among Bonanza Creek Energy, Inc., the Guarantors, KeyBank National Association, as Administrative Agent and as Issuing Lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on May 15, 2015)
|
10.14
|
|
Letter Agreement and Amendment No. 12, dated as of October 19, 2015, to the Credit Agreement, among Bonanza Creek Energy, Inc., the Guarantors, KeyBank National Association, as Administrative Agent and as Issuing Lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on October 20, 2015)
|
10.15
|
|
Registration Rights Agreement, among Bonanza Creek Energy, Inc., Project Black Bear LP, Her Majesty the Queen in Right of Alberta, in her own capacity and as a trustee/nominee for certain designated entities and certain other stockholders of the Registrant (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S‑1/A filed on July 25, 2011)
|
10.16*
|
|
Form of Indemnity Agreement between Bonanza Creek Energy, Inc. and each of its directors and executive officers (incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S‑1/A filed on July 25, 2011)
|
10.17*
|
|
Bonanza Creek Energy, Inc. Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 5, 2015)
|
10.18*
|
|
Form of Restricted Stock Agreement (Employee) under the Bonanza Creek Energy, Inc. Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10‑Q filed on July 28. 2015)
|
10.19*
|
|
Form of Restricted Stock Agreement (Director) under the Bonanza Creek Energy, Inc. Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10‑Q filed on July 28, 2015)
|
10.20*
|
|
Form of Performance Share Agreement for 2013 grants (incorporated by reference to Exhibit 10.3 of the Current Report on Form 8‑K filed on March 29, 2013)
|
10.21*
|
|
Form of Performance Share Agreement for 2014 grants (incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q filed on May 9, 2014)
|
10.22*
|
|
Form of Performance Stock Unit Agreement for 2015 grants (incorporated by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q filed on May 8, 2015).
|
10.23*
|
|
Employment Letter Agreement effective March 21, 2014 between Bonanza Creek Energy, Inc. and Wade E. Jaques (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on March 24, 2014)
|
10.24*
|
|
Employment Letter Agreement dated November 11, 2014, between Bonanza Creek Energy, Inc. and Richard J. Carty (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8‑K filed on November 14, 2014)
|
10.25*
|
|
Performance Share Agreement dated November 11, 2014, between Bonanza Creek Energy, Inc. and Richard J. Carty (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on November 14, 2014)
|
10.26*
|
|
Form of Employment Letter Agreement (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8‑K filed on March 29, 2013)
|
10.27*
|
|
Bonanza Creek Energy, Inc. Amended and Restated Executive Change in Control and Severance Plan (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10‑Q filed on July 28, 2015)
|
10.28
|
|
Membership Interest Purchase Agreement dated November 5, 2015 by and among Bonanza Creek Energy Operating Company, LLC and Meritage Midstream Services IV, LLC (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on November 10, 2015).
|
10.29
|
|
Purchase and Sale Agreement by and between DJ Resources, LLC, Bonanza Creek Energy Operating Company, LLC and Bonanza Creek Energy, Inc. dated May 21, 2014 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on May 23, 2014).
|
10.30
|
|
Separation Agreement dated March 23, 2016, between Bonanza Creek Energy, Inc. and William Cassidy (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10‑Q filed on May 5, 2016)
|
10.31
|
|
Separation Agreement dated March 22, 2016, between Bonanza Creek Energy, Inc. and Christopher Humber (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10‑Q filed on May 5, 2016)
|
10.32
|
|
Long Term Incentive Plan Agreement (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10‑Q filed on August 1, 2016)
|
10.33
|
|
Separation Agreement dated June 15, 2016, between Bonanza Creek Energy, Inc. and Marvin Chronister (incorporated by reference to Exhibit 10.3 of the Quarterly Report on Form 10‑Q filed on August 1, 2016)
|
10.34†
|
|
Employment Letter Agreement dated September 28, 2016, between Bonanza Creek Energy, Inc. and Scott Fenoglio
|
10.35
|
|
Restructuring Support Agreement, dated as of December 23, 2016 (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on December 23, 2016).
|
10.36
|
|
Backstop Commitment Agreement, dated as of December 23, 2016 (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on December 23, 2016).
|
10.37
|
|
Stipulation dated February 1, 2017 among the Debtors, the Ad Hoc Noteholder Group and Silo (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on February 3, 2017).
|
21.1†
|
|
List of subsidiaries
|
23.1†
|
|
Consent of Hein & Associates LLP
|
23.2†
|
|
Consent of Independent Petroleum Engineers, Netherland, Sewell & Associates, Inc.
|
31.1†
|
|
Certification of the Chief Executive Officer pursuant to Rule 13a‑ 14(a)
|
31.2†
|
|
Certification of the Chief Financial Officer pursuant to Rule 13a‑ 14(a)
|
32.1†
|
|
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002 (furnished herewith)
|
32.2†
|
|
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002 (furnished herewith)
|
99.1†
|
|
Report of Independent Petroleum Engineers, Netherland, Sewell & Associates, Inc. for reserves as of December 31, 2016
|
101†
|
|
The following material from the Bonanza Creek Energy, Inc. Annual Report on Form 10‑K for the year ended December 31, 2016 (and related periods), formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations and Comprehensive Income, (iii) the Condensed Consolidated Statements of Stockholders’ Equity, (iv) the Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text
|
•
|
An annual salary of $275,000 to be paid on a bi-weekly basis, subject to all withholdings, taxes, and deductions;
|
•
|
Continued participation in the Company’s Short Term Incentive Program (the “STIP”) administered at the discretion of the Compensation Committee of the Board of Directors of the Company. The STIP has been designed to supplement your base salary and provide a year-over-year short term incentive cash bonus payment opportunity if and when the Company meets or exceeds its goals and you meet your individual goals. We expect that your “target” cash bonus opportunity for 2017 will be equal to 75% of your base salary, based on Company performance achievement as well as individual performance. Your 2016 cash bonus will be pro-rated to take into account your varied base salary and STIP target levels as Vice President, Planning and your new role as Senior Vice President, Finance & Planning;
|
•
|
Continued participation in the Company’s Executive Change in Control and Severance Plan, as amended (the “Severance Plan”). Coincident with your promotion, your status under the Severance Plan will change from a Tier 4 Executive to a Tier 3 Executive (as those terms are defined in the Severance Plan);
|
•
|
Continued participation in the Company’s Amended and Restated 2011 Long Term Incentive Program (“LTIP”), subject to the terms and conditions of the LTIP and the award agreement(s) to be entered into thereunder, at the discretion of the Company’s Compensation Committee and Board of Directors;
|
•
|
Continued participation in the Company’s No Tracking Vacation Program; ten (10) days sick leave annually; and eleven (11) paid holidays per year, all in accordance with the Company’s benefits policy;
|
•
|
Option to participate or continued participation in the Company’s 401(k) Plan, in accordance with such plan; currently the Company provides matching contributions of 6% of W-2 income, which amount may be amended from time to time in accordance with the terms of the 401(k) Plan;
|
•
|
Option to participate or continued participation in the Company’s health insurance plans upon your election subject to the terms and conditions of the plans; and
|
•
|
Option to participate or continued participation in the Company’s flexible benefit plan (Section 125 Plan).
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
|
By:
|
/s/ C.H. (Scott) Rees III
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
Chairman and Chief Executive Officer
|
Dallas, Texas
|
|
|
March 15, 2017
|
|
|
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 most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
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.
|
|
/s/ Richard J. Carty
|
|
Richard J. Carty
|
|
President and Chief Executive Officer
|
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 most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
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.
|
|
/s/ Scott A. Fenoglio
|
|
Scott A. Fenoglio
|
|
Senior Vice President, Finance & Planning
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ Richard J. Carty
|
|
Richard J. Carty
|
|
President and Chief Executive Officer
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
|
/s/ Scott A. Fenoglio
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Scott A. Fenoglio
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Senior Vice President, Finance & Planning
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Net Reserves
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Future Net Revenue (M$)
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Oil
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NGL
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Gas
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Present Worth
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Category
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(MBBL)
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(MBBL)
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(MMCF)
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Total
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at 10%
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Proved Developed Producing
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25,321.1
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9,775.1
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83,636.0
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391,601.9
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245,215.6
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Proved Developed Non-Producing
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992.5
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175.8
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2,335.9
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19,514.7
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11,838.8
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Proved Undeveloped
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23,782.9
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7,595.9
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52,072.9
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178,729.5
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19,901.0
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Total Proved
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50,096.5
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17,546.8
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138,044.8
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589,846.1
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276,955.4
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