Civitas Resources
Annual Report 2015

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Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549____________________________Form 10-KxANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934For the fiscal year ended December 31, 2015OR¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934Commission file number: 001-35371Bonanza Creek Energy, Inc.(Exact name of registrant as specified in its charter) Delaware(State or other jurisdiction ofincorporation or organization)61-1630631(I.R.S. Employer Identification No.)410 17th Street, Suite 1400 Denver, Colorado(Address of principal executive offices)80202(Zip Code)(720) 440-6100(Registrant’s telephone number, including area code)Securities Registered Pursuant to Section 12(b) of the Act: (Title of Class) (Name of Exchange)Common Stock, par value $0.001 per share New York Stock ExchangeSecurities Registered Pursuant to Section 12(g) of the Act: NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No xIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No xIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and postedpursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post suchfiles). Yes x No ¨Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. xIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of“large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer xAccelerated filer ¨Non-accelerated filer ¨(Do not check if asmaller reporting company)Smaller reporting company ¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No xThe aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates on June 30, 2015, based upon the closing price of $18.25 of theregistrant’s common stock as reported on the New York Stock Exchange, was approximately $901,272,418. Excludes approximately 365,800 shares of the registrant’s common stockheld by executive officers, directors and stockholders that the registrant has concluded, solely for the purpose of the foregoing calculation, were affiliates of the registrant.Number of shares of registrant’s common stock outstanding as of February 22, 2016: 49,741,134Documents Incorporated By Reference:Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within120 days of December 31, 2015, are incorporated by reference into Part III of this report for the year ended December 31, 2015. 1 Table of ContentsBONANZA CREEK ENERGY, INC.FORM 10-KFOR THE YEAR ENDED DECEMBER 31, 2015TABLE OF CONTENTS PAGE Glossary of Oil and Natural Gas Terms5PART IItem 1.Business11Item 1A.Risk Factors35Item 1B.Unresolved Staff Comments59Item 2.Properties59Item 3.Legal Proceedings59Item 4.Mine Safety Disclosures59PART IIItem 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities59Item 6.Selected Financial Data61Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations62Item 7A.Quantitative and Qualitative Disclosure about Market Risk78Item 8.Financial Statements and Supplementary Data80Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure110Item 9A.Controls and Procedures110Item 9B.Other Information112PART IIIItem 10.Directors, Executive Officers and Corporate Governance113Item 11.Executive Compensation113Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters113Item 13.Certain Relationships and Related Transactions and Director Independence113Item 14.Principal Accountant Fees and Services113PART IVItem 15.Exhibits, Financial Statement Schedules1142 Table of ContentsInformation Regarding Forward-Looking StatementsThis Annual Report on Form 10-K contains various statements, including those that express belief, expectation or intention, as well as those that arenot statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, andSection 21E of the Securities and Exchange Act of 1934, as amended. When used in this Annual Report on Form 10-K, the words “could,” “believe,”“anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan” “will,” and similar expressions are intended toidentify forward-looking statements, although not all forward-looking statements contain such identifying words.Forward-looking statements include statements related to, among other things:•the Company's business strategies and intent to maximize liquidity;•reserves estimates;•estimated sales volumes for 2016;•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;•ability to modify future capital expenditures;•ability to consummate certain strategic divestitures;•the Wattenberg Field being a premier oil and resource play in the United States;•realization of anticipated cost reductions;•compliance with debt covenants;•ability to fund and satisfy obligations related to ongoing operations;•compliance with government regulations;•adequacy of gathering systems and continuous improvement of such gathering systems;•impact from the lack of available gathering systems and processing facilities in certain areas;•natural gas, oil and natural gas liquid prices and factors affecting the volatility of such prices;•impact of lower commodity prices;•sufficiency of impairments for the remainder of 2016;•the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;•our drilling inventory and drilling intentions;•our estimated revenues and losses;•the timing and success of specific projects;•our implementation of long reach laterals in the Wattenberg Field;•our use of multi-well pads to develop the Niobrara and Codell formations;•intention to continue to optimize enhanced completion techniques and well design changes;•intentions with respect to working interest percentages;•management and technical team;•outcomes and effects of litigation, claims and disputes;•primary sources of future production growth;•full delineation of the Niobrara B and C benches in our legacy acreage;•our ability to replace oil and natural gas reserves;•our ability to convert PUDs to producing properties within five years of their initial proved booking; 3 Table of Contents•impact of recently issued accounting pronouncements;•impact of the loss a single customer or any purchaser of our products;•timing and ability to meet certain volume commitments related to purchase and transportation agreements;•the impact of customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes andother industry-related constraints;•our financial position;•our cash flow and liquidity;•the adequacy of our insurance; and•other statements concerning our operations, economic performance and financial condition.We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception ofhistorical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. They canbe affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual futureresults. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of whichare beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differmaterially from those expressed or implied in the forward-looking statements.Factors that could cause actual results to differ materially include, but are not limited to, the following:•the risk factors discussed in Part I, Item 1A of this Annual Report on Form 10-K;•further declines or volatility in the prices we receive for our oil, natural gas liquids and natural gas;•general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;•ability of our customers to meet their obligations to us;•our access to capital;•our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreagepositions;•the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume rates and associated costs;•uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and possible resources;•the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes andchanges in environmental regulation);•environmental risks;•seasonal weather conditions;•lease stipulations;•drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;•our ability to acquire adequate supplies of water for drilling and completion operations;•availability of oilfield equipment, services and personnel;•exploration and development risks;•competition in the oil and natural gas industry;•management’s ability to execute our plans to meet our goals;•risks related to our derivative instruments;•our ability to attract and retain key members of our senior management and key technical employees;•our ability to maintain effective internal controls;4 Table of Contents•access to adequate gathering systems and pipeline take-away capacity to provide adequate infrastructure for the products of our drillingprogram;•our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;•costs and other risks associated with perfecting title for mineral rights in some of our properties;•continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and•other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact ourbusinesses, operations or pricing.All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to update or revise thesestatements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans,intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we cangive no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differmaterially from our expectations under Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results ofOperations and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us orpersons acting on our behalf.GLOSSARY OF OIL AND NATURAL GAS TERMSWe have included below the definitions for certain terms used in this Annual Report on Form 10-K:“3-D seismic data” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic data typically provide a more detailed andaccurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic data.“Analogous reservoir” Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth,temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogousreservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);(ii)Same environment of deposition;(iii)Similar geological structure; and(iv)Same drive mechanism.“Asset Sale” shall mean any direct or indirect sale, lease (including by means of production payments and reserve sales and a sale and lease-backtransaction), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of(a) shares of capital stock of a subsidiary (b) all or substantially all of the assets of any division or line of business of the Company or any subsidiary or(c) any other assets of the Company or any subsidiary outside of the ordinary course of business.“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.“Bcf” One billion cubic feet of natural gas.“Boe” One stock tank barrel of oil equivalent, calculated by converting natural gas and natural gas liquids volumes to equivalent oil barrels at aratio of six Mcf to one Bbl of oil.“British thermal unit” or “BTU” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.“Basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.5 Table of Contents“Completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil or naturalgas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.“Condensate” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, isin the liquid phase at surface pressure and temperature.“Developed acreage” The number of acres that are allocated or assignable to productive wells or wells capable of production.“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oiland gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs ofdevelopment activities, are costs incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose ofdetermining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to theextent necessary in developing the proved reserves; (ii) drill and equip development wells, development-type stratigraphic test wells, and service wells,including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly; (iii) acquire, construct, andinstall production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gascycling and processing plants, and central utility and waste disposal systems; and (iv) provide improved recovery systems.“Development well” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to beproductive.“Differential” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead pricedreceived.“Deterministic method” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering oreconomic data) in the reserves calculation.“Dry hole” Exploratory or development well that does not produce oil or gas in commercial quantities.“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, oris reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oiland gas producing activities.“Environmental assessment” A study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of aproject.“ERISA” Employee Retirement Income Security Act of 1974.“Estimated ultimate recovery (EUR)” Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production asof that date.“Exploratory well” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in anotherreservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.“Extension well” A well drilled to extend the limits of a known reservoir.“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural featureand/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally bylocal geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operationalfield. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broaderterms of basins, trends, provinces, plays, areas-of-interest, etc.“Finding and development costs” Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amountof estimated net proved reserves added through discoveries, extensions, infill drilling, acquisitions, and revisions of previous estimates less sales of reserves,during the same period.6 Table of Contents“Formation” A layer of rock which has distinct characteristics that differ from nearby rock.“GAAP” Generally accepted accounting principles in the United States.“HH” Henry Hub index.“Horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a rightangle within a specified interval.‘‘Hydraulic fracturing” The process of injecting water, proppant and chemicals under pressure into the formation to fracture the surrounding rockand stimulate production.“LIBOR” London interbank offered rate.“MBbl” One thousand barrels of oil or other liquid hydrocarbons.“MBoe” One thousand Boe.“Mcf” One thousand cubic feet.“MMBoe” One million Boe.“MMBtu” One million British Thermal Units.“MMcf” One million cubic feet.“Net acres” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100acres owns 50 net acres.“Net production” Production that is owned by the registrant and produced to its interest, less royalties and production due others.“Net revenue interest” Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from theworking interest ownership.“Net well” Deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum ofthe fractional working interest owned in gross wells expressed as whole numbers and fractions of whole numbers.“NGL” Natural gas liquid.“NYMEX” The New York Mercantile Exchange.“Oil and gas producing activities” defined as (i) the search for crude oil, including condensate and natural gas liquids, or natural gas in their naturalstates and original locations; (ii) the acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil orgas from such properties; (iii) the construction, drilling and production activities necessary to retrieve oil and gas from their natural reservoirs, including theacquisition, construction, installation, and maintenance of field gathering and storage systems, such as lifting the oil and gas to the surface and gathering,treating and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (iv) extraction of saleable hydrocarbons, in the solid,liquid, or gaseous state, from oil sands, shale, coal beds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas,and activities undertaken with a view to such extraction.“PDNP” Proved developed non-producing reserves.“PDP” Proved developed producing reserves.“Percentage-of-proceeds” A processing contract where the processor receives a percentage of the sold outlet stream, dry gas, NGLs or acombination, from the mineral owner in exchange for providing the processing services. In the Mid-Continent region, we are both a producer and, throughownership of gas plants, a processor, our sales volumes include volumes7 Table of Contentsprocessed through the gas plants directly related to our working interest and volumes for which we are contractually entitled pursuant to the processing of gasfrom third party interests.“Play” A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areaswith potential oil and gas reserves.“Plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escapeinto another or to the surface. Regulations of many states require plugging of abandoned wells.“Pooling” Pooling, either contractually or statutorily through regulatory actions, allows an operator to combine multiple leased tracts to create agovernmental spacing unit for one or more productive formations. (Pooling is also known as unitization or communitization.). Ownership interests arecalculated within the pooling/spacing unit according to the net acreage contributed by each tract within the pooling/spacing unit.“Possible reserves” Those additional reserves that are less certain to be recovered than probable reserves.“Probable reserves” Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves,are as likely as not to be recovered.“Production costs” Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicableoperating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. Theybecome part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are (a) costs of labor to operate the wells andrelated equipment and facilities; (b) repairs and maintenance; (c) materials, supplies, and fuel consumed and supplies utilized in operating the wells andrelated equipment and facilities; (d) property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and (e)severance taxes. Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, andmarketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicableoperating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition,exploration, and development costs are not production costs but also become part of the costs of oil and gas produced along with production (lifting) costsidentified above.“Productive well” An exploratory, development or extension well that is not a dry well.“Proppant” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturallyoccurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, mayalso be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to thewellbore.“Proved developed reserves” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operatingmethods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.“Proved reserves” Those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certaintyto be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods andgovernment regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonablycertain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.(i)The area of the reservoir considered as proved includes:(a)The area identified by drilling and limited by fluid contacts, if any, and(b)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to containeconomically producible oil or gas on the basis of available geoscience and engineering data.8 Table of Contents(ii)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 wellpenetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gascap, proved oil reserves may be assigned in the structurally higher potions of the reservoir only if geoscience, engineering, or performance dataand reliable technology establish the higher contact with reasonable certainty.(iv)Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluidinjection) are included in the proved classification when:(a)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, theoperation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes thereasonable certainty of the engineering analysis on which the project or program was based, and(b)The project has been approved for development by all necessary parties and entities, including governmental entities.(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall bethe average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweightedarithmetic 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.“Proved undeveloped reserves” or “PUD” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existingwells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsettingdevelopment spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishesreasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if adevelopment plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogousreservoir, or by other evidence using reliable technology establishing reasonable certainty.“PV-10” A non-GAAP financial measure that represents inflows from proved crude oil and natural gas reserves, less future development andproduction costs, discounted at 10% per annum to reflect timing of future cash inflows and using the twelve-month unweighted arithmetic average of thefirst-day-of-the-month commodity prices (after adjustment for differentials in location and quality) for each of the preceding twelve months. Please refer tothe footnote 2 of the Proved Reserves table in Item 1 of this Annual Report on Form 10-K for additional discussion.“Reasonable certainty” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will berecovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed theestimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability ofgeoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time,reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.“Recompletion” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in anattempt to establish or increase existing production.“Reserves” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, byapplication of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, thelegal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits andfinancing required to implement the project.9 Table of Contents“Reserve replacement percentage” The sum of sales of reserves, reserve extensions and discoveries, reserve acquisitions, and reserve revisions ofprevious estimates for a specified period of time divided by production for that same period.“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that isconfined by impermeable rock or water barriers and is individual and separate from other reservoirs.“Resource play” Refers to drilling programs targeted at regionally distributed oil or natural gas accumulations. Successful exploitation of thesereservoirs is dependent upon new technologies such as horizontal drilling and multi-stage fracture stimulation to access large rock volumes in order toproduce economic quantities of oil or natural gas.“Royalty interest” An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGLs produced and soldunencumbered by expenses of drilling, completing and operating of the affected well.“Sales volumes” All volumes for which a reporting entity is entitled to proceeds, including production, net to the reporting entity’s interest andthird party production obtained from percentage-of-proceeds contracts and sold by the reporting entity.“Service well” A service well is drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled forthe following specific purposes: gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, orinjection for in-situ combustion.“Spacing” Spacing as it relates to a spacing unit is defined by the governing authority having jurisdiction to designate the size in acreage of aproductive reservoir along with the appropriate well density for the designated spacing unit size. Typical spacing for conventional wells is 40 acres for oilwells and 640 acres for gas wells.“Three stream” The separate reporting of NGLs extracted from the natural gas stream and sold as a separate product.“Undeveloped acreage” Those leased acres on which wells have not been drilled or completed to a point that would permit the production ofeconomic quantities of oil or gas regardless of whether such acreage contains proved reserves.“Undeveloped reserves” Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Also referred to as “undeveloped oil and gasreserves.”“Working interest” The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The workinginterest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.“Workover” Operations on a producing well to restore or increase production.“WTI” West Texas Intermediate index.10 Table of ContentsPART IItem 1. Business.When we use the terms “Bonanza Creek,” the “Company,” “we,” “us,” or “our” we are referring to Bonanza Creek Energy, Inc. and its consolidatedsubsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary ofOil and Natural Gas Terms above. Throughout this document we make statements that may be classified as “forward-looking.” Please refer to the InformationRegarding Forward-Looking Statements section above for an explanation of these types of statements.OverviewBonanza Creek is an independent energy company engaged in the acquisition, exploration, development and production of onshore oil andassociated liquids-rich natural gas in the United States. Bonanza Creek Energy, Inc. was incorporated in Delaware on December 2, 2010 and went public inDecember 2011.Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southernArkansas. In addition, we own and operate oil-producing assets in the North Park Basin in Colorado and the McKamie Patton Field in southern Arkansas. TheWattenberg Field is one of the premier oil and gas resource plays in the United States benefiting from a low cost structure, strong production efficiencies,established reserves and prospective drilling opportunities, which allows for predictable production and reserve growth.Our Business StrategiesBeginning in 2014, the oil and natural gas industry began to experience a sharp decline in commodity prices. Caused in part by global supply anddemand imbalances and an oversupply of natural gas in the United States, the pricing declines have extended into 2016 and the timing of any rebound isuncertain. Low commodity prices resulted in impairments and a reduction of our revenues, profitability, cash flows, proved reserve values and stock price. Ifthe industry downturn continues for an extended period or becomes more severe, we could experience additional impairments and further material reductionsin revenues, profitability, cash flows, proved reserves and stock price.Given the current depressed commodity price environment, our primary goals are to preserve stockholder value by maximizing the cash flows fromour existing production, optimize the Company’s liquidity position and position our organization and leasehold for increased development activity whenthe appropriate commodity price signals are observed. We intend to accomplish this by focusing on the following key strategies:•2016 Liquidity. We are considering various strategies to reinforce our balance sheet and improve our liquidity. These strategies include potentialasset sales and joint ventures or other arrangements that would enable us to support development of our core areas with additional third-partycapital, debt restructurings, the issuance of new debt or equity and conservation of our liquid assets. The outcome of these potential alternatives, thetiming of which cannot be accurately predicted at this time, are likely to affect our liquidity, future operations and financial condition.•2016 Capital Expenditures. We expect to control our reduced liquidity during 2016 by scaling back our capital expenditures to match the currentcommodity pricing environment. Although we cannot predict or control future commodity prices, our expected 2016 capital expenditure budget hasbeen decreased to accommodate the reduction in commodity prices. We have a modest capital program of $40.0 million to $50.0 million planned for2016 in order to conserve our liquid assets. These costs will largely be incurred during the first quarter of 2016.•Cost-Reduction Initiatives. We have taken steps to reduce our future capital, operating and corporate costs. During 2015, we negotiated with ourprimary suppliers and service providers resulting in an approximate 29% reduction in our drilling and completion costs on our standard reach lateralwells and an approximate 12% reduction in our lease operating expense per Boe. We also took measures to reduce corporate costs by reducingheadcount resulting in a $5.3 million reduction in general and administrative expense on an annual basis and we continue to focus on cost reductionopportunities.Competitive Strengths•Control the timing of resource development on our leasehold. We maintain a 90% working interest and operate the majority of our futuredevelopment drilling inventory. This allows the Company to control the pace and magnitude of11 Table of Contentsour future capital expenditures and provides us the ability to wait for increased commodity prices prior to undertaking future projects.•Continue to align our operations and cost structure to current economic conditions. We operate 98% of our current production. All decisionsrelated to the technical operation of these producing properties and the costs associated with operation of these assets are made by the Company. Weleverage our operating and asset management skills to optimize the productivity of these properties while minimizing the ongoing costs ofoperations.•Large, contiguous leasehold in the Denver-Julesburg Basin. We control approximately 69,000 net acres in the Wattenberg Field in Weld County.We believe the contiguous nature of our leasehold allows for the most efficient resource development by providing the greatest ability to drilllarge pads of horizontal wells with centralized surface facilities servicing multiple pads over the life of field development.•High degree of geologic and technical control. We have successfully delineated the majority of our leasehold over the past four years. Whencoupled with offsetting operator results, we believe our future development locations have a high degree of definition.•Liquids-weighted reserves. While current commodity prices have caused us to significantly reduce our anticipated drilling plan for 2016, we believethe commodity mix of our reserves provides significant leverage to any future recovery in oil prices.•Significant inventory of undrilled locations available for development. As of December 31, 2015, we had 204 gross (163.9 net) proved undevelopedlocations (220 gross standard reach lateral equivalents) identified in the Wattenberg Field, which represents a 3.4 year future development inventoryassuming a continuous one rig drilling program.In 2015, we successfully drilled 101 and completed 110 productive operated wells and participated in drilling seven and completing six productivenon-operated wells. The resulting production rates achieved by this program increased sales volumes by 20% over the previous year to 28,272 Boe/d ofwhich 76% was crude oil and natural gas liquids (“NGLs”). We had nine operated wells and three non-operated wells in progress as of December 31, 2015.Our sales volumes during the fourth quarter of 2015 were 28,572 Boe/d, a 10% increase over the comparable period in 2014.The following tables summarize our estimated proved reserves, PV-10 reserve value, sales volumes, and projected capital spend as of December 31,2015: Natural Crude Natural Gas Total Oil Gas Liquids ProvedEstimated Proved Reserves (MBbls) (MMcf) (MBbls) (MBoe)Developed Rocky Mountain 21,074 53,864 8,704 38,756 Mid-Continent 7,818 23,616 1,655 13,409 28,892 77,480 10,359 52,165Undeveloped Rocky Mountain 24,689 49,916 8,400 41,408 Mid-Continent 3,812 16,831 1,159 7,776 28,501 66,747 9,559 49,184Total Proved 57,393 144,227 19,918 101,34912 Table of Contents Sales Volumes for the Year Ended Net Proved Estimated Proved Reserves at December 31, Undeveloped December 31, 2015(1) 2015 Drilling Average Net Projected Locations Total Daily Sales 2016 Capital as of Proved % of % Proved PV-10 Volumes % of Expenditures December 31, (MBoe) Total Developed ($ in MM)(2) (Boe/d) Total ($ in millions) 2015Rocky Mountain 80,164 79% 48% $247.8 22,987 81% $36.5-46.5 163.9Mid-Continent(3) 21,185 21% 63% 80.0 5,285 19% 3.5 81.1Total 101,349 100% 51% $327.8 28,272 100% $40.0-50.0 245.0_____________________(1)Proved reserves and related future net revenue and PV-10 were calculated using prices equal to the twelve-month unweighted arithmetic average of thefirst-day-of-the-month commodity prices for each of the preceding twelve months, which were $50.28 per Bbl WTI and $2.59 per MMBtu HH.Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $6.28 per Bbl of crude oil and adecrease of $0.26 per MMBtu of natural gas.(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 naturalgas 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 eachof the preceding twelve months. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts andsophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetarysignificance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size andvalue of our reserves to other companies’ reserves. Because there are many unique factors that can impact an individual company when estimating theamount 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 notintended 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 StandardizedMeasure presented several pages below.(3)Mid-Continent sales volumes were 5,285 Boe/d for 2015, which is comprised of 4,684 Boe/d of production net to our interest and 601 Boe/d salesvolumes from our percentage-of-proceeds contracts.Our OperationsOur operations are mainly focused in the Wattenberg Field in the Rocky Mountain region and in the Dorcheat Macedonia Field in the Mid-Continent region.Rocky Mountain RegionThe two main areas in which we operate in the Rocky Mountain region are the Wattenberg Field in Weld County, Colorado and the North ParkBasin in Jackson County, Colorado. As of December 31, 2015, our estimated proved reserves in the Rocky Mountain region were 80,164 MBoe, whichrepresented 79% of our total estimated proved reserves and contributed 22,987 Boe/d, or 81%, of sales volumes during 2015.Wattenberg Field - Weld County, Colorado. Our operations are in the oil and liquids-weighted extension area of the Wattenberg Field targeting theNiobrara and Codell formations. As of December 31, 2015, our Wattenberg position consisted of approximately 91,000 gross (69,000 net) acres. We own 3-Dseismic surveys covering the majority of our acreage in the Wattenberg Field, which helps provide efficient and targeted horizontal drilling operations. Wehave seen an uplift in production from larger stimulations using approximately 1,500 pounds per foot and from our new mono-bore well design thatincorporates the plug-and-perf completion technique. We plan to incorporate both techniques on wells drilled and completed during 2016.The Wattenberg Field is now primarily developed for the Niobrara and Codell formations using horizontal drilling and multi-stage fracturestimulation techniques. We believe the Niobrara B and C benches have been fully delineated on our legacy acreage, while the Codell formation continues tobe delineated in our eastern legacy acreage. Our delineation wells in our Northern acreage have validated the productivity of the Niobrara Chalk.13 Table of ContentsOur estimated proved reserves at December 31, 2015 in the Wattenberg Field were 79,869 MBoe. As of December 31, 2015, we had a total of 620gross producing wells, of which 401 were horizontal wells, and our sales volumes during 2015 were 22,894 Boe/d. Our sales volumes for the fourth quarter of2015 were 23,535 Boe/d. As of December 31, 2015, our working interest for all producing wells averaged approximately 90% and our net revenue interestwas approximately 74%.Our strategy in 2015 was to utilize existing infrastructure and maximize extended reach lateral wells to allow us to reduce costs. We also establisheda midstream entity, Rocky Mountain Infrastructure, LLC, to house our gas gathering and midstream facility assets that we subsequently deemed as held forsale during the same year. We continued to expand our proved reserves in this area by drilling non-proved horizontal locations. As of December 31, 2015, wehave an identified drilling inventory of approximately 204 gross (163.9 net) proved undeveloped (“PUD”) drilling locations (220 gross standard reach lateralequivalents) on our acreage with an average standard reach lateral well cost of $3.0 million, based on average capital expenditures in 2015 when excludingoutliers. During 2015, we drilled 84 and completed 95 gross horizontal wells.The first criteria of our 2015 operated drilling program was to drill near our central production facilities. We maximized our extended reach lateraldevelopment in the program and were successful in achieving 48% of our program as extended reach laterals on a standard reach lateral equivalent basis (47of 98 standard reach lateral equivalents). During the year, in the Niobrara benches, we drilled 26 extended reach lateral wells and 45 standard reach lateralwells. We completed 28 extended reach lateral wells and 51 standard reach lateral wells. In addition, we drilled 6 Codell standard reach lateral wells andcompleted 10 with carryover from 2014. We also participated in the drilling of 2 standard reach lateral wells (0.8 net) and 5 extended reach lateral wells (1.0net) and the completion of 6 extended reach lateral wells (0.8 net) in the Niobrara formation. During 2015 we analyzed our test results using variouscompletion fluids and additives, frac sand concentration and casing designs and configurations.We estimate our capital expenditures in the Wattenberg Field for the first quarter 2016 will range from $35.0 million to $45.0 million, to be used todrill two extended reach lateral wells in the Niobrara formation, six standard reach lateral wells in the Niobrara and one standard reach lateral well in theCodell. We anticipate completing four medium reach lateral wells and eight standard reach lateral wells in the Niobrara in the first quarter of 2016 andparticipate in three non-operated well completions (two standard reach laterals and one extended reach lateral). The Company expects well costs to continueto contract in the near term, targeting a range of $2.5 million to $2.7 million for a standard reach lateral well down from $4.2 million and is targetingapproximately $4.3 million for an extended reach lateral well down from $5.1 million. Further budget guidance for the remainder of 2016 will be determinedbased upon the final outcome of our divestiture processes. Please refer to Note 3 - Assets Held for Sale in Part II, Item 8 of this Annual Report on Form 10-K,for additional discussion. In 2016, we plan to use the monobore well design that incorporates the plug-and-perf completion technique and 1,500 pounds offrac sand per lateral foot.North Park Basin - Jackson County, Colorado. We control approximately 19,000 gross (15,000 net) acres in the North Park Basin in JacksonCounty, Colorado, all prospective for the Niobrara oil shale. We operate the North and South McCallum Fields, which currently produce light oil, which istrucked to market. We currently have all of our assets within the North Park Basin held for sale.In the North Park Basin, our estimated proved reserves as of December 31, 2015 were approximately 295 MBoe, 100% of which was crude oil, andour sales volumes during 2015 were 93.4 Boe/d. Our sales volumes for the fourth quarter of 2015 were 70.6 Boe/d. During 2014, we drilled and cored onevertical well, which was subsequently evaluated in 2015 and deemed a dry hole at such time. There were no wells drilled during 2015 in the North ParkBasin.None of our 2016 capital budget is assigned to the North Park Basin.Mid-Continent RegionIn southern Arkansas, we target the oil-rich Cotton Valley sands in the Dorcheat Macedonia and McKamie Patton Fields. As of December 31, 2015,our estimated proved reserves in the Mid-Continent region were 21,185 MBoe, 68% of which were oil and NGLs and 63% of which were proved developed.We currently have 294 gross producing vertical wells. During 2015, we drilled 24 wells and successfully completed 21 operated wells in the Mid-Continentregion. We achieved a sales volume rate for 2015 of 5,285 Boe/d, of which 69% was from oil and NGLs, and a sales volume rate for the fourth quarter of 2015of 4,966 Boe/d. Productive reservoirs range in depth from 4,500 to 9,000 feet. Those reservoirs include the Smackover and the Pettet, but our primarydevelopment target is the Cotton Valley sands. We estimate our capital expenditures in the Mid-Continent region for 2016 could be $3.5 million with thecontinuation of the recompletion program, although we currently have all of our assets within the Mid-Continent region held for sale.14 Table of ContentsDorcheat Macedonia. In the Dorcheat Macedonia Field, we average an approximate 89% working interest and an approximate 73% net revenueinterest on all producing wells, and the majority of our acreage is held by unitization, production, or drilling operations. We have approximately 260 grossproducing wells and our production during 2015 was approximately 4,450 Boe/d (5,051 Boe/d sales volumes). During the fourth quarter of 2015, ourproduction was 4,129 Boe/d (4,730 Boe/d sales volumes). Our proved reserves in this field are approximately 20,073 MBoe. As of December 31, 2015, wehave identified approximately 96 gross (81.1 net) PUD drilling locations on our acreage in this area. During 2015, we drilled 22 and successfully completed21 vertical Cotton Valley wells in the Dorcheat Macedonia Field.Other Mid-Continent. We own additional interests in the McKamie Patton Field in the Mid-Continent region near the Dorcheat Macedonia Field. Asof December 31, 2015, our estimated proved reserves were approximately 1,112 MBoe, and sales volume during 2015 were approximately 234 Boe/d. Duringthe fourth quarter of 2015, our production was 236 Boe/d.Gas Processing Facilities. Our Mid-Continent gas processing facilities are located in Lafayette and Columbia counties in Arkansas and arestrategically located to serve our production in the region. In the aggregate, our Arkansas gas processing facilities have approximately 40 MMcf/d ofcapacity with 86,000 gallons per day of associated NGL capacity. As a cost savings measure, during 2015 we idled our McKamie Patton gas plant droppingour current capacity in the Dorcheat Macedonia Field to 24 MMcf/d with 54,000 gallons per day of associated NGL capacity. Our ownership of thesefacilities and related gathering pipeline provides us with the benefit of controlling processing and compression of our natural gas production and the timingof connection to our newly completed wells.ReservesEstimated Proved ReservesThe summary data with respect to our estimated proved reserves presented below has been prepared in accordance with rules and regulations of theSecurities and Exchange Commission (the “SEC”) applicable to companies involved in oil and natural gas producing activities. Our reserve estimates do notinclude probable or possible reserves, categories which SEC rules do permit us to disclose in public reports. Our estimated proved reserves for the years endedDecember 31, 2015, 2014 and 2013 were determined using the preceding twelve months’ unweighted arithmetic average of the first-day-of-the-month prices.For a definition of proved reserves under the SEC rules, please see the Glossary of Oil and Natural Gas Terms included in the beginning of this report.Reserve estimates are inherently imprecise and estimates for new discoveries are more imprecise than reserve estimates for producing oil and gasproperties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table arenot intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actual quantities andpresent values of our estimated proved reserves may be less than we have estimated.15 Table of ContentsThe table below summarizes our estimated proved reserves at December 31, 2015, 2014 and 2013 for each of the regions and currently producingfields in which we operate. The proved reserve estimates at December 31, 2015 and 2014 are based on reports prepared by our internal corporate reservoirengineering group, of which 100% were audited by Netherland, Sewell & Associates, Inc. (“NSAI”), our third-party independent reserve engineers. Theproved reserve estimates at December 31, 2013 are based on reports prepared by NSAI. In preparing these reports for 2013, NSAI evaluated 100% of ourestimated proved reserves. For more information regarding our independent reserve engineers, please see Independent Reserve Engineers below. Theinformation in the following table is not intended to represent the current market value of our proved reserves nor does it give any effect to or reflect ourcommodity derivatives or current commodity prices. At December 31,Region/Field 2015 2014 2013 (MMBoe)Rocky Mountain 80.1 68.1 49.1 Wattenberg 79.8 67.8 48.8 North Park 0.3 0.3 0.3Mid-Continent 21.2 21.4 20.7 Dorcheat Macedonia 20.1 19.9 19.4 McKamie Patton 1.1 1.5 1.3 Total 101.3 89.5 69.8The following table sets forth more information regarding our estimated proved reserves at December 31, 2015, 2014 and 2013: At December 31, 2015 2014 2013 Reserve Data(1): Estimated proved reserves: Oil (MMBbls) 57.4 54.7 43.6 Natural gas (Bcf) 144.2 188.6 139.6 Natural gas liquids (MMBbls) 19.9 3.4 2.9 Total estimated proved reserves (MMBoe)(2) 101.3 89.5 69.8 Percent oil and liquids 76% 65% 67% Estimated proved developed reserves: Oil (MMBbls) 28.9 28.3 20.7 Natural gas (Bcf) 77.5 94.5 59.2 Natural gas liquids (MMBbls) 10.4 2.2 1.6 Total estimated proved developed reserves (MMBoe)(2) 52.2 46.3 32.2 Percent oil and liquids 75% 66% 69% Estimated proved undeveloped reserves: Oil (MMBbls) 28.5 26.4 22.9 Natural gas (Bcf) 66.7 94.1 80.4 Natural gas liquids (MMBbls) 9.6 1.2 1.3 Total estimated proved undeveloped reserves (MMBoe)(2) 49.2 43.2 37.6 Percent oil and liquids 77% 64% 64% ____________________(1)Proved reserves were calculated using prices equal to the twelve month unweighted arithmetic average of the first-day-of-the-month prices for each ofthe preceding twelve months, which were $50.28 per Bbl WTI and $2.59 per MMBtu HH, $94.99 per Bbl WTI and $4.35 per MMBtu HH, and $96.91per Bbl WTI and $3.67 per MMBtu HH for the years ended December 31, 2015, 2014 and 2013, respectively. Adjustments were made for location andgrade.(2)Determined using the ratio of 6 Mcf of natural gas to one Bbl of crude oil.16 Table of ContentsProved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment andoperating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or fromexisting wells where a relatively major expenditure is required for completion. Proved undeveloped reserves on undrilled acreage are limited to those directlyoffsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishesreasonable certainty of economic productivity at greater distances.Proved undeveloped locations in our December 31, 2015 reserve report are included in our development plan and are scheduled to be drilled withinfive years from their initial proved booking date. The Company’s management evaluated the proved undeveloped drilling plan using the Company’s currentbudget price deck and the liquidation model for general and administrative costs, estimated interest payments and hedging payments. The budget price deckwas derived from various external sources, such as the NYMEX strip price, the S&P and Moody's indices, prices from equity analysts who cover theCompany, along with internal management estimates. We have a strong PUD conversion rate as evidenced by our 2014 conversion rate of 21% and our 2015conversion rate of 16%. Given the anticipated limited drilling program in 2016, we analyzed the potential PUD loss within the Wattenberg Field at the end of2016 to be less than 1%. The reliable technologies used to establish our proved reserves are a combination of pressure performance, geologic mapping, offsetproductivity, electric logs, and production data.Estimated proved reserves at December 31, 2015 were 101.3 MMBoe, a 13% increase from estimated proved reserves of 89.5 MMBoe atDecember 31, 2014. Approximately 79% of our December 31, 2015 proved reserves are attributed to the Rocky Mountain region, over 99% of which areattributed to the Wattenberg Field. The net increase in our reserves of 11.8 MMBoe is the result of additions in extensions and discoveries of 12.0 MMBoe,coupled with a net positive revision of 8.4 MMBoe (engineering and pricing) and net acquisitions of 1.5 MMBoe offset by 10.1 MMBoe in production. TheMid-Continent region contributed the acquisition reserves of 1.5 MMBoe, 2.5% the extensions and discoveries and less than 4% of the reserve revisions.The addition in extension and discoveries is primarily the result of drilling and completing 63 unproved horizontal locations (including five non-operated) in the Niobrara and the Codell formations in the Wattenberg Field during 2015 and the addition of 17 new horizontal proved undevelopedlocations. Twenty-eight additional proved undeveloped locations were added in the engineering revision category since the offsetting proved developedproducing wells were drilled prior to 2015. For the year ended December 31, 2015, greater than 90% of our horizontal development in the Wattenberg Fieldwas in the Niobrara formation, the majority of which was on 80-acre spacing within each bench. All Niobrara proved undeveloped locations are spaced on 80acres.Total Company positive engineering revisions as of December 31, 2015, were 37,174 Mboe, of which 30,086 Mboe (81%) related to reserve changesin the Wattenberg Field. This positive engineering revision is offset by a negative pricing revision of 21,417 Mboe in the Wattenberg Field. The majority ofthe positive revisions in the Wattenberg Field resulted from a combination of decreased drilling and completion costs, $3.0 million per standard reach lateralwell as of December 31, 2015 compared to $4.2 million at December 31, 2014, a 29% decrease, and an increase in productivity from horizontal proveddeveloped producing wells which increased the offsetting proved undeveloped reserves. The increase in proved developed producing reserves is primarilyattributed to the installation of infrastructure in the east side of our Wattenberg Field acreage which removed the producing constraint that inhibitedproductivity over the last two years of development in that area. Another significant contribution to the positive reserve revision in the Wattenberg Fieldresults from a contract change as of January 1, 2015 which gives our Company ownership of the natural gas liquids from our gas production. This conversionfrom two stream (wet gas and oil) to three stream (dry gas, natural gas liquids and oil) added 8,560 Mboe to our proved reserves as of December 31, 2015.With the addition of 45 horizontal proved undeveloped locations in the Wattenberg Field to the proved reserves at December 31, 2015, the total provedundeveloped location count is 204 (220 standard reach lateral equivalents) and was 226 as of December 31, 2014. Our five-year plans include the drilling ofthese proved undeveloped locations before they expire. The 2016 drilling program included in the year end 2015 reserves is a one rig program estimated toconvert 16% of our year end 2015 proved undeveloped reserves in the Wattenberg Field. If commodity prices do not increase significantly or if our propertiesheld for sale are not sold, we will cease drilling at the end of the first quarter 2016. At that time, we anticipate we will have drilled 20% of the provedundeveloped locations scheduled to be drilled in 2016. There is only one horizontal proved undeveloped location in the Wattenberg Field at risk to expire in2016 if we do not continue drilling past the first quarter of the year. If we cease drilling at the end of the first quarter of 2016, run a single rig program in 2017and add one additional rig per year thereafter for the remaining three years, all remaining proved undeveloped locations will be developed within their fiveyear windows. A negative pricing revision of 28,810 Mboe for the Company resulted from a decrease in average commodity price from $94.99 per Bbl WTIand $4.35 per MMBTU HH for the year ended December 31, 2014 to $50.28 per Bbl WTI and $2.59 per MMBTU HH for the year ended December 31, 2015.17 Table of ContentsEstimated proved reserves at December 31, 2014 were 89.5 MMBoe, a 28% increase from estimated proved reserves of 69.8 MMBoe at December31, 2013. The net increase in reserves of 19.7 MMBoe was the result of additions in extensions and discoveries of 20.2 MMBoe, primarily due to thedevelopment of the Niobrara B and C benches and the Codell formations in the Wattenberg Field, coupled with a net positive revision of 7.1 MMBoe(engineering and pricing) and net acquisitions (acquisitions less divestitures) of 0.8 MMBoe offset by 8.4 MMBoe in production. The addition in extensionand discoveries was primarily the result of drilling and completing 99 unproved horizontal locations (including 12 non-operated) in the Niobrara and theCodell formations in the Wattenberg Field during 2014 and the addition of 37 new horizontal proved undeveloped locations directly offsetting new wellsbrought online in 2014. As of December 31, 2014, approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara Bformation, the majority of which was on 80-acre spacing. The net positive engineering revision was primarily the result of adding new Niobrara B provedundeveloped locations on 80-acre spacing, directly offsetting economic proved producing Niobrara B wells drilled prior to 2014, diagonal offsets toeconomic Niobrara B proved producing wells and a relatively small number of locations greater than one offset to economic Niobrara B proved producingwells but within developed areas and surrounded by Niobrara B proved producing wells. A total of 119 horizontal proved undeveloped locations were addedto the proved reserves at December 31, 2014 of which 86 (72%) were direct offsets to economic proved producing wells (drilled in 2014 or prior to 2014), 21(18%) were direct offsets in a diagonal pattern to economic proved producing wells and 12 (10%) were greater than one offset from economic provedproducing wells. The reasonable certainty of the reserves associated with the latter two categories of proved undeveloped locations was based on analysis ofthe immediate surrounding productivity of the Niobrara B bench and detailed geologic mapping. All Niobrara proved undeveloped locations were spaced on80 acres. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A negative pricing revision of0.25 MMBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBTU HH for the year ended December 31,2013 to $94.99 per Bbl WTI and $4.35 per MMBTU HH for the year ended December 31, 2014.Estimated proved reserves at December 31, 2013 were 69.8 MMBoe, a 32% increase from estimated proved reserves of 53.0 MMBoe atDecember 31, 2012. The net increase in reserves of 16.8 MMBoe resulting from development in the Wattenberg Field was comprised of 28.9 MMBoe ofadditions in extensions and discoveries offset by 3.8 MMBoe in sales volumes and negative revisions of 8.3 MMBoe. The negative revision results primarilyfrom a combination of eliminating 45 net vertical locations from proved undeveloped due to the change in focus from vertical to horizontal development, theelimination of all proved non-producing reserves associated with vertical well refracs, recompletions, and lower performance from our vertical producers dueto increased line pressure. The addition in extension and discoveries was the result of drilling and completing 68 unproved horizontal locations (includingfour non-operated) in the Wattenberg Field during 2013 and the addition of 89 new horizontal proved undeveloped locations. A net increase in reserves of0.1 MMBoe in the Mid-Continent region resulted from the drilling and completion of our 5-acre increased density pilots in the Cotton Valley formationoffset by a negative revision resulting from lower than expected proved developed performance. A small positive pricing revision of 0.51 MMBoe resultedfrom an increase in average commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per BblWTI and $3.67 per MMBtu HH for the year ended December 31, 2013.Reconciliation of PV-10 to Standardized MeasurePV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of theStandardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes,discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flowsattributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating therelative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative sizeand value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gasproperties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present thefair value of our oil and natural gas reserves.18 Table of ContentsThe following table provides a reconciliation of PV-10 to Standardized Measure at December 31, 2015, 2014 and 2013: December 31, 2015 2014 2013 (in millions)PV-10 $327.8 $1,340.5 $1,227.2Present value of future income taxes discounted at 10%(1) — (233.1) (301.9)Standardized Measure $327.8 $1,107.4 $925.3____________________________(1) The tax basis of our oil and gas properties as of December 31, 2015 provides more tax deduction than income generated from our oil and gas propertieswhen the reserve estimates were prepared using $50.28 per Bbl WTI and $2.59 per MMBTU HH.Proved Undeveloped Reserves Net Reserves, MBoe At December 31, 2015 2014 2013Beginning of year 43,246 37,603 29,192Converted to proved developed (6,994) (7,791) (3,047)Additions from capital program 2,308 5,596 16,535Acquisitions 1,541 — 1,779Revisions 9,083 7,838 (6,856)End of year 49,184 43,246 37,603At December 31, 2015, our proved undeveloped reserves were 49,184 MBoe, all of which are scheduled to be drilled within five years of their initialproved booking date. During 2015, the Company converted 16% of its proved undeveloped reserves (52 gross wells representing net reserves of 6,994MBoe) at a cost of $121.0 million. Executing our 2015 capital program resulted in the addition of 2,308 MBoe (17 gross wells) in proved undevelopedreserves in the Wattenberg Field. A small acquisition within the field limits of the Dorcheat Macedonia Field added 14 gross proved undeveloped locationsand 1,541 MBoe to our reserves. The positive engineering revision of 9,083 MBoe was primarily the result of adding 28 gross new proved undevelopedlocations in the Wattenberg Field on 80-acre spacing, the majority directly offsetting economic proved producing wells drilled prior to 2015, and an increasein east Wattenberg Field proved undeveloped reserves resulting from increased productivity due to the installation of infrastructure which eliminated aproduction constraint thereby allowing productivity to rise, proved developed reserves to increase, and associated proved undeveloped reserves to increaseby an estimated 3.0 MMBoe.At December 31, 2014, our proved undeveloped reserves were 43,246 MBoe, all of which were scheduled to be drilled within five years of theirinitial proved booking date. During 2014, the Company converted 21% of its proved undeveloped reserves (58 gross wells representing net reserves of 7,791MBoe) at a cost of $116.9 million. Executing our 2014 capital program resulted in the addition of 5,596 MBoe (45 gross wells) in proved undevelopedreserves. The positive engineering revision of 7,838 MBoe was primarily the result of adding 49 new proved undeveloped locations in Wattenberg on 80-acre spacing, directly offsetting economic proved producing wells drilled prior to 2014, 21 diagonal offsets to economic proved producing wells and 12gross proved undeveloped locations positioned greater than one offset to economic proved producing wells but within developed areas and surrounded byproved producing wells. Also included in the revision category was the removal from proved undeveloped locations of 15 horizontal locations in theWattenberg Field that were no longer spaced on 80 acres following the 2014 capital drilling program and all of the vertical proved undeveloped locations inthe Wattenberg Field which have been replaced by horizontal wells or are expected to be replaced in the future. Proved undeveloped locations remaining inthe category from December 31, 2013 received a downward revision of 214 Mboe.At December 31, 2013, our proved undeveloped reserves were 37,603 MBoe, all of which were scheduled to be drilled within five years of theirinitial proved booking date. During 2013, 3,047 MBoe or 10% of our proved undeveloped reserves (40 gross wells) were converted into proved developedreserves requiring $62.8 million of drilling and completion capital. Continued delineation and testing in our Wattenberg Field in 2013 resulted in aconversion rate less than 20% for the19 Table of Contentsyear. Execution of our 2013 capital program resulted in the addition of 16,535 MBoe in proved undeveloped reserves (92 gross wells). The negative revisionof 6,856 MBoe resulted from a combination of eliminating vertical proved undeveloped locations in the Wattenberg Field continuing the transition tohorizontal development and a reduction in proved undeveloped reserves in the Dorcheat Macedonia Field based on proved developed performance.Internal controls over reserves estimation processOur policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with SEC definitions andguidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by theSociety of Petroleum Engineers. The Company’s Reserves Committee reviews significant reserve changes on an annual basis and our third-party independentreserve engineers, NSAI, is engaged by and has direct access to the Reserves Committee. NSAI audited 100% of our estimated proved reserves atDecember 31, 2015 and 2014, and evaluated 100% of our estimated proved reserves in the preparation of our reserve report at December 31, 2013.Responsibility for compliance in reserves estimation is delegated to our internal corporate reservoir engineering group managed by Lynn E. Boone.Ms. Boone is our Senior Vice President, Planning & Reserves. Ms. Boone attended the Colorado School of Mines and graduated in 1982 with a Bachelor ofScience degree in Chemical and Petroleum Refining Engineering. She attended the University of Oklahoma and graduated in 1985 with a Master of Sciencedegree in Petroleum Engineering. Ms. Boone has been involved in evaluations and the estimation of reserves and resources for over 32 years. She hasmanaged the technical reserve process at a company level for over ten years. Collectively with Ms. Boone, our internal corporate reservoir engineering grouphas over 100 years of experience.Our technical team works with our banking syndicate members at least twice each year for a valuation of our reserves by the banks in our lendinggroup and their engineers in determining the borrowing base under our revolving credit facility.Independent Reserve EngineersThe reserves estimates for the years ended December 31, 2015 and 2014 shown herein have been independently audited by NSAI, a worldwideleader of petroleum property analysis for industry and financial organizations and government agencies, and prepared by them for the year ended December31, 2013. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. DanSmith and Mr. John Hattner. Mr. Smith, a Licensed Professional Engineer in the State of Texas (No. 49093), has been practicing consulting petroleumengineering at NSAI since 1980 and has over seven years of prior industry experience. He graduated from Mississippi State University in 1973 with aBachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559), has beenpracticing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami,Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in GeologicalOceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet orexceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas ReservesInformation promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering andgeoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.Production, Revenues and Price HistoryThe recent collapse in oil prices is among the most severe on record. The daily NYMEX WTI oil spot price went from a high of $107.62 per Bbl in2014 to low of $34.73 per Bbl in 2015. The drop in crude oil pricing is due in large part to increased production levels, crude oil inventories and recessedglobal economic growth. Oil prices are also impacted by real or perceived geopolitical risks in oil producing regions, the relative strength of the U.S. dollar,weather and the global economy. Gas prices have been under downward pressure during 2015 due to excess supply leading to higher levels of gas in storagewhen compared to the 5-year average. We expect that depressed oil prices will lead to cuts in the exploration and production budgets to reduce incrementaloil supply, which should ultimately restore equilibrium to the world oil market and rebalance oil prices.An extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results ofoperations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets. We believe thatwe have the means necessary to fund our limited drilling program in 2016 with operating cash flows. Our drilling program consists of limited drilling in thefirst quarter of 2016 with no drilling for the remainder of the year until such time that oil prices rebound or we execute a divestiture. Please refer to Part II,20 Table of ContentsItem 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion on liquidity.Sensitivity AnalysisIf oil and natural gas SEC prices declined by 10% then our PV-10 value as of December 31, 2015 would decrease by approximately 12% or $39.5million. The PV-10 of our Rocky Mountain region, primarily our Wattenberg assets, would decrease by 9.5% or $23.5 MM.We recorded $419.3 million and $321.2 million of proved property impairments in the Rocky Mountain and Mid-Continent regions, respectively,during the third and fourth quarters of 2015. We believe that we have sufficiently written-down our proved properties to their current fair value and do notanticipate triggering additional impairments in 2016 when analyzing price changes only. Impairment calculations use undiscounted cash flows to indicatewhether assets are impaired. After our 2015 impairments, our asset carrying values are well below the undiscounted cash flows. We ran various impairmentreserve runs keeping all assumptions constant except for pricing and concluded that the NYMEX WTI strip price would have to drop below $20.00 per Bblfor 2016, 2017 and 2018 to trigger an additional impairment, assuming prices revert back to budget pricing for years subsequent to 2018.For the oil and natural gas derivatives outstanding at December 31, 2015, a hypothetical upward or downward shift of 10% per Bbl or MMBtu in theNYMEX forward curve as of December 31, 2015 would change our derivative gain by $(0.3) million and $0.3 million, respectively.ProductionThe following table sets forth information regarding oil and natural gas production, sales prices, and production costs for the periods indicated. Foradditional information on price calculations, please see information set forth in Part II, Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations.21 Table of Contents For the Years Ended December 31, 2015 2014(1) 2013(1)Oil: Total Production (MBbls) 6,072.3 5,618.7 3,887.2 Wattenberg Field 5,029.6 4,486.4 2,775.6 Dorcheat Macedonia Field 923.2 1,025.6 925.2Average sales price (per Bbl), including derivatives $62.10 $84.00 $88.82Average sales price (per Bbl), excluding derivatives $40.98 $81.95 $91.84Natural Gas: Total Production (MMcf) 14,110.9 15,316.1 9,975.9 Wattenberg Field 11,020.8 11,372.7 6,269.1 Dorcheat Macedonia Field 3,090.5 4,030.6 3,598.3Average sales price (per Mcf), including derivatives $2.01 $5.16 $4.70Average sales price (per Mcf), excluding derivatives $1.82 $5.11 $4.66Natural Gas Liquids: Total Production (MBbls) 1,675.9 260.6 352.8 Wattenberg Field 1,489.9 16.8 10.2 Dorcheat Macedonia Field 186.0 243.8 342.6Average sales price (per Bbl), including derivatives $9.49 $49.14 $51.74Average sales price (per Bbl), excluding derivatives $9.49 $49.14 $51.74Oil Equivalents: Total Production (MBoe) 10,100.0 8,365.6 5,902.7 Wattenberg Field 8,356.3 6,398.6 3,830.7 Dorcheat Macedonia Field 1,624.2 1,874.7 1,867.5Average Daily Production (Boe/d) 27,671.2 22,919.3 16,171.8 Wattenberg Field 22,894.1 17,530.5 10,495.0 Dorcheat Macedonia Field 4,450.0 5,136.3 5,116.4Average Production Costs (per Boe)(3)(2) $7.56 $8.66 $8.09_________________________(1)Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or heldfor sale as of December 31, 2014 and 2013.(2)Excludes ad valorem and severance taxes.(3)Represents lease operating expense per Boe using total production volumes of 10,100.0 MBoe and 8,365.6 MBoe for 2015 and 2014, respectively. Totalproduction volumes exclude volumes from our percentage-of-proceeds contracts of 219.4 MBoe and 215.3 MBoe for 2015 and 2014, respectively.Principal CustomersFour of our customers, Kaiser-Silo Energy Company, Lion Oil Trading & Transportation, Inc., Plains Marketing LP and Duke Energy Field Servicescomprised 31%, 16%, 11% and 11%, respectively, of our total revenue for the year ended December 31, 2015. No other single non-affiliated customeraccounted for 10% or more of our oil and natural gas sales in 2015. We believe the loss of any one customer would not have a material effect on our financialposition or results of operations because there are numerous potential customers for our production.Delivery CommitmentsWe have entered into two purchase and transportation agreements to deliver a fixed determinable quantity of crude oil within the Wattenberg Field.The first agreement took effect during the second quarter of 2015 for 12,580 gross barrels per day over an initial five-year term. The second agreement isanticipated to take effect during the fourth quarter of 2016 for 15,000 gross barrels per day over an initial seven-year term. The aggregate financialcommitment fee is approximately $503.7 million at December 31, 2015. While the volume commitment may be met with Company volumes or third-partyvolumes, the22 Table of ContentsCompany may be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.Productive WellsThe following table sets forth the number of producing oil and natural gas wells in which we owned a working interest at December 31, 2015. Oil(2) Natural Gas(1) Total(2) Operated(2) Gross Net Gross Net Gross Net Gross NetRocky Mountain 682 579.4 — — 682 579.4 604 565.4Mid-Continent 294 254.1 — — 294 254.1 288 254.1 Total(2) 976 833.5 — — 976 833.5 892 819.5__________________________(1)All gas production is associated gas from producing oil wells.(2)Count came from internal production reporting system.AcreageThe following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as ofDecember 31, 2015 for each of the areas where we operate along with the PV-10 values of each. Acreage related to royalty, overriding royalty and othersimilar interests is excluded from this summary. Undeveloped Developed Acres Acres Total Acres Gross Net Gross Net Gross Net PV-10Rocky Mountain 67,501 56,673 42,804 26,589 110,305 83,262 $247,811 Wattenberg Field 59,752 48,924 31,487 19,698 91,239 68,622 246,148 Other Rocky Mountain 7,749 7,749 11,317 6,891 19,066 14,640 1,663Mid-Continent 8,736 7,055 6,110 4,282 14,846 11,337 80,005 Dorcheat Macedonia Field 4,985 3,482 2,180 1,153 7,165 4,635 68,509 Other Mid-Continent 3,751 3,573 3,930 3,129 7,681 6,702 11,496 Total 76,237 63,728 48,914 30,871 125,151 94,599 $327,816Undeveloped acreageWe critically review and consider at-risk leasehold with attention to either convert term leasehold to held by production status or through termextensions primarily within the core fields of development where reserve bookings are prevalent. Decisions to expire leasehold generally reside in areas outof our core fields of development or do not pose relevant impacts to development plans or reserves in terms of net acres allowed to expire.The following table sets forth the number of net undeveloped acres as of December 31, 2015 that will expire over the next three years by area unlessproduction is established within the spacing units covering the acreage prior to the expiration dates: Expiring 2016 Expiring 2017 Expiring 2018 Gross Net Gross Net Gross NetRocky Mountain 10,954 5,897 4,523 4,090 3,481 2,645Mid-Continent 604 377 266 174 202 8 Total 11,558 6,274 4,789 4,264 3,683 2,65323 Table of ContentsDrilling ActivityThe following table describes the exploratory and development wells we drilled and completed during the years ended December 31, 2015, 2014and 2013. For the Years Ended December 31, 2015 2014 2013 Gross Net Gross Net Gross NetExploratory Productive Wells — — — — — —Dry Wells 2 1.8 — — 1 1 Total Exploratory 2 1.8 — — 1 1Development Productive Wells 92 76.1 142 124.3 117 102.7Dry Wells 2 1.4 — — — — Total Development 94 77.5 142 124.3 117 102.7Total 96 79.3 142 124.3 118 103.7The following table describes the present operated drilling activities as of December 31, 2015. As of December 31, 2015 Gross NetExploratory Rocky Mountain — —Mid-Continent — — Total Exploratory — —Development Rocky Mountain 9 7.7Mid-Continent — — Total Development 9 7.7Total 9 7.7Capital Expenditure BudgetOur anticipated capital budget for 2016 ranges from $40.0 million to $50.0 million. We plan to spend $35.0 million to $40.0 million, or 89%, of ourtotal budget in the first quarter of 2016 in the Rocky Mountain region to drill nine wells, two extended reach laterals and seven standard reach laterals, andcomplete 12 wells, four medium reach laterals and eight standard reach laterals, in the Wattenberg Field and participate in the completion of three non-operated wells. In the Mid‑Continent region, we plan to spend approximately $3.5 million during 2016 to perform approximately 38 recompletions with theremaining $1.5 million planned for corporate expenditures. Further budget guidance for the remainder of 2016 will be determined based upon the finaloutcome of our divestiture processes. Please refer to Note 3 - Assets Held for Sale in Part II, Item 8 of this Annual Report on Form 10-K, for additionaldiscussion. If commodity prices do not increase significantly or if our properties held for sale are not sold, we plan to cease drilling at the end of first quarter2016. The ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, commodity prices, assetmonetizations, the success of our drilling results as the year progresses and changes in the borrowing base under our revolving credit facility.Derivative ActivityIn addition to supply and demand, oil and gas prices are affected by seasonal, economic and geopolitical factors that we can neither control norpredict. We attempt to mitigate a portion of our price risk through the use of derivative contracts.24 Table of ContentsAs of December 31, 2015, and through the filing date of this report, we had the following economic derivatives in place, which settle monthly: Average Average Total Short Floor Floor Average Fair Market Derivative Volumes Price Price Ceiling Value ofSettlement Period Instrument (Bbls per day) (Short-Put) (Long-Put) Price AssetOil (in thousands)2016 3-Way Collar 5,500 $70.00 $85.00 $96.83 $29,566Total $29,566Currently, forward oil prices are below the average price of our short-puts associated with our three-way collars. Should monthly crude oil settlementprices occur below the strike price of our short-puts associated with the Company’s three-way collars, we will receive a payment from our hedgingcounterparty equal to the difference between the strike prices of the short-put and long-put multiplied by the monthly volume associated with the three-waycollar.We do not apply hedge accounting treatment to any commodity derivative contracts. Settlements on these contracts and adjustments to fair valueare shown as a component of derivative gain (loss) in the accompanying consolidated statements of operations and comprehensive income ("accompanyingstatements of operations"). Please refer to Note 13 - Derivatives in Part II, Item 8 of this Annual Report on Form 10-K for additional discussion on derivatives.Title to PropertiesOur properties are subject to customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for currenttaxes and other industry‑related constraints, including leasehold restrictions. We do not believe that any of these burdens materially interfere with our use ofthe properties in the operation of our business. We believe that we have satisfactory title to or rights in all of our producing properties. We undergo thoroughtitle review and receive title opinions from legal counsel before we commence drilling operations, subject to the availability and examination of accuratetitle records. Although in certain cases, title to our properties is subject to interpretation of multiple conveyances, deeds, reservations, and other constraints,we believe that none of these will materially detract from the value of our properties or from our interest therein or will materially interfere with the operationof our business.CompetitionThe oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources.Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwidebasis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling anddevelopment operations, locating and acquiring attractive producing oil and gas properties, attracting and retaining qualified personnel, and obtainingtransportation for the oil and gas we produce in certain regions. There is also competition between producers of oil and gas and other industries producingalternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulationconsidered from time to time by federal, state and local governments; however, it is not possible to predict the nature of any such legislation or regulationthat may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs ofexploring for, developing or producing gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of theserisks cannot be accurately predicted.Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 76% of ourestimated proved reserves as of December 31, 2015 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oilprices. During the year ended December 31, 2015, the daily NYMEX WTI oil spot price ranged from a high of $61.43 per Bbl to a low of $34.73 per Bbl, andthe NYMEX natural gas HH spot price ranged from a high of $3.29 per MMBtu to a low of $1.53 per MMBtu.Insurance MattersAs is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is notavailable or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financialposition, results of operations or cash flows.25 Table of ContentsRegulation of the Oil and Natural Gas IndustryOur operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and relatedoperations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operateproperties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, includingprovisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casingwells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process,and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drillingand spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, andregulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment ofproduction from fields and individual wells.Failure to comply with applicable laws and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry aresubject to the same regulatory requirements and restrictions that affect our operations. The regulatory burden on the industry can increase the cost of doingbusiness and negatively affect profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws andregulations are frequently amended through various rulemakings. Therefore, it is difficult and we are often unable to predict the future costs or impact ofcompliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states and variousmunicipalities, the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals or proceedingsmay become effective and if the outcomes will negatively affect our operations.We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existingrequirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirementsmay change, currently unforeseen incidents may occur or past non-compliance with laws or regulations may be discovered.Regulation of transportation of oilOur sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated byFERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICAand its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil andrefined products (collectively referred to as “petroleum pipelines”) be just and reasonable and non‑discriminatory and that such rates and terms andconditions of service be filed with FERC.Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and thedegree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates areequally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is ofmaterial difference from those of our competitors who are similarly situated.Regulation of transportation and sales of natural gasHistorically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federalgovernment, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas thatwe produce, as well as the revenues we receive for sales of our natural gas.In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currentlybe made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with theenactment of the Natural Gas Policy Act (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affectingwellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarilyunder the Natural Gas Act (“NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastatetransportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.26 Table of ContentsFERC issued a series of orders in 1996 and 1997 to implement its open access policies. As a result, the interstate pipelines’ traditional role aswholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an openaccess basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to fosterincreased competition within all phases of the natural gas industry.The Domenici Barton Energy Policy Act of 2005 (“EP Act of 2005”), is a comprehensive compilation of tax incentives, authorized appropriationsfor grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to beprescribed by FERC. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA andincreases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisionsare applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a ruleimplementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (1) inconnection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation more accessible to natural gasservices subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make anyuntrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act orpractice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate orother non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well asotherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERCjurisdiction, which now includes the annual reporting requirements under Order 704. The anti-market manipulation rule and enhanced civil penalty authorityreflect an expansion of FERC’s NGA enforcement authority.Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although itspolicy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency toincrease our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmentaland, in some circumstances, nondiscriminatory-take requirements. Although nondiscriminatory-take regulation has not generally been affirmatively appliedby state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe thatthe natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject toregulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services isthe subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations byFERC, the courts or Congress.Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder bythe Commodity Futures Trading Commission (“CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of anycommodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false ormisleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gastransportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofaras such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that theregulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affectour operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation ofintrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportationservice on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affectus in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.27 Table of ContentsRegulation of productionThe production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in whichwe own and operate properties have regulations governing conservation matters, including provisions for the spacing and unitization or pooling of oil andnatural gas properties, the regulation of well spacing and well density, and procedures for proper plugging and abandonment of wells. The intent of theseregulations is to promote the efficient recovery of oil and gas reserves while reducing waste and protecting correlative rights. Through collaboration withindustry through exploration and development operations these regulations effectively identify where wells can be drilled, well densities by geologicformation along with the proper spacing and pooling unit size to effectively drain the resources. Operators can apply for exceptions to such regulationsincluding applications to increase well densities to more effectively recover the oil and gas resources. Moreover, each state generally imposes a production orseverance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.We own interests in properties located onshore in two U.S. states. These states regulate drilling and operating activities by requiring, among otherthings, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the methodof drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The lawsof these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, thesize of drilling and spacing units or proration units and the density of wells that may be drilled, and the unitization and pooling of oil and gas properties.Some states have the power to prorate production to the market demand for oil and gas.Regulation of derivatives and reporting of government paymentsThe Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was passed by Congress and signed into law in July 2010.The Dodd-Frank Act is designed to provide a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent toprovide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap participants to capitaland margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption fromthese clearing and cash collateral requirements for commercial end-users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of theDodd-Frank Act, Disclosure of Payment by Resource Extraction Issuers, which would have required resource extraction issuers, such as us, to file annualreports that provide information about the type and total amount of payments made for each project related to the commercial development of oil, naturalgas, or minerals to each foreign government and the federal government. In July 2013, the U.S. District Court for the District of Columbia vacated the rule,and the SEC has announced it will not appeal the court’s decision. In December 2015, the SEC proposed revised resource extraction payments disclosurerules that if issued will be applicable to our business.Environmental, Health and Safety RegulationOur natural gas and oil exploration and production operations are subject to numerous stringent federal, regional, state and local statutes andregulations governing safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of whichcarry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of permits beforedrilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into theenvironment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling andcompletion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protectedareas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits;establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure tocomply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.The following is a summary of the more significant existing environmental and health and safety laws and regulations to which our businessoperations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.Hazardous substances and waste handlingThe Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, andcomparable state laws impose liability without regard to fault or the legality of the original conduct on28 Table of Contentscertain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include currentand prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found atthe site. Under CERCLA, these potentially “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardoussubstances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommonfor neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substancesreleased into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding ourlack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, incertain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are notaware of any liabilities for which we may be held responsible that would materially and adversely affect us.The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose requirements on the generation, handling, storage,treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes certain drilling fluids, produced waters, and other wastesassociated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However,these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws.Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastescould be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in anincrease in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financialposition. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratorywastes and waste compressor oils that are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do notbelieve that our costs in this regard are materially more burdensome than those for similarly situated companies.We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil andnatural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may havebeen disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes havebeen taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release ofhydrocarbons and wastes were not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous statelaws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners oroperators), to clean up contaminated property (including groundwater contaminated by prior owners or operators), to pay for damages for the loss orimpairment of natural resources, and to take measures to prevent future contamination from our operations.In addition, other laws require the reporting on use of hazardous and toxic chemicals. For example, in October 2015, EPA granted, in part, a petitionfiled by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases ofcertain “toxic chemicals” under the Toxic Release Inventory (“TRI”) program under the Emergency Planning and Community Right-to-Know Act. EPAdetermined that natural gas processing facilities may be appropriate for addition to TRI applicable facilities and will conduct a rulemaking process topropose such action.Pipeline safety and maintenancePipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation andstorage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the publicor the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability togovernment agencies for natural resources damages, and significant business interruption. The U.S. Department of Transportation has adopted safetyregulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. Theseregulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection andtesting of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certainqualifications and that pipeline operators develop comprehensive spill response plans.There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. The Pipeline Safety,Regulatory Certainty, and Job Creation Act was signed into law in early 2012. In addition, the29 Table of ContentsPipeline and Hazardous Materials Safety Administration (“PHMSA”) has issued new rules to strengthen federal pipeline safety enforcement programs. In2015, PHMSA proposed to expand its regulations in a number of ways, including through the increased regulation of gathering lines, even in rural areas.Air emissionsThe Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil andgas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for theconstruction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent airpermit requirements or utilize specific equipment or technologies to control emissions. Obtaining required air permits can significantly delay thedevelopment of certain oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollutioncontrol equipment or other air emissions related issues.For example, on August 16, 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmissionand storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutantsprograms. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions fromthree subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gaswells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wellsmust route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However,the “other” wells must use reduced emission completions, also known as “green completions,” with combustion devices, after January 1, 2015. Theseregulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors effectiveOctober 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2014. The EPA received numerous requests for reconsideration ofthese rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA issued revised rules in 2013 and2014 in response to some of these requests. Specifically, on September 23, 2013, the EPA published a final amendment extending the compliance dates forcertain groups of storage vessels to April 15, 2014 and April 15, 2015, and on December 31, 2014, the EPA issued a final amendment clarifying certainreduced emission completion requirements. Most recently, as part of the reconsideration, EPA proposed amendments to the NSPS rules focused on achievingadditional methane and volatile organic compound reductions from oil and natural gas operations. Among other things, EPA has proposed new requirementsfor leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic equipment, and additional control requirementsfor gathering, boosting, and compressor stations.On October 1, 2015, EPA finalized its rule lowering the existing 75 part per billion ("ppb") national ambient air quality standard ("NAAQS") forozone under the CAA to 70 ppb. Also in 2015, the State of Colorado received a bump-up in its existing ozone non-attainment status from “marginal” to“moderate.” Oil and natural gas operations in ozone nonattainment areas, including in Colorado, may be subject to increased regulatory burdens in the formof more stringent emission controls, emission offset requirements, and increased permitting delays and costs. In addition, in February 2014, the ColoradoDepartment of Public Health and Environment’s Air Quality Control Commission (“AQCC”) adopted new and revised air quality regulations that imposestringent new requirements to control emissions from existing and new oil and gas facilities in Colorado. The proposed regulations include new control,monitoring, recordkeeping, and reporting requirements on oil and gas operators in Colorado. For example, the new regulations impose Storage TankEmission Management (“STEM”) requirements for certain new and existing storage tanks. The STEM requirements require us to install costly emissioncontrol technologies as well as monitoring and recordkeeping programs at most of our new and existing well production facilities. The new Coloradoregulations also impose a Leak Detection and Repair (“LDAR”) program for well production facilities and compressor stations. The LDAR program primarilytargets hydrocarbon (i.e., methane) emissions from the oil and gas sector in Colorado and represents a significant new use of state authority regarding theseemissions.Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gasprojects and increase our costs of development and production, which costs could be significant. However, we do not currently believe that compliance withsuch requirements will have a material adverse effect on our operations.Climate changeIn response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public healthand the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of SignificantDeterioration (“PSD”) construction and Title V operating permit30 Table of Contentsrequirements for certain large stationary sources that include potential major sources of GHG emissions. In June 2014, the United States Supreme Court ruledin Utility Air Regulatory Group v. EPA, No. 12‑1146. The Supreme Court upheld part of EPA’s GHG-related regulations but struck down other portions of therules. Specifically, the Supreme Court ruled that sources subject to the PSD or Title V programs because of non-GHG emissions could still potentially besubject to certain “best available control technology” requirements applicable to their GHG emissions. Under the Court’s opinion, sources subject to the PSDor Title V programs due solely to their GHG emissions, however, can no longer be subject to EPA’s GHG permitting requirements. The D.C. Circuit issued anamendment judgment following remand, and EPA intends to conduct future rulemaking to make revisions conforming to the court rulings. EPA alsopublished a proposed rule regarding source determination, including proposals to define the term “adjacent” under the CAA in 2015, which could affect howmajor sources, including GHG major sources, are regulated. These EPA rulemakings could adversely affect our operations and restrict or delay our ability toobtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from specified onshoreand offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHGemissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliancewith applicable reporting obligations.While Congress has, from time to time, considered legislation to reduce emissions of GHGs, there has not been significant activity in the form ofadopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state andregional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require majorsources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Most recently, theEPA finalized rules to further reduce GHG emissions, primarily from coal-fired power plants, under its Clean Power Plan. If fully implemented, the CleanPower Plan could affect the demand for products we supply or otherwise affect our operations. If Congress undertakes comprehensive tax reform in thecoming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand forrefined products. President Obama has indicated that climate change and GHG regulation remains a significant priority for his second term as reflected mostrecently in the agreement reached during the December 2015 United Nations climate change conference to reduce 26-28% of United States’ GHG emissionsby 2025 against a 2005 baseline. The President also issued a Climate Action Plan in June 2013, calling for, among other things, a reduction in methaneemissions from the oil and gas industry. In January 2015, the EPA announced a comprehensive strategy intended to further reduce methane emissions fromthe oil and gas sector, which already has resulted in the proposed amendments to the 2012 NSPS noted above and may result in additional regulation.Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact ourbusiness, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from our equipment and operations couldrequire us to incur costs to reduce emissions of GHGs associated with our operations. Severe limitations on GHG emissions could adversely affect demand forthe oil and natural gas we produce.Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produceclimate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effectswere to occur, they could have an adverse effect on our exploration and production operations.Water dischargesThe Federal Water Pollution Control Act or the Clean Water Act (“CWA”) and analogous state laws impose restrictions and controls regarding thedischarge of pollutants into certain surface waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of apermit issued by the EPA or underlying state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited unlessauthorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). Obtaining permits has the potential to delay the development of natural gasand oil projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oiland other substances in certain quantities that may impose substantial potential liability for the costs of removal, remediation and damages. The EPA andCorps have issued a final rule that seeks to clarify the scope of jurisdictional waters of the United States under the CWA. The effectiveness of this rule isstayed pending the outcome of litigation. An expansive definition of such waters could affect our ability to operate in certain areas and may increase ourcosts of operations and permitting.Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or stormwater and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection withon‑site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and furtherbelieve we are in substantial31 Table of Contentscompliance with the terms thereof. As properties are acquired, we determine the need for new or updated SPCC plans and, where necessary, will develop orupdate such plans to implement physical and operation controls, the costs of which are not expected to be material.Endangered Species ActThe federal Endangered Species Act restricts activities that may affect endangered and threatened species or their habitats. A final rule amendinghow critical habitat is designated was finalized in 2016. Some of our facilities may be located in areas that are designated as habitat for endangered orthreatened species. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subjectto operating restrictions or bans in the affected areas.Employee health and safetyWe are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (the “OSH Act”), andcomparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSH Act’s hazard communication standard, the EPAcommunity right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require thatinformation be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state andlocal government authorities and citizens.Hydraulic fracturingRegulations relating to hydraulic fracturing. We are subject to extensive federal, state, and local laws and regulations concerning health, safety, andenvironmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulicfracturing specifically are receiving increasing regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process inthe completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicalsunder pressure into rock formations to stimulate hydrocarbon production.States have historically regulated oil and gas exploration and production activity, including hydraulic fracturing. State governments in the areaswhere we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certaincircumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosureof the chemicals used in fracturing. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additionalamendments in 2011 and 2013. Among other things, the updated and amended regulations require operators to reduce methane emissions associated withhydraulic fracturing, compile and report additional information regarding well bore integrity, publicly disclose the chemical ingredients used in hydraulicfracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, andimplement additional groundwater testing. In 2014, the State enacted legislation to increase the potential sanctions for statutory, regulatory and otherviolations. Among other things, this legislation and its implementing regulations mandate monetary penalties for certain types of violations, require apenalty to be assessed for each day of violation and significantly increase the maximum daily penalty amount. Most recently, Colorado adopted rulesimposing additional permitting requirements for certain large scale facilities in urban mitigation areas and additional notice requirements prior to engagingin operations near certain municipalities. Any enforcement actions or requirements of additional studies or investigations by governmental authorities wherewe operate could increase our operating costs and cause delays or interruptions of our operations.The federal Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced orused during oil and gas development. Subsurface emplacement of fluids, primarily via disposal wells or enhanced oil recovery (“EOR”) wells, is governed byfederal or state regulatory authorities that, in some cases, include the state oil and gas regulatory or the state’s environmental authority. The federal EnergyPolicy Act of 2005 amended the Underground Injection Control, provisions of the SDWA to expressly exclude certain hydraulic fracturing from thedefinition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for EOR is not excluded. The U.S.Senate and House of Representatives have considered bills to repeal this SDWA exemption for hydraulic fracturing. If enacted, hydraulic fracturingoperations could be required to meet additional federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfillmonitoring, reporting, and recordkeeping obligations, meet plugging and abandonment requirements, and provide additional public disclosure of chemicalsused in the fracturing process as a consequence of additional SDWA permitting requirements.32 Table of ContentsFederal agencies are also considering additional regulation of hydraulic fracturing. The EPA has published guidance for issuing undergroundinjection permits that would regulate hydraulic fracturing using diesel fuel. This guidance eventually could encourage other regulatory authorities to adoptpermitting and other restrictions on the use of hydraulic fracturing. In addition, on October 21, 2011, the EPA announced its intention to propose regulationsunder the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. In April 2015, EPA proposedregulations that would address discharges of wastewater pollutants from onshore unconventional extraction facilities to publicly-owned treatment works. TheEPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. The EPA issued a progress reportregarding the study in December 2012, which described generally the continuing focus of the study, but did not provide any data, findings, or conclusionsregarding the safety of hydraulic fracturing operations. In June 2015, EPA released a draft assessment of the potential impacts to drinking water resourcesfrom hydraulic fracturing. The Agency will finalize the assessment following public comment and review. The results of this study could result in additionalregulations, which could lead to operational burdens similar to those described above. The EPA also has initiated a stakeholder and potential rulemakingprocess under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing. The EPA has notindicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on avariety of issues related to the TSCA rulemaking. On January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that theEPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under EPA’s Toxics ReleaseInventory (“TRI”) program. The United States Department of the Interior also finalized a new rule regulating hydraulic fracturing activities on federal lands,including requirements for disclosure, well bore integrity and handling of flowback water. This rule has been stayed pending the outcome of ongoinglitigation. In early 2016, the Bureau of Land Management (“BLM”) proposed rules related to further controlling the venting and flaring of natural gas onBLM land. And the U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply touse of sand as a proppant for hydraulic fracturing. In addition, the Department of Labor and the Department of Justice, Environment and Natural ResourcesDivision released a Memorandum of Understanding announcing an inter-agency effort to increase the enforcement of workplace safety crimes that occur inconjunction with environmental crimes.Apart from these ongoing federal and state initiatives, local governments are adopting new requirements on hydraulic fracturing and other oil andgas operations. For example, voters in the cities of Fort Collins, Boulder and Lafayette, Colorado recently approved bans of varying lengths on hydraulicfracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collinsappealed the decisions. In 2015, the Colorado Supreme Court heard oral arguments on these appeals and a decision is expected in the first half of 2016. Inaddition, New York recently enacted a permanent moratorium on all hydraulic fracturing activities, which became final in June 2015. Any successful bans ormoratoriums where we operate could increase the costs of our operations, impact our profitability, and even prevent us from drilling in certain locations.At this time, it is not possible to estimate the potential impact on our business of recent state and local actions or the enactment of additional federalor state legislation or regulations affecting hydraulic fracturing. The adoption of future federal, state or local laws or implementing regulations imposing newenvironmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells,increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that arenot commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that anysuch outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.Our use of hydraulic fracturing. We use hydraulic fracturing as a means to maximize production of oil and gas from formations having lowpermeability such that natural flow is restricted. Fracture stimulation has been used for decades in both the Rocky Mountains and Mid-Continent. In both theRocky Mountains and the Mid-Continent, other companies in the oil and gas industry have significantly more experience than we do using hydraulicfracturing.Typical hydraulic fracturing treatments are made up of water, chemical additives and sand. We utilize major hydraulic fracturing service companieswho track and report all additive chemicals that are used in fracturing as required by the appropriate government agencies. Each of these companies fracturestimulate a multitude of wells for the industry each year. For as long as we have owned and operated properties subject to hydraulic fracturing, there have notbeen any material incidents, citations or suits related to fracturing operations or related to environmental concerns from fracturing operations.We periodically review our plans and policies regarding oil and gas operations, including hydraulic fracturing, in order to minimize any potentialenvironmental impact. We adhere to applicable legal requirements and industry practices for33 Table of Contentsgroundwater protection. Our operations are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage),who frequently inspect our fracturing operations.We strive to minimize water usage in our fracture stimulation designs. Water recovered from our hydraulic fracturing operations is disposed of in away that does not impact surface waters. We dispose of our recovered water by means of approved disposal or injection wells.National Environmental Policy ActNatural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPArequires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantlyimpact the environment. In the course of such evaluations, an agency prepares an Environmental Assessment to evaluate the potential direct, indirect andcumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that ismade available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and developmentplans, on federal lands require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has thepotential to delay or limit, or increase the cost of, the development of natural gas and oil projects. Authorizations under NEPA also are subject to protest,appeal or litigation, which can delay or halt projects.Oil Pollution ActThe Oil Pollution Act of 1990 (“OPA”) establishes strict liability for owners and operators of facilities that are the site of a release of oil into watersof the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liabilityfor damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a releasemay affect waters of the U.S. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. Whileliability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconductor resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup,liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party,including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could beincurred in connection with an oil spill.State lawsOur properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission (the “COGCC”), as well asother state agencies. The COGCC recently approved new rules regarding minimum setbacks, groundwater monitoring, large-scale facilities in urbanmitigation areas, and public notice requirements that are intended to prevent or mitigate environmental impacts of oil and gas development and include thepermitting of wells. Over the past several years, the COGCC has also approved new rules regarding various other matters, including wellbore integrity,hydraulic fracturing, well control waste management, spill reporting, and an increase in potential sanctions for COGCC rule’s violations. Depending on howthese and any other new rules are applied, they could add substantial increases in well costs for our Colorado operations. The rules could also impact ourability and extend the time necessary to obtain drilling permits, which would create substantial uncertainty about our ability to meet future drilling plans andthus production and capital expenditure targets. The State of Colorado also created a task force to make recommendations for minimizing land use and otherconflicts concerning the location of new oil and gas facilities. In February 2015, the task force concluded their deliberations and agreed upon nine consensusproposals which were sent to Governor Hickenlooper for his review. Three of the proposals require further legislative action, while the other six proposalsrequire rulemaking or other regulatory action. The proposals support (i) a senate bill that would postpone expiration of recently adopted regulations,regarding air emissions; (ii) tasking the COGCC with crafting new rules related to siting of “large-scale” pads and facilities; (iii) requiring the industry toprovide advance information about development plans to local governments; (iv) improving the COGCC’s local government liaison and designee programs;(v) adding 11 full-time staffers to the COGCC; (vi) bolstering the inspection staff and equipment for monitoring oil and gas facility air emissions and settingup a hotline for citizen health complaints at the Colorado Department of Public Health and Environment; (vii) creating a statewide oil and gas informationclearinghouse; (viii) studying ways to ameliorate the impact of oil and gas truck traffic and (ix) creating a compliance-assistance program at the COGCC tohelp operators comply with the state's changing rules and ensure consistent enforcement of rules by state inspectors. A number of additional proposals did notreceive sufficient task force support to be included with the nine consensus proposals, but may nevertheless be forwarded to the Governor as well.34 Table of ContentsIn 2015 and into 2016, COGCC began a rulemaking to implement two of these recommendations (in particular items (ii) and (iii) identified above).With respect to recommendation (ii) above, the COGCC finalized rules to permit “large-scale facilities” in “urban mitigation areas.” With respect torecommendation (iii) above, the COGCC finalized rules to require operators to provide certain municipalities with public notice prior to engaging inoperations. Both rules will become effective later this year.EmployeesAs of December 31, 2015, we employed 282 people and also utilize the services of independent contractors to perform various field and otherservices. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collectivebargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.OfficesAs of December 31, 2015, we leased 83,463 square feet of office space in Denver, Colorado at 410 17th Street where our principal offices are locatedand leased 1,635 square feet in Kersey, Colorado, where we have a field office. We also own field offices in Evans, Colorado and Magnolia, Arkansas.Available informationWe are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy anydocuments filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on theoperation of the Public Reference Room by calling the SEC at 1‑800‑SEC‑0330. Our filings with the SEC are also available to the public from commercialdocument retrieval services and at the SEC’s website at http://www.sec.gov.Our common stock is listed and traded on the New York Stock Exchange under the symbol “BCEI.” Our reports, proxy statements and otherinformation filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.We also make available on our website at http://www.bonanzacrk.com all of the documents that we file with the SEC, free of charge, as soon asreasonably practicable after we electronically file such material with the SEC. Information contained on our website, other than the documents listed below,is not incorporated by reference into this Annual Report on Form 10‑K.Item 1A. Risk Factors.Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K,actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additionalrisks not presently known to us or which we currently consider immaterial also may adversely affect us.Risks Related to Our BusinessContinuation of the recent declines, or further declines, in oil and, to a lesser extent, natural gas prices, will adversely affect our business, financialcondition or results of operations and our ability to meet our capital expenditure obligations or targets and financial commitments.The price we receive for our oil and, to a lesser extent, natural gas and NGLs, heavily influences our revenue, profitability, cash flows, liquidity,borrowing base under our revolving credit facility, access to capital, present value and quality of our reserves, the nature and scale of our operations andfuture rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changesin supply and demand. In recent years, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future.Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 76% of our estimated provedreserves as of December 31, 2015 were oil and NGLs, our financial results are more sensitive to movements in oil prices. Since mid-2014, the price of crudeoil has significantly declined. As a result, we experienced significant decreases in crude oil revenues and recorded asset impairment charges due tocommodity price declines. If commodity prices do not increase significantly or if our properties held for sale are not sold, we plan to cease drilling at the endof the first quarter 2016. A prolonged period of low market prices for oil, natural gas and NGLs, like the35 Table of Contentscurrent commodity price environment, or further declines in the market prices for oil and natural gas, will result in capital expenditures being further curtailedand will adversely affect our business, financial condition and liquidity and our ability to meet obligations, targets or financial commitments and couldultimately lead to restructuring or filing for bankruptcy, which would have a material adverse effect on our stock price and indebtedness. Additionally, loweroil, natural gas, and NGL prices may cause further decline in our stock price. During the year ended December 31, 2015, the daily NYMEX WTI oil spot priceranged from a high of $61.43 per Bbl to a low of $34.73 per Bbl and the NYMEX natural gas HH spot price ranged from a high of $3.29 per MMBtu to a lowof $1.53 per MMBtu. As of February 23, 2016, the daily NYMEX WTI oil spot price and NYMEX natural gas HH spot price was $30.07 per Bbl and $1.83 perMMBtu, respectively.The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include,but are not limited to, the following:•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 andconditions 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;•the availability of pipeline capacity and infrastructure; and•the price and availability of alternative fuels.Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices. Declines incommodity prices may have the following effects on our business:•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 topay our liabilities as they come due;•certain properties in our portfolio becoming economically unviable;•delay or postponement of some of our capital projects;•further reduction of our 2016 capital program, or significant reductions in future capital programs, resulting in a reduced ability to develop ourreserves;•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;36 Table of Contents•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; and•additional counterparty credit risk exposure on commodity hedges.We are exposed to fluctuations in the price of oil and will be affected by continuing and prolonged declines in the price of oil and natural gas.Oil and natural gas prices are volatile and the Company has a limited portion of its anticipated production hedged in 2016. As our hedges expire,more of our future production will be sold at market prices, exposing us to the fluctuations in the price of oil and natural gas, unless we enter into hedgingtransactions. To the extent that the price of oil and natural gas remains at current levels or declines further, we will not be able to hedge future production atthe same level as our current hedges and our results of operations and financial condition would be materially adversely impacted.In 2016, we have 5,500 Bbls/d of oil hedged with three-way collars with an average ceiling of $96.83/Bbl, average floor of $85.00/Bbl and averageshort floor of $70.00/Bbl. These hedges may be inadequate to protect us from continuing and prolonged declines in the price of oil and natural gas.Currently, oil and natural gas prices are trading below the average prices of our short floors associated with our three-way collars. To the extent that futuremonthly settlement prices are below our short floor prices, we will realize the settlement price plus the difference between our short floor and floor prices.Therefore, additional risk is associated with these three-way collar contracts in a declining commodity price environment relative to fixed price swaps andcollars. See the Derivative Activity section in Part I, Item I of this Annual Report on Form 10-K for a summary of our hedging activity.Due to reduced commodity prices and lower operating cash flows we may be unable to maintain adequate liquidity and our ability to make interestpayments in respect of our indebtedness could be adversely affected.Recent declines in commodity prices have caused a reduction in our available liquidity and we may not have the ability to generate sufficient cashflows from operations and, therefore, sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs. In order to increaseour liquidity to levels sufficient to meet our commitments, we are currently pursuing or considering a number of actions including (i) dispositions of non-coreassets, (ii) minimizing our capital expenditures, (iii) issuing of new debt or equity, (iv) effectively managing our working capital and (v) improving our cashflows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can beconsummated within the period needed to meet certain obligations. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds tomeet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternativemeasures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations.Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financialcondition.Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian andthe United States financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition,continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect theglobal economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitatedan economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. Ifthe economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish37 Table of Contentsfurther, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operationsand ultimately adversely impact our results of operations, liquidity and financial condition.Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to makepayment on our Senior Notes.As of December 31, 2015, we had $500.0 million of outstanding 6.75% Senior Notes due 2021 (“6.75% Senior Notes”), $300.0 million ofoutstanding 5.75% Senior Notes due 2023 (“5.75% Senior Notes” and, together with the 6.75% Senior Notes, the “Senior Notes”), $79.0 million outstandingunder our revolving credit facility and $21.3 million of cash and cash equivalents. At this time, we intend to fund our capital expenditures through our cashflow from operations and borrowings under our revolving credit facility, but continuation of the recent declines, or further declines in commodity pricescoupled with our financing needs may require us to seek additional equity, debt, or project-level financing. Our level of indebtedness could affect ouroperations in several ways, including the following:•require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available tofinance our operations and other business activities;•limit management’s discretion in operating our business and our flexibility in planning for or reacting to changes in our business and theindustry in which we operate;•increase our vulnerability to downturns and adverse developments in our business and the economy generally;•limit our ability to access capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capitalexpenditures or acquisitions or to refinance existing indebtedness;•place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in businesscombinations;•make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;•make us more vulnerable to increases in interest rates as our indebtedness under any revolving credit facility may vary with prevailing interestrates;•place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictiveterms governing their indebtedness; and•make it more difficult for us to satisfy our obligations under the Senior Notes or other debt and increase the risks that we may default on our debtobligations.Our revolving credit facility and the indentures governing the Senior Notes have restrictive covenants that could limit our growth and our ability to financeour operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.Our revolving credit facility and the indentures governing the Senior Notes contain restrictive covenants that limit our ability to engage in activitiesthat may be in our long-term best interests.Our ability to borrow under our revolving credit facility is subject to compliance with certain financial covenants, including the maintenance ofcertain financial ratios, including a minimum current ratio, a maximum leverage ratio and a minimum interest coverage ratio. As of December 31, 2015, theCompany was in compliance with all financial covenants, with a senior secured debt to EBITDAX ratio of 0.3x, an interest coverage ratio of 4.8x and acurrent ratio of 3.5x. However, continuation of low oil, natural gas and NGL prices or their further deterioration could significantly reduce cash flow, which isa critical underpinning of our required financial covenants, which could make it necessary for us to negotiate an amendment to one or more of these financialcovenants in order to avoid a default. However, there is no guarantee that we would be successful in negotiating such an amendment with our lenders.38 Table of ContentsIn addition, our revolving credit facility and the indentures governing the Senior Notes contain covenants that, among other things, limit our abilityand the ability of our restricted subsidiaries to:•incur or guarantee additional indebtedness;•issue preferred stock;•sell or transfer assets;•pay dividends on, redeem or repurchase our capital stock;•repurchase or redeem our subordinated debt;•make certain acquisitions and investments;•create or incur liens;•engage in transactions with affiliates;•create unrestricted subsidiaries;•enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;•enter into sale-leaseback transactions;•consolidate, merge or transfer all or substantially all of our assets; and•engage in certain business activities.Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all ofour indebtedness. We would not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion ofour outstanding indebtedness. As of December 31, 2015 and through the filing date of this report, we were in compliance with all financial and non-financialcovenants. There is the possibility that if we do not dispose of some assets or execute upon one or more of our other 2016 liquidity strategies, we will violateour revolving credit facility covenants by the end of 2016. If any event of default exists under the revolving credit facility, the lenders will be able toaccelerate the maturity of the loan and exercise other rights and remedies.We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictivecovenants contained in our revolving credit facility and the indentures governing the Senior Notes. Our ability to comply with the financial ratios andfinancial condition tests under our revolving credit facility may be affected by events beyond our control and, as a result, we may be unable to meet theseratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, makeneeded capital expenditures, withstand a continued downturn in commodity prices, our business or the economy in general or otherwise conduct necessarycorporate activities.A downgrade in our debt or credit ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.39 Table of ContentsOur ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned toour debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of timeor that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our creditratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, coststructure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit, increaseour borrowing costs and potentially require us to post letters of credit for certain obligations.Borrowings under our revolving credit facility are limited by our borrowing base, which is subject to periodic redetermination.The borrowing base under our revolving credit facility is redetermined at least semi-annually, and up to one additional time between scheduleddeterminations upon request of the Company or lenders holding 662/3% of the aggregate commitments. In October 2015, our borrowing base wasredetermined from $550.0 million to $475.0 million, and our next scheduled redetermination is in May 2016. Redeterminations are based upon a number offactors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjectivefactors. Given the current commodity pricing environment, we are expecting further reductions to our borrowing base. Upon a redetermination, we could berequired to repay a portion of our bank debt to the extent our outstanding borrowings at such time exceed the redetermined borrowing base. We may not havesufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans thereunder requiringus to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financialresults.Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial conditionor results of operations.Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and productionactivities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling willnot result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations orproperties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, theresults of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see Our estimatedproved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlyingassumptions will materially affect the quantities and present value of our reserves below. Our cost of drilling, completing and operating wells is oftenuncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, manyfactors, including, but not limited to, the following, may result in substantial losses, including personal injury or loss of life, penalties, damage or destructionof property and equipment, and curtailments, delays or cancellations of our scheduled drilling projects:•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, and40 Table of Contents•limitations in the market for oil and natural gas.Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimatesor underlying assumptions will materially affect the quantities and present value of our reserves.The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions,including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations orassumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See Estimated ProvedReserves under Part I, Item 1 of this Annual Report on Form 10-K for information about our estimated oil and natural gas reserves and the PV-10 (a non-GAAPfinancial measure) as of December 31, 2015, 2014 and 2013.In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze availablegeological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economicassumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, and giventhe current volatility in pricing, such assumptions are difficult to make. Although the reserve information contained herein is reviewed by independentreserve engineers, estimates of oil and natural gas reserves are inherently imprecise particularly as they relate to state-of-the-art technologies being employedsuch as the combination of hydraulic fracturing and horizontal drilling.Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oiland natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reservesshown in this Annual Report on Form 10-K and our impairment charges. In addition, we may adjust estimates of proved reserves to reflect production history,results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.There is a limited amount of production data from horizontal wells completed in the Wattenberg Field. As a result, reserve estimates associated withhorizontal wells in this Field are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same Field.Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontaldrilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been utilized by producers in this field for over 50 years. As aresult, the amount of production data from horizontal wells available to reserve engineers is relatively small. Until a greater number of horizontal wells havebeen completed in the Wattenberg Field, and a longer production history from these wells has been established, there may be a greater variance in our provedreserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories.We cannot assure you that any such variance would not be material and any such variance could have a material and adverse impact on our cash flows andresults of operations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves and are less likelyto be recovered.Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the regions where we operate.Oil and natural gas operations are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife,particularly in the Rocky Mountain region in both cases. In certain areas on federal lands, drilling and other oil and natural gas activities can only beconducted during limited times of the year. These restrictions limit our ability to operate in those areas and can potentially intensify competition for drillingrigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages orhigh costs could delay our operations and materially increase our operating and capital costs. Similarly, hot weather may adversely impact the transportationservices provided by midstream companies, and therefore our production, results of operation and cash flow.The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil andnatural gas reserves.You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil andnatural gas reserves. In accordance with SEC requirements for the years ended December 31, 2015, 2014 and 2013, we based the estimated discounted futurenet revenues from our proved reserves on the unweighted41 Table of Contentsarithmetic average of the first-day-of-the-month commodity prices (after adjustment for location and quality differentials) for the preceding twelve months,without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:•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;•the supply and demand of oil and natural gas; and•changes in governmental regulations or taxation.The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gasproperties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10%discount factor (the factor required by the SEC) used when calculating discounted future net revenues may not be the most appropriate discount factor basedon interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.Because market prices for oil at the end of 2015 were significantly lower than the average price for the year determined under SEC rules, the actualfuture prices and costs will likely differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Moreover, thelower prices at the end of 2015 may be more reflective of future economic conditions since prices have fallen further in 2016. If oil and natural gas SEC pricesdeclined by 10% then our PV-10 value as of December 31, 2015 would decrease by approximately 12% or $39.5 million. The PV-10 of our Rocky Mountainregion, primarily our Wattenberg assets, would decrease by 9.5% or $23.5 MM. Please refer to Estimated Proved Reserves under Part 1, Item 1 of this AnnualReport on Form 10-K for management’s discussion of this non-GAAP financial measure.As a result of the sustained decrease in prices for oil, natural gas and NGLs, we have taken write-downs of the carrying value of our properties and may berequired to take further write-downs if oil and natural gas prices remain depressed or decline further or if we have substantial downward adjustments toour estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverabilityof their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and thecontinuing evaluation of development plans, production data, economics and other factors, from time to time, we may be required to write-down the carryingvalue of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. Oil, natural gas and NGL prices have significantlydeclined since mid-2014 and have remained depressed into 2016. Primarily as a result of these low commodity prices, we recorded a $740.5 millionimpairment of oil and gas properties for the year ended December 31, 2015. Additionally, given the history of price volatility in the oil and natural gasmarkets, prices could remain depressed or decline further or other events may arise that would require us to record further impairments of the book valuesassociated with oil and natural gas properties. Accordingly, we may incur significant impairment charges in the future which could have a material adverseeffect on our results of operations and could reduce our earnings and stockholders’ equity for the periods in which such charges are taken.We intend to pursue the further development of our properties in the Wattenberg Field through horizontal drilling. Horizontal drilling operations can bemore operationally challenging and costly relative to our historic vertical drilling operations. Our limited operational history with drilling andcompleting horizontal wells may make us more susceptible to cost overruns and lower results.Horizontal drilling is generally more complex and more expensive on a per well basis than vertical drilling. As a result, there is greater riskassociated with a horizontal well drilling program. Risks associated with our horizontal drilling program include, but are not limited to, the following, any ofwhich could materially and adversely impact the success of our horizontal drilling program and thus, our cash flows and results of operations:•landing our well bore in the desired drilling zone;42 Table of Contents•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 well bore;•running tools and other equipment consistently through the horizontal well bore;•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.The results of our drilling in new or emerging formations, such as horizontal drilling in the Niobrara formation, are more uncertain initially thandrilling results in areas or using technologies that are more developed and have a longer history of established production. Newer or emerging formations andareas have limited or no production history, and consequently we are less able to predict future drilling results in these areas.Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profilesare established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because ofcapital constraints, lease expirations, access to gathering systems, limited takeaway capacity or depressed natural gas and oil prices, the return on ourinvestment in these areas may not be as attractive as anticipated. Further, as a result of any of these developments, we could incur material impairments of ouroil and gas properties and the value of our undeveloped acreage could decline in the future.Our ability to produce natural gas and oil economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies ofwater for our drilling operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicableenvironmental rules.The hydraulic fracture stimulation process on which we depend to produce commercial quantities of oil and natural gas requires the use and disposalof significant quantities of water. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, couldadversely impact our operations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certainoperations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with theexploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal,storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions ortermination of our operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our operations and financialcondition.The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to executeour exploration and development plans within our budget and on a timely basis.Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development andexploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effecton our business, financial condition or results of operations and may lead to reduced liquidity and the inability to pay our liabilities as they come due.Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financingon satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves or anticipated production volumes.Our exploration, development and exploitation activities are capital intensive. We make and expect to continue to make substantial capitalexpenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flows used in investingactivities, excluding derivative cash settlements, were $452.6 million, of which, $454.3 million (including $28.3 million for the acquisition of oil and gasproperties and contractual obligations for land43 Table of Contentsacquisitions) was related to capital and exploration expenditures for the year ended December 31, 2015. Our capital expenditure budget for 2016 ranges from$40.0 million to $50.0 million. If commodity prices do not increase significantly or if our properties held for sale are not sold, we plan to cease drilling at theend of the first quarter of 2016. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, amongother things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological andcompetitive developments.At this time, we intend to finance our future capital expenditures primarily through cash flows provided by operating activities and borrowingsunder our revolving credit facility. However, continuation of the recent declines, or further declines in commodity prices coupled with our financing needsmay require us to alter or increase our capitalization substantially through the issuance of additional equity securities, debt securities or the strategic sale ofassets. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal andinterest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. In addition, upon theissuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility would bereduced. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:•our proved reserves;•the amount of oil and natural gas we are able to produce from existing wells;•the prices at which our oil and natural gas are sold;•the costs of developing and producing our oil and natural gas production;•our ability to acquire, locate and produce new reserves;•the ability and willingness of our banks to lend; and•our ability to access the equity and debt capital markets.If the borrowing base under our revolving credit facility or our revenues continue to decrease as a result of lower oil or natural gas prices, operatingdifficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations. If additionalcapital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all, and we may be unable to complete the strategicsale of assets. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failureto obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to apossible expiration of our undeveloped leases and a decline in our oil and natural gas reserves, and could adversely affect our business, financial conditionand results of operations may lead to reduced liquidity and the inability to pay our liabilities as they come due.Increased costs of capital could adversely affect our business.Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in creditavailability, impacting our ability to finance our operations. Our business and operating results can be harmed by factors such as the terms and cost of capital,increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limitour access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling, render us unable to replace reservesand production and place us at a competitive disadvantage.Concentration of our operations in a few core areas may increase our risk of production loss.Our assets and operations are concentrated in two core areas: the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southernArkansas. These core areas currently provide approximately 99% of our current sales volumes and the vast majority of our development projects.Additionally, if we are able to successfully execute upon the sale of our Arkansas assets that are currently held for sale, our assets and operations will besolely concentrated in one core area in the Wattenberg Field which would further increase our risk of production loss.44 Table of ContentsThe Wattenberg and Dorcheat Macedonia Fields represent 81% and 18%, respectively, of our 2015 total sales volumes. Because our operations arenot as diversified geographically as some of our competitors, the success of our operations and our profitability may be disproportionately exposed to theeffect of any regional events, including: fluctuations in prices of crude oil, natural gas and NGLs produced from wells in the area, accidents or naturaldisasters, restrictive governmental regulations and curtailment of production or interruption in the availability of gathering, processing or transportationinfrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. For example, recent increases inactivity in the Wattenberg Field have contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, andthese adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of ourassets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect developmentactivities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case inrecent years in the Wattenberg Field, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel,which may lead to periodic shortages or delays. These constraints and the resulting shortages or high costs could delay our operations and materially increaseour operating and capital costs.We do not maintain business interruption (loss of production) insurance for our oil and gas producing properties. Loss of production or limitedaccess to reserves in either of our core operating areas could have a significant negative impact on our cash flows and profitability.We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.We do not operate all of the properties in which we have an interest. As a result, we may have a limited ability to exercise influence over normaloperating procedures, expenditures or future development of underlying properties and their associated costs. For all of the properties that are operated byothers, we are dependent on their decision-making with respect to day-to-day operations over which we have little control. The failure of an operator of wellsin which we have an interest to adequately perform operations, or an operator’s breach of applicable agreements, could reduce production and revenues wereceive from that well. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factorsoutside of our control, including the timing and amount of capital expenditures, the available expertise and financial resources, the inclusion of otherparticipants and the use of technology. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures,revenues, production and related matters.We are dependent on third party pipeline, trucking and rail systems to transport our production and, in the Wattenberg Field, gathering and processingsystems to prepare our production. These systems have limited capacity and at times have experienced service disruptions. Curtailments, disruptions orlack of availability in these systems interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect ourcash flow and results of operations.Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gasmarkets or delay our production getting to market. The marketability of our oil and natural gas and production, particularly from our wells located in theWattenberg Field, depends in part on the availability, proximity and capacity of gathering, processing, pipeline, trucking and rail systems. The amount of oiland natural gas that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled andunscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. Aportion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, maintenance,weather, field labor issues or disruptions in service. Curtailments and disruptions in these systems may last from a few days to several months. We may berequired to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. These risksare greater for us than for some of our competitors because our operations are focused on areas where there is currently a substantial amount of developmentactivity, which increases the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the resultingincreases in production. For example, in 2014 and the first half of 2015, the principal third-party provider we use in the Wattenberg Field experienced periodsof high line pressures and was forced to periodically shut down due to oxygen in the line and for other unscheduled repairs. The resulting capacityconstrained our production and reduced our revenue from the affected wells. In addition, we might voluntarily curtail production in response to marketconditions. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities orlack of availability of transport, would interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect ourcash flow and results of operations, and the expected results of our drilling program.45 Table of ContentsCurrently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara formation. Inaddition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this basin. If neither we nor a third partyconstructs the required pipeline system and processing facility, we may not be able to fully develop our resources in the North Park Basin.The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.Therefore, our undeveloped reserves may not be ultimately developed or produced.Approximately 49% of our total proved reserves were classified as proved undeveloped as of December 31, 2015. Development of these reservesmay take longer and require higher levels of capital expenditures than we currently anticipate or that may be available to us. Delays in the development ofour reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future netrevenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could causeus to have to reclassify our proved reserves as unproved reserves.Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial conditionand results of operations.In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.Our current proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless weconduct successful exploration and development activities or acquire properties containing proved reserves. Thus, our future oil and natural gas productionand, therefore, our cash flow and income are highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannotassure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we willbe able to drill productive wells at acceptable costs.According to estimates included in our December 31, 2015 proved reserve report, if, on January 1, 2016, we had ceased all drilling and development,including recompletions, refracs and workovers, then our proved developed producing reserves base would decline at an annual effective rate of 40% duringthe first year. If we fail to replace reserves through drilling, our level of production and cash flows will be affected adversely.We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not beinsured for, or our insurance may be inadequate to protect us against, these risks, including those related to our hydraulic fracturing operations.Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oiland natural gas, including, but not limited to, the possibility of:•environmental hazards, such as spills, uncontrollable flows of oil, natural gas, brine, well fluids, natural gas, hazardous air pollutants or otherpollution 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 (H2S) 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.46 Table of ContentsAny of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:•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.The presence of H2S, a toxic, flammable and colorless gas, is a common risk in the oil and gas industry and may be present in small amounts for briefperiods from time to time at our well locations. Additionally, at one of our Arkansas properties, we produce a small amount of gas from four wells where wehave identified the presence of H2S at levels that would be hazardous in the event of an uncontrolled gas release or unprotected exposure. In addition, ouroperations in Arkansas and Colorado are susceptible to damage from natural disasters such as flooding, wildfires or tornados, which involve increased risks ofpersonal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspensionof operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities couldreduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties.As is customary in the oil and gas industry, we maintain insurance against some, but not all, of these potential risks and losses. Although we believethe coverage and amounts of insurance that we carry are consistent with industry practice, we do not have insurance protection against all risks that we face,because we choose not to insure certain risks, insurance is not available at a level that balances the costs of insurance and our desired rates of return, or actuallosses exceed coverage limits. Insurance costs will likely continue to increase which could result in our determination to decrease coverage and retain morerisk to mitigate those cost increases. In addition, pollution and environmental risks generally are not fully insurable. If we incur substantial liability, and thedamages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materiallyadversely affected.Because hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, propertydamage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if the operator is unaware of thepollution event and unable to report the “occurrence” to the insurance company within the required time frame. Nor do we have coverage for gradual, long-term pollution events.Under certain circumstances, we have agreed to indemnify third parties against losses resulting from our operations. Pursuant to our surface leases,we typically indemnify the surface owner for clean-up and remediation of the site. As owner and operator of oil and gas wells and associated gatheringsystems and pipelines, we typically indemnify the drilling contractor for pollution emanating from the well, while the contractor indemnifies us againstpollution emanating from its equipment.Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.We describe some of our drilling locations and our plans to explore those drilling locations in this Annual Report on Form 10-K. Our drillinglocations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional evaluation.There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recoverdrilling or completion costs or to be economically viable. Prior to drilling, the use of 2-D and 3-D seismic technologies, various other technologies and thestudy of producing fields in the same area will not enable us to know conclusively whether oil or natural gas will be present or, if present, whether oil ornatural gas will be present in sufficient quantities to be economically viable. In addition, the use of 2-D and 3-D seismic data and other technologies requiresgreater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditureswhich may result in a reduction in our returns or increase our losses. Even if sufficient amounts of oil or natural gas exist, we may damage the potentiallyproductive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in productionfrom the well or abandonment of the well. If we drill any dry holes in our current and future drilling locations, our profitability and the value of our propertieswill likely be reduced. We cannot assure you that the analogies we47 Table of Contentsdraw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initialproduction rates reported by us or other operators may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing andoperating any well is often uncertain, and new wells may not be productive.Our potential drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter theoccurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill asubstantial portion of our potential drilling locations.Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage.These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability todrill and develop these locations is subject to a number of uncertainties, including uncertainty in the level of reserves, the availability of capital to us andother participants, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, availability of permits, costs and drilling results. Because ofthese uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil ornatural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, provedundeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore berequired to downgrade to probable or possible any proved undeveloped reserves that are not developed within this five-year time frame. These limitationsmay limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on unitscontaining the acreage.The terms of our oil and gas leases stipulate that the lease will terminate if not held by production, rentals, or production. As of the filing date of thisreport, the majority of our acreage in Arkansas was held by unitization, production, or drilling operations and therefore not subject to lease expiration. As ofthe filing date of this report, approximately 12,101 net acres of our properties in the Rocky Mountain region were not held by production. For theseproperties, if production in paying quantities is not established on units containing these leases during the next year, then approximately 5,366 net acres willexpire in 2016, approximately 4,090 net acres will expire in 2017, and approximately 2,645 net acres will expire in 2018 and thereafter. While some expiringleases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. It ispossible that market conditions at the time of negotiation could require us to agree to new leases on less favorable terms to us than the terms of the expiredleases. If our leases expire, we will lose our right to develop the related properties.We may incur losses as a result of title deficiencies.The existence of a title deficiency can diminish the value of an acquired leasehold interest and can adversely affect our results of operations andfinancial condition. Title insurance covering mineral leasehold interests is not generally available. As is industry standard, we may rely upon a landprofessional’s careful examination of public records prior to purchasing or leasing a mineral interest. Once a mineral or leasehold interest has been acquired,we typically defer the expense of obtaining further title verification by a practicing title attorney until approval to drill the related drilling block is required.We perform the necessary curative work to correct deficiencies in the marketability of the title and we have compliance and control measures to ensure anyassociated business risk is approved by the appropriate Company authority. In cases involving more serious title deficiencies, all or part of a mineral orleasehold interest may be determined to be invalid or unleased, and, as a result, the target area may be deemed to be undrillable until owners can be contactedand curative measures performed to perfect title. In other cases, title deficiencies may result in our failure to have paid royalty owners correctly. Certain titledeficiencies may also result in litigation to effectively agree or render a decision upon title ownership. Additional title issues are present in some of oursouthern Arkansas operations where significant delays in the title examination process are possible due to, among other challenges, the large volume ofinstruments contained in abstracts, poor indexing at the county clerk and recorder’s office, unrecorded conveyances, misfiling of instruments, instrumentswith missing or inadequate legal descriptions and unclear conveyance terms.Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmentaluncertainties.Acquisitions of producing properties and undeveloped properties have been an important part of our recent and historical growth. We expectacquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond ourcontrol. These factors include recoverable reserves, development potential, future48 Table of Contentscommodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherentlyuncertain. In connection with our assessments, we perform engineering, environmental, geological and geophysical reviews of the acquired properties, whichwe believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with theproperties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undevelopedacreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may existor arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, from time to time we also acquireacreage without any warranty of title except as to claims made by, through or under the transferor.When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on theacquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquiredproperties. In certain cases, we acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties.Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitionsfor which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherentrisks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. Furthermore, significant acquisitions could change the nature of our operations depending upon the character of the acquired properties, whichmay have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. Thesefactors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be requiredto finance the purchase price, and any related increase in interest expense or other related charges.The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control and there are risks inconnection with such dispositions. In addition, in certain cases, the Company may be required to retain liabilities for certain matters.We have made and continue to pursue dispositions of assets and properties, in order to increase our liquidity and to redirect our resources toward ourcore operations and for other purposes. We continue to pursue strategic asset dispositions. However, we cannot assure you that suitable dispositionopportunities will be identified in the future, or that we will be able to complete such dispositions on favorable terms. Further, we cannot assure you that ouruse of the net proceeds from such dispositions will result in improved results of operations.The successful disposition of assets and properties requires an assessment of numerous factors, some of which are beyond our control, including,without limitation:•the availability of purchasers willing to acquire interests or purchase the assets on terms and at prices acceptable to the Company;•estimated recoverable reserves;•the receipt of approvals of governmental agencies or third parties;•exploration and development potential;•future oil, natural gas, and NGL prices;•operating costs;•potential seller indemnification obligations;•the creditworthiness of the buyer; and•potential environmental and other liabilities.49 Table of ContentsSellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability or indemnificationobligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, third parties may be unwilling to release theCompany from guarantees or other credit support provided prior to the sale of the assets. As a result, the Company may remain secondarily liable for theobligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.We face various risks associated with the trend toward increased activism against oil and gas exploration and development activities.Opposition toward oil and gas drilling and development activity has been growing globally and is particularly pronounced in the United States.Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety,environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and stategovernment lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue toadvocate for increased regulations or bans on shale drilling in the United States, even in jurisdictions that are among the most stringent in their regulation ofthe industry. In fact, New York State has just enacted a permanent moratorium on all hydraulic fracturing operations, which became final in June 2015. Futureactivist efforts could result in the following:•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 hydraulicfracturing 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.We may need to incur significant costs associated with responding to these initiatives. Complying with any resulting additional legal or regulatoryrequirements that are substantial could have a material adverse effect on our business, financial condition and results of operations.Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.Our oil and natural gas exploration, production and processing operations are subject to stringent and complex federal, state and local laws andregulations governing health and safety aspects of our operations, the discharge of materials into the environment and the protection of the environment.These laws and regulations may impose on our operations numerous requirements, including the obligation to obtain a permit before conducting drilling orunderground injection activities; restrictions on the types, quantities and concentration of materials that may be released into the environment; limitations orprohibitions of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safetycriteria to protect workers; and the responsibility for cleaning up any pollution resulting from operations. Numerous governmental authorities, such as theEPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimesrequiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminalpenalties;50 Table of Contentsthe imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing some or all of our operations; delays in grantingpermits, or even the cancellation of leases.There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may bematerial, due to our handling of petroleum hydrocarbons and wastes, our emissions into air and water, the underground injection or other disposal of ourwastes, the use and disposition of hydraulic fracturing fluids, and historical industry operations and waste disposal practices. Under certain environmentallaws and regulations, we may be liable for the full cost of removing or remediating contamination, regardless of whether we were at fault, and even whenmultiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releaseson our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Asidefrom government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes aretaken for reclamation or disposal, and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, collectpenalties for violations, or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that historic contamination has migrated from those sites to ours. Changes inenvironmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, emission, waste managementor cleanup requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effecton our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additionaloperating restrictions or delays.We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Governmentalauthorities frequently add to those requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasingregulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells inlow-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulatehydrocarbon production.In August 2012, the EPA issued final New Source Performance Standards (known as “Quad O”) that establish new air emission controls for naturalgas processing operations, as well as for oil and natural gas production. Among other things, Quad O imposes reduced emission completion (or “greencompletion”) requirements and also imposes stringent control and other standards on certain storage tanks, compressors and associated equipment. Afterseveral parties challenged the Quad O regulations in court, the EPA administratively reconsidered certain requirements. As a result of such administrativereconsideration, the EPA issued final amendments to the Quad O regulations in September 2013 and December 2014. In 2015, as part of this reconsideration,EPA proposed updates and amendments to Quad O focused on achieving additional reductions in methane and volatile organic compound emissions at oiland natural gas operations. These newly proposed rules, among other things, would require leak detection and repair, additional control requirements forpneumatic controllers and pumps, and additional control requirements for oil well completions, gathering, boosting, and compressor stations. At this point,we cannot predict the final regulatory requirements or the cost to comply with such air regulatory requirements.On December 17, 2014, the EPA proposed to revise and lower the existing 75 ppb NAAQS for ozone under the federal Clean Air Act to a rangewithin 65-70 ppb. On October 1, 2015, EPA finalized a rule lowering the standard to 70 ppb. This lowered ozone NAAQS could result in an expansion ofozone nonattainment areas across the United States, including areas in which we operate. In a related development, in 2015 the State of Colorado received abump-up to its existing ozone non-attainment status from “marginal” to “moderate.” This increased status will result in additional requirements under theCAA for the State of Colorado and will include a state rulemaking to implement such requirements. Oil and natural gas operations in ozone nonattainmentareas may be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permittingdelays and costs.In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission finalized regulations imposingstrict new requirements relating to air emissions from oil and gas facilities in Colorado that are even more stringent than comparable federal rules. These newColorado rules include storage tank control, monitoring, recordkeeping and reporting requirements as well as leak detection and repair requirements for bothwell production facilities and compressor stations and associated equipment. These new requirements, which represent the first time a state has directlyregulated methane (a greenhouse gas) emissions from the upstream oil and gas sector, have and will continue to impose additional costs on our operations.51 Table of ContentsSome activists have attempted to link hydraulic fracturing to various environmental problems, including potential adverse effects to drinking watersupplies as well as migration of methane and other hydrocarbons. As a result, the federal government is studying the environmental risks associated withhydraulic fracturing and evaluating whether to adopt additional regulatory requirements. For example, the EPA has commenced a multi-year study of thepotential impacts of hydraulic fracturing on drinking water resources. A draft assessment was published for public comment in 2015. The assessmentconcludes that while there are mechanisms by which hydraulic fracturing can impact drinking water resources, there was no evidence that these mechanismshave led to widespread, systemic impacts on drinking water resources in the United States. EPA’s science advisory board, however, has subsequentlyquestioned several elements and conclusions in EPA’s draft assessment. In addition, in 2011, the EPA announced its intention to propose regulations underthe federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. EPA published these proposed rulesin early 2015. The EPA also has issued guidance for issuing underground injection permits for hydraulic fracturing operations that use diesel fuel under theagency’s Safe Drinking Water Act (“SDWA”) authority. This guidance could encourage other regulatory authorities to adopt more stringent to permitting andother restrictions on the use of hydraulic fracturing. Moreover, the U.S. Department of the Interior finalized new rules for hydraulic fracturing activities onfederal lands that, in general, would cover disclosure of fracturing fluid components, well bore integrity, and handling of flowback water. The rule, whilefinal, has been stayed pending the outcome of ongoing litigation. The BLM also proposed rules to address venting and flaring on BLM land and the U.S.Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppantfor hydraulic fracturing.In the United States Congress, bills have been introduced that would amend the SDWA to eliminate an existing exemption for certain hydraulicfracturing activities from the definition of “underground injection,” thereby requiring the oil and natural gas industry to obtain SDWA permits for fracturingnot involving diesel fuels, and to require disclosure of the chemicals used in the process. If adopted, such legislation could establish an additional level ofregulation and permitting at the federal level, but some form of chemical disclosure is already required by most oil and gas producing states. At this time, it isnot clear what action, if any, the United States Congress will take on hydraulic fracturing.Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturingand other aspects of oil and gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significantadditional amendments in 2011, 2014 and 2015. Among other things, the updated and amended regulations require operators to reduce methane emissionsassociated with hydraulic fracturing, compile and report additional information regarding well bore integrity, publicly disclose the chemical ingredients usedin hydraulic fracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearbyresidents, implement additional groundwater testing and incur increased monetary penalties for violations of the State’s oil and gas conservation commissionrules and regulations. Similarly, in February 2015, a task force created by the State of Colorado aimed at making recommendations for minimizing land useand other conflicts concerning the location of new oil and gas facilities agreed upon nine consensus proposals which were sent to Governor Hickenlooper forhis review. Three of the proposals require further legislative action, while the other six proposals require rulemaking or other regulatory action. Theproposals support (i) a senate bill that would postpone expiration of recently adopted regulations regarding air emissions; (ii) tasking the COGCC withcrafting new rules related to siting of “large-scale” pads and facilities; (iii) requiring the industry to provide advance information about development plans tolocal governments; (iv) improving the COGCC’s local government liaison and designee programs; (v) adding 11 full-time staffers to the COGCC to improveinspections and field operations; (vi) bolstering the inspection staff and equipment for monitoring oil and gas facility air emissions and setting up a hotlinefor citizen health complaints at the Colorado Department of Public Health and Environment; (vii) creating a statewide oil and gas information clearinghouse;(viii) studying ways to ameliorate the impact of oil and gas truck traffic and (ix) creating a compliance-assistance program at the COGCC to help operatorscomply with the state's changing rules and ensure consistent enforcement of rules by state inspectors. A number of additional proposals did not receivesufficient task force support to be included with the nine consensus proposals, but may nevertheless be forwarded to the Governor as well. In early 2016,COGCC finalized a rulemaking to implement two of the nine recommendations noted above (numbers (ii) and (iii) specifically). With regard torecommendation (ii), the COGCC finalized rules applicable to the permitting of large-scale facilities in urban mitigation areas. For recommendation (iii), theCOGCC finalized rules requiring operators to provide certain municipalities with notice prior to engaging in certain operations. If we are able to successfullyexecute upon the sale of our Arkansas assets that are currently held for sale, our assets and operations will be solely concentrated in one core area in theWattenberg Field which will further increase the regulatory risks associated with our operations.In some instances certain local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Some countiesin Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governmentshave entered memoranda of agreement with oil and gas producers to accomplish the same objective. Voters in the cities of Fort Collins, Boulder andLafayette, Colorado recently approved bans52 Table of Contentsof varying length on hydraulic fracturing within their respective city limits. The bans in Longmont, Lafayette and Fort Collins were overturned by localdistrict courts; the Boulder and Broomfield bans remain in place and the Boulder County moratorium was recently extended until 2018. In 2015, theColorado Supreme Court heard oral argument on appeal from the district and appellate courts and a decision is expected in the first half of 2016. While theseinitiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for statewidereferendums, especially in Colorado. For example, in December 2015, interests groups in Colorado filed 11 potential ballot initiatives focusing on restrictingor prohibiting oil and gas development in the state, and the State of New York recently placed a permanent moratorium on all hydraulic fracturing operationswithin that state.The adoption of future federal, state or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting,our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business,delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing),or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be material, and any suchoutcome could have a material adverse impact on our cash flows and results of operations.Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oiland natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs inpreparing for or responding to those effects.There is a growing belief that human-caused (anthropogenic) emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climatechange and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, includingnegatively impacting the costs we incur in providing our products and services and the demand for and consumption of our products and services (due topotential changes in both costs and weather patterns).In December 2009, the EPA determined that atmospheric concentrations of carbon dioxide, methane and certain other GHGs present anendangerment to public health and welfare, because such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and otherclimatic changes. Consistent with its findings, the EPA has proposed or adopted various regulations under the Clean Air Act to address GHGs. Among otherthings, the EPA began limiting emissions of GHGs from new cars and light duty trucks beginning with the 2012 model year. In addition, in 2010 the EPApublished a final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” andTitle V permitting programs. Under this rule, the EPA imposed certain GHG permitting requirements on the largest major sources first. As noted above, inJune 2014, the United States Supreme Court invalidated part of the EPA’s stationary source GHG program in Utility Air Regulatory Group v. EPA, No. 12-1146. Specifically, the Supreme Court ruled that major sources subject to the PSD or Title V programs because of non-GHG emissions could potentially bestill subject to certain “best available control technology” requirements applicable to their GHG emissions. Under the Supreme Court’s opinion, sourcessubject to the PSD or Title V programs due solely to their GHG emissions can no longer be subject to the EPA’s GHG permitting requirements. The D.C.Circuit issued an amended judgment following remand, and the EPA intends to conduct future rulemaking to revise its GHG major stationary sourcepermitting program to conform to the court rulings. In a related development, the EPA proposed a rule to further define “adjacency” under the CAA forpurposes of determining and permitting major stationary sources, including GHG major sources.The EPA also adopted regulations requiring the reporting of GHG emissions from specific categories of higher GHG emitting sources in the UnitedStates, including certain oil and natural gas production facilities, which include certain of our operations, beginning in 2012 for emissions occurring in 2011.Information in such report may form the basis for further GHG regulation. Further, the EPA has continued with its comprehensive strategy for further reducingmethane emissions from oil and gas operations, with a proposed rule being issued as part of the 2012 Quad O reconsideration, in 2015 known as “Quad Oa.”Final rules are expected in in 2016. The EPA’s GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for newor modified facilities.Moreover, Congress has from time to time considered adopting legislation to reduce emissions of GHGs or promote the use of renewable fuels. As analternative, some proponents of GHG controls have advocated mandating a national “clean energy” standard. In 2011, for example, President Obamaencouraged Congress to adopt a goal of generating 80% of U.S. electricity from “clean energy” by 2035 with credit for renewable and nuclear power andpartial credit for clean coal and “efficient natural gas.” In the absence of such a comprehensive federal legislative program expressly addressing GHGs, theEPA recently finalized rules for both new and existing power plants known as the “Clean Power Plan” designed to decrease GHG emissions from thesesources. We are unable to predict how, or if, the Clean Power Plan will affect our operations. In53 Table of Contentsaddition, the United States reached agreement during the December 2015 United Nations climate change conference to reduce its GHG emissions by 26-28%by 2025 compared with 2005 levels, and also to provide periodic updates on its progress.In the meantime, many states already have taken such measures, which have included renewable energy standards, development of GHG emissioninventories or cap and trade programs. Cap and trade programs typically work by requiring major sources of emissions or major producers of fuels to acquireand surrender emission allowances, with the number of available allowances reduced each year until the overall GHG emission reduction goal is achieved.These allowances would be expected to escalate significantly in cost over time.The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs topurchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. If we are unable torecover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have amaterial adverse effect on our results of operations and financial condition. Any such legislation or regulatory programs could also increase the cost ofconsuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions ofGHGs could have an adverse effect on our business, financial condition and results of operations.Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produceclimate changes that have significant physical effects, such as increased frequency and severity of storms and floods. If any such effects were to occur, theycould have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effecton our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies orsuppliers with whom we have a business relationship, including compromises to the cost or availability of water or other components necessary to ouroperations. Our insurance may not cover some or any of the damages, losses, or costs that may result from potential physical effects of climate change.Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and securetrained personnel.Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend heavily on our financial resources andability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oiland natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and naturalgas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies maybe able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greaternumber of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstandunsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, andmay be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. Inaddition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be ableto compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining qualitypersonnel and raising additional capital, which could have a material adverse effect on our business.If we fail to retain our existing senior management or technical personnel or attract qualified new personnel, such failure could adversely affect ouroperations. The volatility in commodity prices and business performance may affect our ability to retain senior management and the loss of these keyemployees may affect our business, financial condition and results of operations.To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management,technical personnel, or any of the vice presidents of the Company, could have a material adverse effect on our operations or strategy. The volatility incommodity prices and our business performance may affect our ability to incentivize and retain senior management or key employees. Furthermore,competition for experienced senior management, technical and other professional personnel remains strong. If we cannot retain our current personnel orattract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss oftechnical expertise. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.54 Table of ContentsOur derivative activities could result in financial losses or could reduce our income.To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and mayin the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have notdesignated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value.Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result ofchanges in the fair value of our derivative instruments.Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:•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.In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and mayexpose us to cash margin requirements.We are exposed to credit risks of our hedging counterparties, third parties participating in our wells and our customers.Our principal exposures to credit risk are through receivables resulting from commodity derivatives instruments in the amount of $29.6 million atDecember 31, 2015, joint interest and other receivables of $31.2 million at December 31, 2015 and the sale of our oil, natural gas and NGLs production of$25.3 million in receivables at December 31, 2015, which we market to energy marketing companies, refineries and affiliates.Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarilybased on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells.We are also subject to credit risk due to concentration of our oil, natural gas and NGLs receivables with significant customers. This concentration ofcustomers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year endedDecember 31, 2015, sales to Kaiser-Silo Energy Company, Lion Oil Trading & Transport, Inc., Plains Marketing LP, and Duke Energy Field Servicesaccounted for approximately 31%, 16%, 11% and 11%, respectively, of our total sales.We are exposed to credit risk in the event of default of our counterparty, principally with respect to hedging agreements but also insurance contracts andbank lending commitments. We do not require most of our customers to post collateral. The inability or failure of our significant customers to meet theirobligations to us or their insolvency or liquidation may adversely affect our financial results. Deterioration in the credit markets may impact the creditratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into futuretransactions with us.Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect ofcommodity price, interest rate and other risks associated with our business.The Dodd-Frank Act establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entitiesthat participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements.The Dodd-Frank Act may require us to comply with margin requirements in our derivative activities, although the application of those provisions to us isuncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivativesactivities to separate entities, which may not be as creditworthy as the current counterparties.The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to postcollateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives toprotect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to lesscreditworthy counterparties. If we reduce our55 Table of Contentsuse of derivative as a result of the Dodd-Frank Act and regulations, our results of operations may be more volatile and our cash flows may be less predictable,which could adversely affect our ability to plan for and fund capital expenditures.We may be involved in legal proceedings that may result in substantial liabilities.Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractualdisputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings areinherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legalcosts, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could resultin liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially andadversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments andestimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could bematerial.We are subject to federal, state, and local taxes, and may become subject to new taxes and certain federal income tax deductions currently available withrespect to oil and gas exploration and development may be eliminated as a result of future legislation.The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell, and, for many ofour wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxesassociated with the extraction of hydrocarbons and additional increases may occur. In addition, there has been a significant amount of discussion bylegislators and presidential administrations concerning a variety of energy tax proposals.There have been proposals for legislative changes that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currentlyavailable to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletionallowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of thededuction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It isunclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. Any such changes in U.S.federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas explorationand development, and any such change could negatively affect our financial condition, results of operations and cash flow.Changes to federal tax deductions, as well as any changes to or the imposition of new state or local taxes (including production, severance or similartaxes) could negatively affect our financial condition and results of operations.We may not be able to keep pace with technological developments in our industry.The oil and gas industry is characterized by rapid and significant technological advancements. As our competitors, some of whom have greaterresources than us, use or develop new technologies, we may be placed at a competitive disadvantage. We may not be able to respond to these competitivepressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were tobecome obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results ofoperations could be materially adversely affected.We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption or financialloss.The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production,processing and distribution activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipmentand gathering and transportation systems, conduct reservoir modeling and reserves estimation and process and record financial and operating data. Pipelines,refineries, power stations and distribution points for both fuels and electricity are becoming more interconnected by computer systems. At the same time,cyber incidents, including deliberate attacks or unintentional events, have increased. Our technologies, systems, networks and those of our vendors, suppliersand other business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering,monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, weaknesses in thecyber security of our vendors,56 Table of Contentssuppliers, and other business partners could facilitate an attack on our technologies, systems and networks. In addition, certain cyber incidents, such assurveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated byits opponents, our technologies, systems and networks may be of particular interest to certain groups with political agendas, which may seek to launch cyber-attacks as a method of promoting their message. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient.We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to processand record financial and operating data, communicate with our employees and business parties, analyze seismic and drilling information, estimate quantitiesof oil and gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of ourproduction and financial institutions, are also dependent on digital technology. The technologies needed to conduct our oil and gas exploration anddevelopment activities make certain information the target of theft or misappropriation.Although to date we have not experienced any material losses relating to cyber-attacks, we may suffer such losses in the future. We may be requiredto expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information securityvulnerabilities.Risks Relating to our Common StockWe do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, our stockholders’ onlyopportunity to achieve a return on their investment is if the price of our stock appreciates.We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from makingany cash dividends pursuant to the terms of our revolving credit facility and our Senior Notes. Consequently, our stockholders’ only opportunity to achieve areturn on their investment in us will be if the market price of our common stock appreciates, which may not occur, and the stockholders sell their shares at aprofit. There is no guarantee that the price of our common stock will ever exceed the price that the stockholders paid.We have experienced recent volatility in the market price and trading volume of our common stock and may continue to do so in the future.The trading price of shares of our common stock has fluctuated widely and in the future may be subject to similar fluctuations. As an example,during the year ended December 31, 2015, the sales price of our common stock ranged from a low of $3.72 per share to a high of $30.81 per share. The tradingprice of our common stock may be affected by a number of factors, including the volatility of oil, natural gas, and NGL prices, our operating results, changesin our earnings estimates, additions or departures of key personnel, our financial condition and liquidity, drilling activities, legislative and regulatorychanges, general conditions in the oil and natural gas exploration and development industry, general economic conditions, and general conditions in thesecurities markets. In particular, a significant or extended decline in oil, natural gas and NGL prices could have a material adverse effect our sales price of ourcommon stock. Other risks described in this annual report could also materially and adversely affect our share price.Although our common stock is listed on the New York Stock Exchange, we cannot assure you that an active public market will continue for ourcommon stock or that will be able to continue to meet the listing requirements of the NYSE. If an active public market for our common stock does notcontinue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or "float" for ourstock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stockwould be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile.In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us.Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity orconvertible securities may dilute our current stockholders’ ownership in us.If our existing stockholders sell a large number of shares of our common stock in the public market, the market price of our common stock coulddecline significantly. In addition, the perception in the public market that our existing stockholders might sell shares of common stock could depress themarket price of our common stock, regardless of the actual plans of our existing stockholders. Her Majesty the Queen in Right of Alberta, in her own capacityand as trustee/nominee for certain Alberta pension clients (“HMQ”), owns 7,587,859 shares, or approximately 15% of our total outstanding shares. HMQ isparty to a registration rights agreement with us (the “HMQ Registration Rights Agreement”). Pursuant to the HMQ Registration57 Table of ContentsRights Agreement, we have agreed to effect the registration of shares held by HMQ if it so requests or if we conduct other registrations of our common stock.In addition, we may issue additional shares of our common stock, including securities that are convertible into or exchangeable for, or that represent the rightto receive, shares of common stock or substantially similar securities, which may result in dilution to our stockholders. In addition, our stockholders may befurther diluted by future issuances under our equity incentive plans.Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, evenif such acquisition or merger may be in our stockholders’ best interests.Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directorselects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation andbylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:•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 ofstockholders; and•limitations on the ability of our stockholders to call special meetings or act by written consent.Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder whobeneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unlessvarious conditions are met, such as approval of the transaction by our board of directors.Alberta Investment Management Corporation (“AIMCo”) may be deemed to beneficially own or control a significant portion of our common stock, givingthem influence over corporate transactions and other matters. Their interests and the interests of the parties on whose behalf they invest may conflict withour other stockholders, and the concentration of ownership of our common stock by such stockholders will limit the influence of other public stockholders.AIMCo, a Canadian corporation and investment manager to HMQ and certain Alberta pension funds, may be deemed to beneficially own or controlapproximately 15% of our outstanding common stock. West Face Capital and AIMCo, on behalf of HMQ and certain Alberta pension funds, have enteredinto an investment management agreement pursuant to which West Face Capital has the right to vote the shares of our common stock held by HMQ.Accordingly, West Face may exert influence over our board of directors and the outcome of stockholder votes. Even if the investment management agreementbetween West Face Capital and AIMCo were to be terminated, AIMCo, on behalf of HMQ, would have the ability to exert influence over the Company. Otherthan the HMQ Registration Rights Agreement, there are no contractual relationships or other understanding between the Company and HMQ or AIMCo.A concentration of beneficial ownership in AIMCo's clients would allow such stockholders to influence, directly or indirectly and subject toapplicable law, significant matters affecting us, including the following:•establishment of business strategy and policies;•amendment of our certificate of incorporation or bylaws;•nomination and election of directors;•appointment and removal of officers;•our capital structure; and•compensation of directors, officers and employees and other employee-related matters.Such a concentration of ownership may have the effect of delaying, deterring or preventing a change in control, a merger, consolidation, takeover orother business combination, and could discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, whichcould in turn have an adverse effect on the market price of our58 Table of Contentscommon stock. The significant ownership interest of HMQ could also adversely affect investors' perceptions of our corporate governance.Item 1B. Unresolved Staff Comments.None.Item 2. Properties.The information required by Item 2. is contained in Item 1. Business and is incorporated herein by reference.Item 3. Legal Proceedings.From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers andmarketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulationsgoverning air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no materialpending or overtly threatened legal actions against us that of which we are aware.Item 4. Mine Safety Disclosures.Not applicable.PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.Market for Registrant’s Common Equity. Our common stock is listed on the NYSE under the symbol “BCEI”. On February 22, 2016, the sale price ofour common stock, as reported on the NYSE, was $1.75 per share.The following table sets forth the high and low intra-day sales prices per share of our common stock as reported on the NYSE. High Low2014 1st Quarter $52.47 $37.712nd Quarter 62.94 41.083rd Quarter 62.89 53.754th Quarter 57.12 16.362015 1st Quarter $30.81 $20.232nd Quarter 30.69 17.353rd Quarter 18.18 3.934th Quarter 9.54 3.72Holders. As of February 22, 2016, there were approximately 262 registered holders of our common stock.Dividends. We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility and the indenturesgoverning our Senior Notes restrict the payment of cash dividends on our common stock. We currently intend to retain all future earnings for thedevelopment and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeablefuture.Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the quarter andyear ended December 31, 2015.59 Table of Contents 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 ProgramsJanuary 1, 2015 - March 31, 201571,802 $26.25 April 1, 2015 - June 30, 201511,237 $26.60 July 1, 2015 - September 30, 201514,236 $7.93 October 1, 2015 - October 31, 20152,510 $6.82 — —November 1, 2015 - November 30, 20155,795 $7.77 — —December 1, 2015 - December 31, 20152,490 $6.10 — —Total108,070 $21.94 — —_________________________(1)Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations uponthe vesting of restricted stock awards. These repurchases were not part of a publicly announced plan or program to repurchase shares of our commonstock, nor do we have a publicly announced plan or program to repurchase shares of our common stock.Sale of Unregistered Securities. We had no sales of unregistered securities during the quarter ended December 31, 2015.Stock Performance Graph. The following performance graph shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Actof 1934, as amended (the “Exchange Act”), or otherwise subject to liabilities under that section and shall not be deemed to be incorporated by reference intoany filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.The following graph compares the cumulative total stockholder return for the Company’s common stock, the Standard and Poor’s 500 Stock Index(the “S&P 500 Index”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P O&G E&P Index”). The measurement points in thegraph below are December 14, 2011 (the first trading day of our common stock on the NYSE) and each fiscal quarter thereafter through December 31, 2015.The graph assumes that $100 was invested on December 14, 2011 in each of the common stock of the Company, the S&P 500 Index and the S&P O&G E&PIndex and assumes reinvestment of any dividends. The stock price performance on the following graph is not necessarily indicative of future stock priceperformance.60 Table of ContentsItem 6. Selected Financial Data.The selected historical financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition andResults of Operations below and financial statements and the notes to those financial statements in Part I, Item 8 of this Annual Report on Form 10-K.The following tables set forth selected historical financial data of the Company as of and for the period indicated. For the Years Ended December 31, 2011 2012 2013 2014 2015 (in thousands, except per share amounts)Statement of Operations Data: Total operating net revenues (1) $105,724 $231,205 $421,860 $558,633 $292,679Income (loss) from operations (1) 34,425 77,903 146,995 (47,506) (907,444)Net income (loss) 12,691 46,523 69,184 20,283 (745,547)Basic net income (loss) per common share $0.43 $1.17 $1.72 $0.50 $(15.57) Basic weighted-average common shares outstanding 29,324 39,052 39,337 40,139 47,874Diluted net income (loss) per common share $0.43 $1.17 $1.71 $0.49 $(15.57) Diluted weighted-average common shares outstanding 29,324 39,052 39,403 40,290 47,874Balance Sheet Data: Cash and cash equivalents $2,090 $4,268 $180,582 $2,584 $21,341Property and equipment, net (excludes assets held for sale) 618,229 943,175 1,267,249 1,756,477 922,344Oil and gas properties held for sale, net of accumulated depreciation,depletion, and amortization 9,896 582 360 — 214,922Total assets 664,349 1,002,490 1,545,935 2,006,089 1,273,367Long-term debt Credit facility 6,600 158,000 — 33,000 79,000 Senior Notes, net of unamortized premium — — 508,847 807,619 806,392 Total stockholders’ equity $527,982 $578,518 $656,028 $740,071 $209,407Selected Cash Flow Data: Net cash provided by operating activities $60,627 $157,636 $307,015 $327,720 $95,027Net cash used in investing activities (161,926) (305,277) (465,223) (824,994) (321,577)Net cash provided by financing activities $103,389 $149,819 $334,522 $319,276 $245,307Sales Volumes: Oil (MBbls) 887.4 2,191.0 3,887.2 5,618.7 6,072.3Natural gas (MMcf) 2,773.1 5,473.2 9,975.9 15,395.8 14,551.1Natural gas liquids (MBbls) 183.8 284.7 352.8 396.3 1,821.9Estimated Proved Reserves: Oil (MMBbls) 24.6 30.2 43.6 54.7 57.4Natural gas (Bcf) 93.0 118.5 139.6 188.6 144.2Natural gas liquids (MMBbls) 3.6 3.1 2.9 3.4 19.9Total proved reserves (MMBoe) 43.7 53.0 69.8 89.5 101.3Average Sales Price (before derivatives): Oil (MBbls) $89.67 $89.08 $91.84 $81.95 $40.98Natural gas (MMcf) $4.85 $3.62 $4.66 $5.11 $1.82Natural gas liquids (MBbls) $67.23 $55.54 $51.74 $49.14 $9.49Average Sales Price (after derivatives): Oil (MBbls) $85.51 $88.40 $88.82 $84.00 $62.10Natural gas (MMcf) $5.09 $3.76 $4.70 $5.16 $2.01Natural gas liquids (MBbls) $67.23 $55.54 $51.74 $49.14 $9.49Expense per BOE: Lease operating $11.90 $9.06 $8.09 $8.44 $7.40Severance and ad valorem taxes $3.86 $4.04 $4.61 $5.88 $1.81Depreciation, depletion, and amortization $18.27 $19.54 $23.75 $26.66 $23.73General and administrative $11.49 $9.27 $9.40 $9.51 $6.81______________________(1)Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or heldfor sale as of December 31, 2014, 2013 and 2012.61 Table of ContentsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Executive Summary We are a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the UnitedStates. Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southernArkansas.Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operatedsales 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. Thecontract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified toconform to the current presentation given the prospective nature of the agreements. The NGL volumes identified by the Company’s gas purchasers areconverted to an oil equivalent. The Company believes that this conversion will more accurately convey its production and sales volumes and will allowresults to be more comparable with those of our peers. This revision will increase reserves volumes, sales volumes and the percentage of sales volumes thatrelate to NGLs. Financial and Operating Highlights Our 2015 financial and operational results, some of which were impacted by depressed oil, natural gas and NGL prices, include:•Total liquidity of $405.3 million at December 31, 2015, consisting of year-end cash balance plus funds available under our revolving credit facility,as compared with $545.6 million at December 31, 2014. Please refer to Liquidity and Capital Resources below for additional discussion;•Cash operating costs, which consist of lease operating expense, severance and ad valorem taxes, and the cash portion of general and administrativeexpense, per barrel decreased by $6.80 per Boe to $14.61 per Boe from $21.41 per Boe in 2014; •Rocky Mountain region drilling and completion costs decreased 29% from 2014 for standard reach lateral wells;•Lease operating expense per Boe was down 12% from 2014 due to stricter cost controls across all areas and the Company's decision to temporarilyshut down the McKamie Patton Plant in the Mid-Continent region;•Cash flows provided by operating activities of $95.0 million, as compared with $327.7 million in 2014. Please refer to Liquidity and CapitalResources below for additional discussion;•Full year capital expenditures were $16.0 million lower than our mid-year guidance of $420.0 million;•Net loss of $745.5 million, as compared with $20.3 million net income (including $17.0 million from continuing operations) for 2014;•Impairment of oil and gas properties of $740.5 million due to depressed commodity prices; •Increased sales volumes by 20% to 10.3 MMBoe in 2015 from 8.6 MMBoe in 2014, with oil and NGL production representing 76% of total salesvolumes. Sales volumes exclude discontinued operations. Please refer to the caption Results of Operations below for additional discussion;•Increased proved reserves to 101.3 MMBoe as of December 31, 2015, an increase of 13% from December 31, 2014;•Increased proved developed producing reserves to 49.7 MMBoe as of December 31, 2015, an increase of 20% from December 31, 2014;•Increased proved developed producing reserves for the Wattenberg Field to 38.5 MMBoe as of December 31, 2015, an increase of 26% fromDecember 31, 2014;62 Table of Contents•Fourth quarter 2015 sales volumes of 28.6 MBoe/d exceeded guidance range of 27.5 - 28.1 MBoe/d due to strong base production performance fromconsistent midstream run times;•Drilled 84 and completed 95 gross wells within our Rocky Mountain region and drilled 24 and completed 21 gross wells within our Mid-Continentregion during 2015;•Executed upon PUD conversions at a rate of 16%;•During 2015, the Company, along with a third-party midstream entity, completed pipeline infrastructure that allowed for connectivity in our eastand west legacy acreage in the Wattenberg Field relieving line pressure constraints and allowing more flexibility; and•We are re-marketing our Rocky Mountain Infrastructure, LLC ("RMI") assets as we have terminated the previously announced purchase agreement. Business Strategies and Outlook for 2016Beginning in 2014, the oil and natural gas industry began to experience a sharp decline in commodity prices. Caused in part by global supply anddemand imbalances and an oversupply of natural gas in the United States, the pricing declines have extended into 2016 and the timing of any rebound isuncertain. Low commodity prices resulted in a reduction of our revenues, profitability, cash flows and proved reserve values, impairments, and reductions inour stock price. If the industry downturn continues for an extended period or becomes more severe, we could experience additional impairments and furthermaterial reductions in revenues, profitability, cash flows, proved reserves and declines in our stock price.Despite the current depressed commodity pricing environment, we are committed to preserving stockholder value by maximizing the cash flowsfrom our existing production, optimizing the Company’s liquidity position and positioning existing leasehold for increased development activity whenappropriate commodity price signals are observed.•2016 Liquidity. We are considering various strategies to reinforce our balance sheet and improve our liquidity. These strategies include potentialasset sales and joint ventures or other arrangements that would enable us to support development of our core areas with additional third-partycapital, debt restructurings, the issuance of new debt or equity and conservation of our liquid assets. The outcome of these potential alternatives, thetiming of which cannot be accurately predicted at this time, are likely to affect our liquidity, future operations and financial condition.•2016 Capital Expenditures. We expect to control our reduced liquidity during 2016 by scaling back our capital expenditures to match the currentcommodity pricing environment. Although we cannot predict or control future commodity prices, our expected 2016 capital expenditure budget hasbeen decreased to accommodate market expectations of reduced commodity prices. We have a modest capital program of $40.0 million to $50.0million planned for 2016 in order to conserve our liquid assets. Theses costs will largely be incurred during the first quarter of 2016.•Cost-Reduction Initiatives. We have taken steps to reduce our future capital, operating and corporate costs. During 2015, we continually negotiatedwith our primary suppliers and service providers resulting in an approximate 29% reduction in our drilling and completion costs on our standardreach lateral wells and an approximate 12% reduction in our lease operating expense per Boe. We also took measures to reduce corporate costs byreducing headcount resulting in a $5.3 million reduction in general and administrative expense on an annual basis and we continue to focus on costreduction opportunities.Given the current commodity price environment and our goal of optimizing the Company's liquidity, we estimate our capital expenditures in theWattenberg Field for 2016 to be $35.0 million to $45.0 million, used to drill two extended reach lateral wells in the Niobrara formation, six standard reachlateral wells in the Niobrara and one standard reach lateral well in the Codell. We anticipate completing four medium reach lateral wells and eight standardreach lateral wells in the Niobrara and participate in the completion of three non-operated wells. In the Mid-Continent region, we plan to spendapproximately $3.5 million during 2016 to perform approximately 38 recompletions with the remaining $1.5 million planned for corporate expenditures. Ifcommodity prices do not increase significantly or if our properties held for sale are not sold, we will cease drilling at the end of the first quarter 2016. Theultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, commodity prices, sale of non-coreassets, the success of our drilling results as the year progresses and changes in the borrowing base under our revolving credit facility.Results of Operations 63 Table of ContentsThe following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto contained inPart II, Item 8 of this Annual Report on Form 10-K. Comparative results of operations for the period indicated are discussed below.The table below presents revenues, sales volumes, and average sales prices for the years ended December 31, 2015 and 2014: For the Years Ended December 31, 2015(1) 2014 (4) Change Percent Change (In thousands, except percentages)Operating Revenues: Crude oil sales$248,862 $460,442 $(211,580) (46)%Natural gas sales 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 operatedsales 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 reclassifiedto 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 derivativecash 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 heldfor sale as of December 31, 2014. Revenues decreased by 48% to $292.7 million for the year ended December 31, 2015 compared to $558.6 million for the year ended December 31,2014 largely due to a 56% decrease in oil equivalent pricing. The decreased pricing was offset by increased sales volumes of 20% for the year endedDecember 31, 2015 compared to the same period in 2014. The increased64 Table of Contentsvolumes are a direct result of $404.0 million expended for drilling and completion during 2015. During the period from December 31, 2014 throughDecember 31, 2015, we drilled 84 gross (66 net) and completed 95 gross (77.1 net) wells in the Rocky Mountain region and drilled 24 gross (22.2 net) andcompleted 21 gross (19.4 net) wells in the Mid-Continent region. The following table summarizes our operating expenses for the periods indicated. For the Years Ended December 31, 2015 2014 (2) Change Percent Change (In thousands, except percentages)Operating Expenses: Lease operating expense$76,406 $72,411 $3,995 6 %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 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$7.40 $8.44 $(1.04) (12)%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 6.81 9.51 (2.70) (28)%Operating Expenses$116.29 $70.64 $45.65 65 % Operating expenses, excluding impairments$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 operatedsales 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 reclassifiedto 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 heldfor sale as of December 31, 2014. Lease Operating Expense. Our lease operating expense increased $4.0 million or 6%, to $76.4 million for the year ended December 31, 2015 from$72.4 million for the year ended December 31, 2014 and decreased on an equivalent basis from $8.44 per Boe to $7.40 per Boe. The increase in aggregatelease operating expense was related to the 20% increase in sales volumes during the year ended December 31, 2015 when compared to the same period in2014. During the year ended December 31, 2015, the largest component of lease operating expense was compression, which increased $4.0 million over thecomparable period in 2014. The Company reduced operating costs and negotiated contract reductions while increasing production for the year endedDecember 31, 2015, driving the per equivalent barrel rate down when compared to the same period in 2014. Severance and ad valorem taxes. Our severance and ad valorem taxes decreased $31.8 million to $18.6 million for the year ended December 31,2015 from $50.4 million for the year ended December 31, 2014. Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 48%for the year ended December 31, 2015 when compared to the same period in 2014 causing the severance and ad valorem taxes to decrease. Severance and advalorem taxes were further reduced65 Table of Contentsby a tax refund received during 2015. Additionally, our ad valorem tax credits available for deduction increased in 2015 when compared to the same periodin 2014 due to continued development of the Wattenberg Field which further reduced our effective severance tax rate. Exploration. Our exploration expense increased $10.5 million to $15.8 million during the year ended December 31, 2015 from $5.3 million for theyear ended December 31, 2014. During the year ended December 31, 2015, we incurred charges for exploratory wells located in both the North Park Basinand outside of our current development area in southern Arkansas for $5.6 million and $8.5 million, respectively, which we were unable to assign economicproved reserves, and paid $1.0 million and $0.7 million in geological and geophysical expenses and delay rentals, respectively. In 2014, we incurred $3.4million of seismic charges for an acquisition project within the Wattenberg Field, a $1.0 million dry hole charge related to a vertical well within theWattenberg Field drilled to test the Lyons formation, and $0.9 million in delay rentals. Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased $16.1 million, or 7%, to $244.9 millionfor the year ended December 31, 2015 from $228.8 million for the year ended December 31, 2014 and decreased on an equivalent basis from $26.66 per Boeto $23.73 per Boe. The decrease in equivalent basis was primarily due to depreciation ceasing once assets were deemed held for sale coupled with a 20%increase in sales volumes.Impairment of oil and gas properties. Our impairment of proved properties increased $572.9 million to $740.5 million for the year endedDecember 31, 2015 when compared to year ended December 31, 2014. We impaired our Mid-Continent assets by $321.2 million due to their depressed fairvalue from low commodity prices upon classification as held for sale and our Rocky Mountain assets by $419.3 million due to low commodity prices. For theyear ended December 31, 2014, we impaired $127.3 million of proved properties within the Dorcheat Macedonia Field due to low commodity prices, $25.0million of non-core proved properties within the McKamie Patton Field due to low commodity prices, and $15.3 million of proved properties in ourMcCallum Field due to low commodity prices and a strategic shift to horizontal drilling. Please refer to Note 1 - Summary of Significant Accounting Policiesin Part II, Item 8 of this Annual Report on Form 10-K for additional discussion on our impairment policy and practice.Abandonment and impairment of unproved properties. Our abandonment and impairment of unproved properties increased to $33.5 million for theyear ended December 31, 2015 when compared to the year ended December 31, 2014. We incurred $24.8 million of impairment charges relating to non-coreleases expiring within the Wattenberg Field and $8.7 million of impairment charges to fully impair the North Park Basin due to a strategic shift in ourdevelopment plan. There were no unproved properties abandoned or impaired during the year ended December 31, 2014. General and administrative. Our general and administrative expense decreased $11.3 million, or 14%, to $70.3 million for the year endedDecember 31, 2015 from $81.6 million for the comparable period in 2014 and decreased on an equivalent basis to $6.81 per Boe from $9.51 per Boe. Thedecrease in general and administrative expense for the year ended December 31, 2015 when compared to the same period in 2014 was primarily due toexecutive departure costs that occurred in 2014. The decrease in equivalent basis was caused by the 20% increase in sales volumes outpacing the change inthe expense. Derivative gain. Our derivative gain decreased $65.0 million to $56.6 million for the year ended December 31, 2015 from a gain of $121.6 millionfor the comparable period in 2014. The decrease in gain is related to a reduction in hedged volumes during the year ended December 31, 2015 whencompared to the year ended December 31, 2014. Please refer to Note 13 - Derivatives in Part II, Item 8 of this Annual Report on Form 10-K for additionaldiscussion. Interest expense. Our interest expense for the year ended December 31, 2015 increased 23% to $57.1 million compared to $46.4 million for the yearended December 31, 2014 due to the average debt outstanding for the year ended December 31, 2015 being $847.9 million as compared to $644.4 million forthe comparable period in 2014. Interest expense, including amortization of the premium and financing costs, on the Senior Notes for the years endedDecember 31, 2015 and 2014 was $52.1 million and $42.3 million, respectively. Income tax benefit (expense). Our estimate for federal and state income tax benefit for the year ended December 31, 2015 was $164.9 million ascompared to income tax expense of $11.0 million for the year ended December 31, 2014. We are allowed to deduct various items for tax reporting purposesthat are capitalized for purposes of financial statement presentation. Our effective tax rates for the year ended December 31, 2015 was 18.1% as compared to39.3% for the year ended December 31, 2014. These rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes and avaluation allowance being placed against net deferred tax assets.66 Table of ContentsYear Ended December 31, 2014 Compared to Year Ended December 31, 2013The table below presents revenues, sales volumes, and average sales prices for the years ended December 31, 2014 and 2013: For the Years Ended December 31, 2014(3) 2013(3) Change Percent Change (In thousands, except percentages)Operating Revenues: Crude oil sales$460,442 $357,001 $103,441 29 %Natural gas sales 78,714 46,490 32,224 69 %Natural gas liquids sales 19,470 18,256 1,214 7 %CO2 sales 7 113 (106) (94)%Product revenue$558,633 $421,860 $136,773 32 % Sales Volumes: Crude oil (MBbls) 5,618.7 3,887.2 1,731.5 45 %Natural gas (MMcf) 15,395.8 9,975.9 5,419.9 54 %Natural gas liquids (MBbls) 396.2 352.8 43.4 12 %Crude oil equivalent (MBoe)(1) 8,580.9 5,902.7 2,678.2 45 % Average Sales Prices (before derivatives): Crude oil (per Bbl)$81.95 $91.84 $(9.89) (11)%Natural gas (per Mcf)$5.11 $4.66 $0.45 10 %Natural gas liquids (per Bbl)$49.14 $51.74 $(2.60) (5)%Crude oil equivalent (per Boe)(1)$65.10 $71.45 $(6.35) (9)% Average Sales Prices (after derivatives)(2): Crude oil (per Bbl)$84.00 $88.82 $(4.82) (5)%Natural gas (per Mcf)$5.16 $4.70 $0.46 10 %Natural gas liquids (per Bbl)$49.14 $51.74 $(2.60) (5)%Crude oil equivalent (per Boe)(1)$66.53 $69.53 $(3.00) (4)%________________________________(1)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.(2)The derivatives economically hedge the price we receive for crude oil and natural gas. For the years ended December 31, 2014 and 2013, the derivativecash settlement gain (loss) for oil contracts was $11.5 million and $(11.8) million, respectively, and the derivative cash settlement gain for gas contractswas $0.7 million and $0.4 million, respectively. Please refer to Note 13 - Derivatives contained in Part II, Item 8 of this Annual Report on Form 10-K foradditional disclosure.(3)Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or heldfor sale as of December 31, 2014 and 2013. Revenues increased by 32%, to $558.6 million for the year ended December 31, 2014 compared to $421.9 million for the year ended December 31,2013 due primarily to an increase in oil, natural gas, and natural gas liquids sales volumes of 45%, 54% and 12%, respectively. The increased volumes wereoffset by a 9% decrease in crude oil equivalent pricing. The increased volumes are a direct result of the $650.8 million spent for drilling and completionduring 2014. For the period from January 1, 2014 through December 31, 2014, we participated in drilling 126 gross (99.4 net) wells in the Rocky Mountainregion and 48 gross (42.7 net) wells in the Mid-Continent region, and participated in completing 121 gross (99.7 net) wells in the Rocky Mountain regionand 50 gross (44.6 net) wells in the Mid-Continent region. Our Wattenberg Field natural gas is sold without processing into dry gas and NGLs, and therefore,sells at a premium due to its high BTU content.67 Table of ContentsThe table below presents operating expenses and per Boe data for the years ended December 31, 2014 and 2013: For the Years Ended December 31, 2014(1) 2013(1) Change Percent Change (In thousands, except percentages)Operating Expenses: Lease operating expense$72,411 $47,771 $24,640 52 %Severance and ad valorem taxes 50,430 27,203 23,227 85 %Exploration 5,346 4,213 1,133 27 %Depreciation, depletion and amortization 228,789 140,176 88,613 63 %Impairment of oil and gas properties 167,592 — 167,592 100 %General and administrative 81,571 55,502 26,069 47 %Operating Expenses$606,139 $274,865 $331,274 121 % Selected Costs ($ per Boe): Lease operating expense$8.44 $8.09 $0.35 4 %Severance and ad valorem taxes 5.88 4.61 1.27 28 %Exploration 0.62 0.71 (0.09) (13)%Depreciation, depletion and amortization 26.66 23.75 2.91 12 %Impairment of proved properties 19.53 — 19.53 100 %General and administrative 9.51 9.40 0.11 1 %Operating Expenses$70.64 $46.56 $24.08 52 %_______________________________(1)Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or heldfor sale as of December 31, 2014 and 2013. Lease operating expense. Our lease operating expenses increased $24.6 million, or 52%, to $72.4 million for the year ended December 31, 2014from $47.8 million for the year ended December 31, 2013 and increased on an equivalent basis from $8.09 per Boe to $8.44 per Boe. The increase in leaseoperating expense was related to the increased sales volumes of 45% attributable to our drilling program. During the year ended December 31, 2014, three ofthe largest components of lease operating expenses: well servicing, compression and pumping increased $10.0 million, $7.1 million and $3.5 million,respectively, over the comparable period in 2013. We were impacted by high gas gathering pipeline pressures and emission compliance standards whichresulted in sales volumes that were less than anticipated. The increase in lease operating expenses on an equivalent basis was due to extreme cold weatherexperienced during both the first and fourth quarters of 2014 driving up operating costs at a faster pace than sales volumes.Severance and ad valorem taxes. Our severance and ad valorem taxes increased $23.2 million, or 85%, to $50.4 million for the year endedDecember 31, 2014 from $27.2 million for the year ended December 31, 2013. The increase was primarily related to a 45% increase in sales volumes for theyear ended December 31, 2014 over the comparable period in 2013. Colorado has higher severance and ad valorem tax rates than Arkansas and contributed agreater percentage of production for the year ended December 31, 2014 when compared to the same period in 2013. Increased sales volumes from ourWattenberg wells completed in 2014 resulted in a lag in the amount of ad valorem tax credits eligible for deduction against severance taxes generated in thecurrent year because ad valorem taxes are not eligible for deduction during the year a well is completed.Exploration. Our exploration expense increased $1.1 million to $5.3 million in the year ended December 31, 2014 from $4.2 million in the yearended December 31, 2013. During 2014, we incurred $3.4 million of seismic charges for an acquisition project within the Wattenberg Field, a $1.0 milliondry hole charge related to a vertical well within the Wattenberg Field drilled to test the Lyons formation, and $0.9 million in delay rentals. During 2013, wespent $1.5 million on a seismic acquisition project within the Wattenberg Field, wrote-off one exploratory dry hole totaling $0.6 million and wrote-off$1.7 million on an expired non-core lease in the North Park Basin.Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased $88.6 million, or 63%, to $228.8 millionfor the year ended December 31, 2014 from $140.2 million for the year ended68 Table of ContentsDecember 31, 2013. Our depreciation, depletion, and amortization expense per Boe increased $2.91, to $26.66 for the year ended December 31, 2014 ascompared to $23.75 for the year ended December 31, 2013. The increase was primarily the result of a sales volumes growth of 45% outpacing thecorresponding growth in proved reserves of 28%.Impairment of oil and gas properties. Our impairment of oil and gas properties was $167.6 million for the year ended December 31, 2014. Weimpaired $127.3 million of proved properties within the Dorcheat Macedonia Field due to low commodity prices, $25.0 million of non-core provedproperties within the McKamie Patton Field due to low commodity prices, and $15.3 million of proved properties in our McCallum Field due to lowcommodity prices and a strategic shift to horizontal drilling. The Company incurred no impairment charges for the year ended December 31, 2013. Pleaserefer to Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 of this Annual Report on Form 10-K for additional discussion.General and administrative. Our general and administrative expense increased $26.1 million, or 47%, to $81.6 million for the year endedDecember 31, 2014 from $55.5 million for the year ended December 31, 2013 and increased on an equivalent basis from $9.40 per Boe to $9.51 per Boe.During the year ended December 31, 2014, wages and benefits (excluding executive departures) were $13.8 million higher than the comparable period in2013. The increase in wages and benefits is primarily due to an increase in headcount as a result of our drilling program between the two years. Cashseverance and stock-based compensation for executive departures was $14.1 million for the year ended December 31, 2014.Derivative gain (loss). Our derivative gain increased $134.1 million to $121.6 million for the year ended December 31, 2014 from a loss of $12.5million for the comparable period in 2013. The gain incurred was primarily the result of realized prices being less than the contract prices as commodity stripprices, particularly oil, decreased during 2014. Please refer to Note 13 - Derivatives in Part II, Item 8 of this Annual Report on Form 10-K for additionaldiscussion.Interest expense. Our interest expense increased $24.4 million, or 111%, to $46.4 million for the year ended December 31, 2014 from $22.0 millionfor the year ended December 31, 2013. The increase for the year ended December 31, 2014 is primarily due to the $200.0 million 6.75% Senior Notes add-onthat occurred during the fourth quarter of 2013 and the issuance of the $300.0 million 5.75% Senior Notes at the beginning of the third quarter of 2014.Interest expense, including amortization of the premium and financing costs, on the Senior Notes for the year ended December 31, 2014 and 2013 was $42.3million and $17.0 million, respectively. Interest expense on our revolving credit facility was $3.0 million and amortization of deferred financing costs was$1.1 million for the year ended December 31, 2014. Average debt outstanding during 2014 was $644.4 million as compared to $306.0 million for thecomparable period in 2013.Income tax expense. Our estimate for federal and state income taxes for the year ended December 31, 2014 was $11.0 million from continuingoperations as compared to $42.9 million for the year ended December 31, 2013. We are allowed to deduct various items for tax reporting purposes that arecapitalized for purposes of financial statement presentation. Our effective tax rate for the year ended December 31, 2014 was 39.3% as compared to 38.2% forthe year ended December 31, 2013. These rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.Results for Discontinued OperationsDuring June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California. The Company determinedthat our intent to sell out of an entire region qualified for discontinued operations accounting and these assets have been presented as discontinuedoperations in the accompanying statements of operations.The majority of these properties were sold in 2012. The remaining property located in the Midway Sunset Field sold on March 21, 2014 forapproximately $6.0 million and resulted in a $5.5 million gain.The operating results before income taxes for our California properties for the year ended December 31, 2014 were net revenues of $0.4 million, andoperating expenses of $0.4 million, as compared to net revenues of $1.7 million, and operating expenses of $2.3 million for the year ended December 31,2013. Sales volumes for the years ended December 31, 2014 and 2013 were 10 Boe/d and 47 Boe/d, respectively.Liquidity and Capital Resources We fund our operations, capital expenditures and working capital requirements with cash flows from our operating activities, borrowings under ourrevolving credit facility, divestitures of assets and by accessing the debt and capital markets. We currently anticipate funding our 2016 operations with operating cash flows and the revolving credit facility, until such point that we execute adivestiture. We believe that we will have sufficient cash flows to fund our business for at least the69 Table of Contentsnext 12 months after the date of this filing, assuming we cease drilling after the first quarter of 2016 and until such point that oil prices rebound or we executeupon one or more of our 2016 liquidity strategies. To the extent actual operating results differ from our anticipated results or our borrowing base under ourrevolving credit facility is significantly reduced, our liquidity could be adversely affected. Furthermore, our ability to borrow under our revolving creditfacility is subject to compliance with certain financial covenants, including the maintenance of certain financial ratios, including a minimum current ratio, amaximum leverage ratio and a minimum interest coverage ratio. As of December 31, 2015, the Company was in compliance with all financial covenants, witha senior secured debt to EBITDAX ratio of 0.3x, an interest coverage ratio of 4.8x and a current ratio of 3.5x. However, continuation of low oil, natural gasand NGL prices or their further deterioration could significantly reduce cash flow, which is a critical underpinning of our required financial covenants, whichcould make it necessary for us to negotiate an amendment to one or more of these financial covenants in order to avoid a default. Our ultimate success innegotiating such an amendment with our lenders is not guaranteed nor is our ability to avoid a restructuring or bankruptcy filing. On July 15, 2014, we issued $300.0 million of 5.75% Senior Notes that mature on February 1, 2023. Interest on the 5.75% Senior Notes beganaccruing on July 15, 2014, and we will pay interest on February 1 and August 1 of each year, beginning on February 1, 2015. The net proceeds from the saleof the 5.75% Senior Notes were approximately $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions.Please refer to Note 7 - Long-Term Debt in Part II, Item 8 of this Annual Report on Form 10-K for additional discussion.On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.7 millionafter deducting underwriter discounts, commissions and estimated offering expenses of approximately $6.6 million.On May 13, 2015, our borrowing base was decreased from $600.0 million to $550.0 million and was subsequently further reduced by 14% onOctober 19, 2015 from $550.0 million to $475.0 million, despite a 56% reduction in our crude oil equivalent pricing in 2015 when compared to 2014. As ofDecember 31, 2015, we had $79.0 million outstanding on our revolving credit facility, a $12.0 million letter of credit issued, and $384.0 million of availableborrowing capacity. Our next scheduled borrowing base redetermination is to occur during May 2016. Our weighted-average interest rates (excludingamortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) on borrowings from our revolving credit facilitywere 1.71% and 2.31%, respectively, for the years ended December 31, 2015 and 2014. Our commitment fees were $1.9 million and $2.0 million,respectively, for the years ended December 31, 2015 and 2014. Please refer to the Credit Facility section below for additional discussion.In 2016, we have 5,500 Bbls per day of oil hedged with three-way collars with an average ceiling of $96.83 per Bbl, average floor of $85.00 per Bbland average short floor of $70.00 per Bbl. We expect that our commodity derivative positions will provide partial stabilization of our expected cash flowsfrom operations. Please refer to Note 13 - Derivatives in Part II, Item 8 of this Annual Report on Form 10-K for a summary of derivatives in place and Item 3.Quantitative and Qualitative Disclosures About Market Risks below for additional discussion. The following table summarizes our cash flows and other financial measures for the periods indicated. For the Years Ended December 31, 2015 2014 2013 (in thousands) Net cash provided by operating activities$95,027 $327,720 $307,015Net cash used in investing activities(321,577) (824,994) (465,223)Net cash provided by financing activities245,307 319,276 334,522Cash and cash equivalents21,341 2,584 180,582Acquisition of oil and gas properties16,270 179,566 13,797Exploration and development of oil and gas properties425,918 641,204 417,835 Cash flows provided by operating activities During 2015, we generated $95.0 million of cash provided by operating activities, a decrease of $232.7 million from the comparable period in 2014.The decrease in cash flows from operating activities resulted primarily from a 56% decrease in crude oil equivalent pricing and was partially offset by a 20%increase in sales volumes and a $31.8 million reduction in70 Table of Contentsseverance and ad valorem taxes during the year ended December 31, 2015 as compared to the year ended December 31, 2014. See Results of Operationsabove for more information on the factors driving these changes.During 2014, we generated $327.7 million of cash provided by operating activities, an increase of $20.7 million from 2013. The increase in cashflows from operating activities resulted primarily from a 45% increase in sales volumes offset by a 9% decrease in realized crude oil equivalent prices. Thesepositive factors were partially offset by increased lease operating expense, production taxes, cash portion of general and administrative expense, and cashportion of interest expense during 2014 as compared to 2013. See Results of Operations above for more information on the factors driving these changes.Cash flows used in investing activities Expenditures for development of oil and natural gas properties are the primary use of our capital resources. Net cash used in investing activities forthe year ended December 31, 2015 decreased $503.4 million as compared to the same period in 2014. For the year ended December 31, 2015, cash used forthe acquisition of oil and gas properties was $16.3 million and cash used for the development of oil and natural gas properties was $425.9 million which wasoffset by net derivative cash receipts of $131.0 million. For the year ended December 31, 2014, cash used for the acquisition of oil and gas properties was$179.6 million, cash used for the development of oil and natural gas properties was $641.2 million and net derivative cash receipts were $12.2 million. Forthe year ended December 31, 2013, cash used for the acquisition of oil and gas properties was $13.8 million, cash used for the development of oil and naturalgas properties was $417.8 million. Cash flows provided by financing activities Net cash provided by financing activities for the year ended December 31, 2015 decreased $74.0 million, compared to the same period in 2014. Thedecrease was primarily due to $202.7 million of net proceeds from the sale of common stock that occurred during the year plus net borrowings of $46.0million from our revolving credit facility compared to $292.9 million of net proceeds from the sale of Senior Notes plus net borrowings of $33.0 million fromour revolving credit facility during the year ended December 31, 2014 being less.Credit facilityRevolving Credit FacilityThe administrative agent of our $1.0 billion revolving credit facility is KeyBank National Association. The revolving credit facility provides forinterest rates plus an applicable margin to be determined based on the London Interbank Offered Rate (“LIBOR”) or a bank base rate (“Base Rate”), at theCompany’s election. LIBOR borrowings bear interest at LIBOR plus 1.50% to 2.50% depending on the utilization level, and the Base Rate borrowings bearinterest at the “Bank Prime Rate,” as defined in the revolving credit facility, plus 0.50% to 1.50%.Our approved borrowing base under the revolving credit facility, which was $475.0 million as of December 31, 2015, is redetermined semiannuallyby May 15 and November 15 and may be redetermined up to one additional time between such scheduled determinations upon our request or upon therequest of the required lenders (defined as lenders holding 662/3% of the aggregate commitments). The borrowing base is determined by the value of our oiland gas reserves. The borrowing base is redetermined (i) in the sole discretion of the administrative agent and all of the lenders, (ii) in accordance with theircustomary internal standards and practices for valuing and redetermining the value of oil and gas properties in connection with reserve based oil and naturalgas loan transactions, (iii) in conjunction with the most recent engineering report and other information received by the administrative agent and the lendersrelating to our proved reserves and (iv) based upon the estimated value of our proved reserves as determined by the administrative agent and the lenders.As of December 31, 2015, and through the date of this filing, we had $79.0 million outstanding under our revolving credit facility. The revolvingcredit facility matures on September 15, 2017. Amounts borrowed and repaid under the revolving credit facility may be re-borrowed. The revolving creditfacility may be used only to finance development of oil and gas properties, for working capital and for other general corporate purposes.Our obligations under the revolving credit facility are secured by first priority liens on all of our property and assets (whether real, personal, ormixed, tangible or intangible), including our proved reserves and our oil and gas properties (which term is defined to include fee mineral interests, termmineral interests, leases, subleases, farm-outs, royalties, overriding royalties, net profit interests, carried interests, production payments, back in interests andreversionary interests). The revolving credit facility is guaranteed by us and all of our direct and indirect subsidiaries.71 Table of ContentsThe applicable margin varies on a daily basis based on the percentage outstanding under the borrowing base. We incur quarterly commitment feesbased on the unused amount of the borrowing base ranging from 0.375% and 0.50% per annum. We may prepay loans under the revolving credit facility atany time without premium or penalty (other than customary LIBOR breakage costs).The revolving credit facility contains various covenants limiting our ability to:•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.The revolving credit facility also contains covenants requiring us to maintain:•a current ratio (i.e., the ratio of current assets to current liabilities, excluding unsettled derivatives) of not less than 1.0 to 1.0 (current assetsinclude, 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 anyoutstanding 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 of 2.50 to 1.00; and•a minimum trailing twelve-month interest to trailing twelve-month EBITDAX coverage rate of 2.50 to 1.00.As of December 31, 2015 and through the filing date of this report, we were in compliance with all financial and non-financial covenants. There isthe possibility that if commodity prices do not rebound or we are not able to execute upon one or more of our 2016 liquidity strategies, we will violate ourdebt covenants by the end of 2016. If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of theloan and exercise other rights and remedies.The revolving credit facility contains customary events of default, including:•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;72 Table of Contents•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 theSecurities and Exchange Act of 1934, as amended, but excluding certain permitted stockholders) directly or indirectly, of more than 35% of ourcommon stock, other than certain of our current stockholders.Contractual Obligations We have the following contractual obligations and commitments as of December 31, 2015: Less than More than Total 1 Year 1 - 3 Years 3 - 5 Years 5 Years (in thousands)Contractual Obligation Senior Notes $800,000 $— $— $— $800,000Interest on Senior Notes 300,829 51,000 102,000 102,000 45,829Revolving credit facility(1) 79,000 — 79,000 — —Delivery commitments(2) 503,685 66,616 179,222 142,871 114,976Wattenberg Field lease acquisition 12,000 12,000 — — —Operating leases(2) 13,023 2,662 5,446 4,915 —Asset retirement obligations(3) 114,196 2,370 1,415 6,860 103,551Total $1,822,733 $134,648 $367,083 $256,646 $1,064,356___________________(1)The revolving credit facility matures in September 2017. The actual payments made on our revolving credit facility may vary significantly.(2)See Note 8 - Commitments and Contingencies to our consolidated financial statements for a description of operating leases and purchase andtransportation agreements.(3)Amounts represent our estimated future retirement obligations on an undiscounted basis. The discounted obligations are recorded as liabilities on ouraccompanying balance sheets as of December 31, 2015. There is $0.2 million included in the less than one year category and is not discounted and isincluded in accounts payable and accrued expenses as of December 31, 2015. 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 - AssetRetirement Obligation, for additional discussion.Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which havebeen prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us tomake estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets andliabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially differentamounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on aregular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, theresults of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actualresults may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of ourmore significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates andassumptions used in preparation of our consolidated financial statements. See Note 1 - Summary of Significant Accounting Policies to our auditedconsolidated financial statements for a discussion of additional accounting policies and estimates made by management.73 Table of ContentsMethod of accounting for oil and natural gas propertiesOil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all propertyacquisition costs and costs of exploratory and development wells are capitalized at cost when incurred, pending determination of whether the well has foundproved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells arecapitalized whether productive or nonproductive. All capitalized well costs and other associated costs and leasehold costs of proved properties are amortizedon a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, toaccumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire field, inwhich case a gain or loss is recognized currently. Gains or losses from the disposal of properties are recognized currently.Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Majorbetterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonmentcosts for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over theremaining life of the related proved developed reserves.Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalizeduntil the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved leaseacquisition costs. The expensing or expiration of unproved lease acquisition costs are recorded as exploration expense in the statements of operations andcomprehensive income in our consolidated financial statements. Lease acquisition costs related to successful exploratory drilling are reclassified to provedproperties and depleted on a unit-of-production basis.For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds receivedand the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless theproceeds exceed the entire cost of the property.Oil and natural gas reserve quantities and Standardized MeasureOur internal corporate reservoir engineering group prepares, and our third-party petroleum consultant audits our estimates of oil and natural gasreserves and associated future net revenues. While the SEC has adopted rules which allow us to disclose proved, probable and possible reserves, we haveelected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC’s revised rules define proved reserves as the quantities of oil and gas,which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward,from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contractsproviding the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilisticmethods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it willcommence the project within a reasonable time. Our internal corporate reservoir engineering group and our third party petroleum consultant must make anumber of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually andconsider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process ofestimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of thequality of available data and of engineering and geological interpretation and judgment.Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoirperformance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors.Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amountsor timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result inimpairment of assets that may be material.Revenue recognitionRevenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumedthe risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (lessthan 12-month) contracts at market-based prices. The sales prices for oil74 Table of Contentsand natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not requiresignificant judgment.Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oiland natural gas, we sell the majority of production soon after it is produced at various locations.Impairment of proved propertiesWe review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverabilityof their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare suchundiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carryingamount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. Thefactors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties,the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, futureproduction estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated withrealizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges forproved properties will be recorded.Impairment of unproved propertiesWe assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results orfuture plans to develop acreage and record impairment expense for any decline in value.We have historically recognized abandonment and impairment expense for unproved properties at the time when the lease term has expired orsooner if, in management’s judgment, the unproved properties have lost some or all of their carrying value. We consider the following factors in ourassessment of the impairment of unproved properties:•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 toexpiration;•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 Niobrara formation by us or by otheroperators in areas adjacent to or near our unproved properties.The assessment of unproved properties to determine any possible impairment requires significant judgment.Asset retirement obligationsWe record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the correspondingcost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled oracquired. The asset retirement obligation (“ARO”) for oil and gas properties represents the estimated amount we will incur to plug, abandon and remediatethe properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and thecapitalized cost is depreciated on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion andamortization in our consolidated statements of operations and comprehensive income.We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requiresmanagement to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fairvalue calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlementand changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value ofthe existing ARO liability, a corresponding adjustment is made to the related asset.75 Table of ContentsDerivativesWe record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designatedany derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Derivativeinstruments are adjusted to fair value every accounting period. Derivative cash settlements and gains and losses from valuation changes in the remainingunsettled commodity derivative instruments are reported under derivative gain (loss) in our consolidated statements of operations and comprehensiveincome.Stock-based compensationRestricted Stock Awards. We recognize compensation expense for all restricted stock awards made to employees and directors. Stock-basedcompensation expense is measured at the grant date based on the fair value of the award and is recognized as an expense on a straight-line basis over therequisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the dateof grant. Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount ofstock-based compensation expense recognized. Stock-based compensation expense recorded for restricted stock awards is included in general andadministrative expenses on our consolidated statements of operations and comprehensive income.Performance Stock Units. We recognize compensation expense for all performance stock unit awards made to officers. Stock-based compensationexpense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite serviceperiod, which is generally the vesting period. The fair value of the performance stock unit is measured at the grant date with a stochastic process methodusing the Monte Carlo simulation. Stock-based compensation expense recorded for performance stock units is included in general and administrativeexpenses on our consolidated statements of operations and comprehensive income.Income taxesOur provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxesunder GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences betweenthe book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to applyto taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred taxassets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance would beestablished to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course ofbusiness, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future taxconsequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognitionthreshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty inincome taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would morelikely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financialstatements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. We did nothave any uncertain tax positions as of the year ended December 31, 2015.Recent accounting pronouncementsIn April 2014, the FASB issued Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a majoreffect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning afterDecember 15, 2014 and is to be applied prospectively. The Company has adopted this provision and it has resulted in minimal impact.In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers. The update prescribes two acceptable methods andis effective for the annual period beginning after December 15, 2016, including interim periods76 Table of Contentswithin that reporting period. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidancewill have a material effect on the Company's financial statements or disclosures.In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That aPerformance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when anaward provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied eitherprospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company currently does nothave any awards that fall within this guidance, but will apply it if such an award is issued.In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements - Going Concern that requires management toevaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after thedate that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and toprovide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods andinterim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact, butdoes not currently believe it will have a material effect on the Company’s financial statements or disclosures.In April 2015, the FASB issued Update No. 2015-03 - Interest - Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs. Thisupdate requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amountof that debt liability. This authoritative accounting guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within thosefiscal years on a retrospective basis. The Company has taken the necessary steps to be ready for adoption of this update but does not believe it will have amaterial effect on the Company’s financial statements or disclosures.In July 2015, the FASB issued Update No. 2015-11 - Inventory. The update requires that inventory be measured at the lower of cost or net realizablevalue. This authoritative guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. The Companyis currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’sfinancial statements or disclosures.In August 2015, the FASB issued Update No. 2015-14 - Revenue from Contracts with Customers to defer the effective date of the new revenuerecognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods,beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning afterDecember 15, 2016. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will havea material effect on the Company’s financial statements or disclosures.In November 2015, the FASB issued Update No. 2015-17 - Income Taxes to simplify the presentation of deferred income taxes by classifyingdeferred tax assets and liabilities as non-current only. The new guidance is effective for annual periods, and interim periods within those annual periods,beginning after December 15, 2016. Early application is permitted. The Company has evaluated the provisions of this guidance and determined it will haveminimal impact on the Company’s financial statements and disclosures.In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets andfinancial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. Thisauthoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company is currentlyevaluating the provisions of this guidance and assessing its impact in relation to the Company's derivatives, but does not currently believe it will have amaterial effect on the Company’s financial statements or disclosures.Effects of Inflation and Pricing Inflation in the United States increased from 1.3% in 2014 to 2.0% in 2015, which did not have a material impact on our results of operations for theperiods ended December 31, 2015, 2014 and 2013. Although the impact of inflation has been relatively insignificant in recent years, it is still a factor in theUnited States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increasedrilling activity in our areas of77 Table of Contentsoperations. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense,impairment assessments of oil and gas properties, ARO, and values of properties in purchase and sale transactions. Material changes in prices can impact thevalue of oil and gas companies and their ability to raise capital, borrow money and retain personnel. Given the recent decline in oil and gas prices, we wouldanticipate that costs of materials and services would also decline.Off-Balance Sheet Arrangements Currently, we do not have any off-balance sheet arrangements.Item 7A. Quantitative and Qualitative Disclosures About Market Risks.Oil and Natural Gas Price RiskOur financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencingoil and natural gas prices include the level of global demand for oil and natural gas, the global supply of oil and natural gas, the establishment of andcompliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability ofalternative fuels, local and global politics, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree ofcertainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce theamount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to pricefluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oiland natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. If oil and natural gas SEC pricesdeclined by 10% then our PV-10 value as of December 31, 2015 would decrease by approximately 12% or $39.5 million. The PV-10 of our Rocky Mountainregion, primarily our Wattenberg assets, would decrease by 9.5% or $23.5 MM.PV-10 is a non-GAAP financial measure. Please refer to Estimated Proved Reserves under Part I, Item 1 of this Annual Report on Form 10-K formanagement's discussion of this non-GAAP financial measure.Commodity Derivative ContractsOur primary commodity risk management objective is to reduce volatility in our cash flows. We enter into derivative contracts for oil and natural gasusing NYMEX futures or over-the-counter derivative financial instruments with only well-capitalized counterparties which have been approved by our boardof directors.The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes areless than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas orotherwise fail to perform. To the extent that we engage in derivative contracts, we may be prevented from realizing the benefits of favorable price changes inthe physical market. However, we are similarly insulated against decreases in such prices.Presently, all of our derivative arrangements are concentrated with three counterparties, all of which are lenders under our credit facility. If thesecounterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in thephysical market.The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our derivatives, if owedby us, generally up to 15 business days before we receive market price cash payments from our customers. This could have a material adverse effect on ourcash flows for the period between derivative settlement and payment for revenues earned.Please refer to the Derivative Activities section of Part I, Item 1 of this Annual Report on Form 10‑K for summary derivative activity tables.For the oil and natural gas derivatives outstanding at December 31, 2015, a hypothetical upward or downward shift of 10% per Bbl or MMBtu in theNYMEX forward curve as of December 31, 2015 would change our derivative gain by $(0.3) million and $0.3 million, respectively.78 Table of ContentsInterest RatesAt December 31, 2015 and through the filing date of this report we had $79.0 million outstanding under our revolving credit facility. Borrowingsunder our revolving credit facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Any increases in theseinterest rates can have an adverse impact on our results of operations and cash flow. As of December 31, 2015 and through the filing date of this report, theCompany had minimal interest expense associated with its revolving credit facility, therefore a one percentage point change within the interest rate wouldhave a minimal impact on our financials.Counterparty and Customer Credit RiskIn connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Three lenders under ourcredit facility are currently counterparties on our derivative instruments currently in place and have investment grade credit ratings. We expect that anyfuture derivative transactions we enter into will be with these or other lenders under our credit facility that will carry an investment grade credit rating.We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. Please refer to thesection titled Principal Customers under Part I, Item 1 of this Annual Report on Form 10-K for further details about our significant customers. The inability orfailure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review thecredit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.Marketability of Our ProductionThe marketability of our production from the Mid-Continent and Rocky Mountain regions depends in part upon the availability, proximity andcapacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems and processing facilities. Wedeliver crude oil and natural gas produced from these areas through trucking services, pipelines and rail facilities that we do not own. The lack of availabilityor capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay ordiscontinuance of development plans for properties.A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, fieldlabor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted atthe same time, it could adversely affect our cash flow.Currently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara shale. Inaddition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this basin. If neither we nor a third-partyconstructs the required pipeline system and processing facility, we may not be able to fully test or develop our resources in the North Park Basin.79 Table of ContentsItem 8. Financial Statements and Supplementary DataREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and StockholdersBonanza Creek Energy Inc.We have audited the accompanying consolidated balance sheets of Bonanza Creek Energy Inc. and subsidiaries as of December 31, 2015 and 2014, and therelated consolidated statements of operations and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period endedDecember 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesefinancial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our auditsprovide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Bonanza Creek EnergyInc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2015, in conformity with U.S. generally accepted accounting principles.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Bonanza Creek Energy Inc.’sand subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated February 29, 2016 expressed anunqualified opinion on the effectiveness of Bonanza Creek Energy Inc.’s internal control over financial reporting./s/ Hein & Associates LLPDenver, ColoradoFebruary 29, 2016 80 Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS As of December 31, 2015 2014 (in thousands, except share data)ASSETS Current assets: Cash and cash equivalents$21,341 $2,584Accounts receivable: Oil and gas sales25,322 54,574Joint interest and other31,224 37,202Prepaid expenses and other4,078 12,522Inventory of oilfield equipment8,543 15,353Derivative asset29,566 86,240Total current assets120,074 208,475Property and equipment (successful efforts method), at cost: Proved properties1,618,970 1,924,380Less: accumulated depreciation, depletion and amortization(943,081) (592,073)Total proved properties, net675,889 1,332,307Unproved properties185,530 206,721Wells in progress51,196 139,208Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion andamortization of $636,917 in 2015 (note 3)214,922 —Natural gas plant, net of accumulated depreciation of $8,457 in 2014— 67,840Other property and equipment, net of accumulated depreciation of $9,407 in 2015 and $6,087 in 20149,729 10,401Total property and equipment, net1,137,266 1,756,477Long-term derivative asset— 17,765Other noncurrent assets16,027 23,372Total assets$1,273,367 $2,006,089LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued expenses (note 6)$96,360 $145,788Oil and gas revenue distribution payable27,613 40,659Contractual obligation for land acquisition12,000 12,000Total current liabilities135,973 198,447Long-term liabilities: Long-term debt (note 7)885,392 840,619Contractual obligation for land acquisition— 11,186Ad valorem taxes17,069 28,635Deferred income taxes— 165,667Asset retirement obligations14,935 21,464Asset retirement obligations for assets held for sale10,591 —Total liabilities1,063,960 1,266,018Commitments 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, 49,754,408 and 41,287,270 issued andoutstanding in 2015 and 2014, respectively49 41Additional paid-in capital806,386 591,511Retained earnings (deficit)(597,028) 148,519Total stockholders’ equity209,407 740,071Total liabilities and stockholders’ equity$1,273,367 $2,006,089The accompanying notes are an integral part of these consolidated financial statements 81 Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share data)Operating net revenues: Oil and gas sales $292,679 $558,633 $421,860Operating expenses: Lease operating expense 76,406 72,411 47,771Severance and ad valorem taxes 18,629 50,430 27,203Exploration 15,827 5,346 4,213Depreciation, depletion and amortization 244,921 228,789 140,176Impairment of oil and gas properties740,478167,592 —Abandonment and impairment of unproved properties 33,543 — —General and administrative (including $14,552, $20,716, and $12,638, respectively, ofstock-based compensation) 70,319 81,571 55,502Total operating expenses 1,200,123 606,139 274,865Income (loss) from operations (907,444) (47,506) 146,995Other income (expense): Derivative gain (loss) 56,558 121,615 (12,472)Interest expense (57,052) (46,447) (21,972)Other income (loss) (2,503) 345 (43)Total other income (expense) (2,997) 75,513 (34,487)Income (loss) from continuing operations before taxes (910,441) 28,007 112,508Current income tax expense (773) (149) (248)Deferred income tax benefit (expense) 165,667 (10,876) (42,678)Income (loss) from continuing operations $(745,547) $16,982 $69,582Discontinued operations: Loss from operations associated with oil and gas properties — (85) (644)Gain on sale of oil and gas properties — 5,496 —Income tax benefit (expense) — (2,110) 246Gain (loss) from discontinued operations — 3,301 (398)Net income (loss) $(745,547) $20,283 $69,184Comprehensive income (loss) $(745,547) $20,283 $69,184Basic income (loss) per share: Income (loss) from continuing operations $(15.57) $0.42 $1.73Income (loss) from discontinued operations $— $0.08 $(0.01)Net income (loss) per common share $(15.57) $0.50 $1.72Diluted income (loss) per share: Income (loss) from continuing operations$(15.57)$0.41 $1.72Income (loss) from discontinued operations$—$0.08 $(0.01)Net income (loss) per common share$(15.57)$0.49 $1.71Basic weighted-average common shares outstanding 47,874 40,139 39,337Diluted weighted-average common shares outstanding 47,874 40,290 39,403The accompanying notes are an integral part of these consolidated financial statements82 Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Additional Common Stock Paid-In Retained Shares Amount Capital Earnings Total (in thousands, except share data)Balances, January 1, 2013 40,115,536 $40 $519,426 $59,052 $578,518Restricted common stock issued, net of excessincome tax benefit 310,439 — 128 — 128Restricted common stock forfeited (31,817) — — — —Restricted stock used for tax withholdings (108,239) — (4,440) — (4,440)Stock-based compensation — — 12,638 — 12,638Net income — — — 69,184 69,184Balances, December 31, 2013 40,285,919 $40 $527,752 $128,236 $656,028Restricted common stock issued, net of excessincome 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 — 20,716Stock issued upon acquisition of oil and gasproperties 853,492 1 49,050 — 49,051Net income — — — 20,283 20,283Balances, December 31, 2014 41,287,270 $41 $591,511 $148,519 $740,071Restricted common stock issued 601,282 1 — — 1Restricted 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 — 326Sale of common stock 8,050,000 8 202,680 — 202,688Stock-based compensation — — 14,552 — 14,552Net loss — — — (745,547) (745,547)Balances, December 31, 2015 49,754,408 $49 $806,386 $(597,028) $209,407The accompanying notes are an integral part of these consolidated financial statements83 Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2015 2014 2013 (in thousands)Cash flows from operating activities: Net income (loss)$(745,547) $20,283 $69,184Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization244,921 228,856 140,547Deferred income taxes(165,667) 12,986 42,432Impairment of oil and gas properties740,478 167,592 —Abandonment and impairment of unproved properties33,543 — —Dry hole expense5,630 — 1,709Stock-based compensation14,552 20,716 12,638Amortization of deferred financing costs and debt premium2,280 1,588 1,505Accretion of contractual obligation for land acquisition814 1,153 761Derivative (gain) loss(56,558) (121,615) 12,472Gain on sale of oil and gas properties— (5,322) —Other1,429 (12) (8)Changes in current assets and liabilities: Accounts receivable35,230 (21,376) (26,315)Prepaid expenses and other assets8,444 (10,884) 1,394Accounts payable and accrued liabilities(23,655) 35,392 50,897Excess income tax benefit from the vesting of stock awards— — (128)Settlement of asset retirement obligations(867) (1,637) (73)Net cash provided by operating activities95,027 327,720 307,015Cash flows from investing activities: Acquisition of oil and gas properties(16,270) (179,566) (13,797)Deposits for acquisitions1,549 (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(425,918) (641,204) (417,835)Natural gas plant capital expenditures(112) (282) (5,202)Derivative cash settlements130,996 12,238 (11,330)(Increase) decrease in restricted cash2,987 (3,062) 79Additions to property and equipment - non oil and gas(2,809) (6,269) (5,138)Net cash used in investing activities(321,577) (824,994) (465,223)Cash flows from financing activities: Proceeds from credit facility137,000 263,000 102,000Payments to credit facility(91,000) (230,000) (260,000)Proceeds from sale of common stock209,308 — —Offering costs related to sale of common stock(6,620) — —Proceeds from sale of Senior Notes—300,000 500,000Offering costs related to sale of Senior Notes(99) (7,070) (11,721)Payment of employee tax withholdings in exchange for the return of common stock(2,683) (6,007) (4,440)Deferred financing costs(599) (647) (445)Premium on Senior Notes— — 9,000Excess income tax benefit from the vesting of stock awards— — 128Net cash provided by financing activities245,307 319,276 334,522Net change in cash and cash equivalents18,757 (177,998) 176,314Cash and cash equivalents: Beginning of period2,584 180,582 4,268End of period$21,341 $2,584 $180,582Supplemental cash flow disclosure: Cash paid for interest$54,566 $36,325 $12,86084 Table of ContentsStock issued for the acquisition of oil and gas properties$—$49,050 $—Stock issued for litigation settlement$326$— $—Cash paid for income taxes$820 $1,400 $100Contractual obligation for land acquisition$12,000 $22,033 $33,272Changes in working capital related to drilling expenditures, natural gas plant expenditures, andproperty acquisition$(50,385) $1,873 $29,273The accompanying notes are an integral part of these consolidated financial statements85 Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of OperationsBonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged primarily in acquiring, developing, exploiting and producing oil and gasproperties. As of December 31, 2015, the Company’s assets and operations were concentrated primarily in the Wattenberg Field in Colorado and in theDorcheat Macedonia Field in southern Arkansas.Basis of PresentationThe consolidated balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy OperatingCompany, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes EasternCompany, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated. In connection withthe preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2015,through the filing date of this report.Use of EstimatesThe preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the UnitedStates of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, anddisclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period.Actual results could differ from those estimates.Cash and Cash EquivalentsThe Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying valueof cash and cash equivalents approximate fair value due to the short-term nature of these instruments.Accounts ReceivableThe Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates.The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected andthe amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold futurerevenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months and theCompany has experienced minimal bad debts.Inventory of Oilfield EquipmentInventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of costor market, which approximates fair value.Oil and Gas Producing ActivitiesThe Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method ofaccounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination ofwhether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling thewell and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive ornonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred.Geological and geophysical costs are expensed as incurred.Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basisusing the units-of-production method based upon proved reserves.86 Table of ContentsThe Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of theassets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets net book value. If the net capitalized costsexceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’sjudgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on alldeveloped proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricingbased on our internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capitalexpenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flowsprojected.The Company assesses its unproved properties periodically for impairment on a property-by-property basis, which requires significant judgment.The Company considers the following factors in its assessment of the impairment of unproved properties:•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 toexpiration;•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 areasadjacent to or near its unproved properties;•its evaluation of the current fair market value of acreage; and•strategic shifts in development areas.For additional discussion, please refer to Note 4 - Impairments.The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with theretirement of a long-lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in theaccompanying consolidated balance sheets (“accompanying balance sheets”). For additional discussion, please refer to Note 11 - Asset RetirementObligations.Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within anexisting field that does not significantly affect the unit-of-production depletion rate will be accounted for as a normal retirement with no gain or lossrecognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted foras a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained.Natural Gas PlantsNatural gas plants are recorded at cost and depreciated using the straight-line method over a 30 year useful life. The Company assesses the facilitiesfor impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable and an impairment loss is recorded asnecessary.Other Property and EquipmentOther property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost ofrenewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred.Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three to ten years.87 Table of ContentsAssets Held for SaleAssets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will takeplace within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment isperformed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fairvalue less the costs to sell impact the measurement of assets held for sale. Any properties deemed held for sale as of the balance sheet date are presentedseparately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell. For additional discussion, please refer to Note 3 -Assets Held for Sale.Revenue RecognitionThe Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas and natural gasliquids ("NGLs") when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tanklifting has occurred. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company willreceive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenueestimates. Payment is generally received within 30 to 90 days after the date of production. The Company has interests with other producers in certainproperties in which case the Company uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as ofDecember 31, 2015 and 2014.For gathering and processing services, the Company either receives fees or commodities from natural gas producers depending on the type ofcontract. Under the percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and apercentage of the residue gas resulting from processing the natural gas. Commodities received are, in turn, sold and recognized as revenue in accordance withthe criteria outlined above.Income TaxesThe Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expectedfuture tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities aredetermined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year inwhich the differences are expected to reverse.Uncertain Tax PositionsThe Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2014, 2013 and 2012are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions.Concentrations of Credit RiskThe Company maintains cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit.The Company is exposed to credit risk in the event of nonpayment by counterparties whose creditworthiness is continuously evaluated. For the yearended December 31, 2015, Kaiser-Silo Energy Company accounted for 31%, Lion Oil Trading & Transportation, Inc. accounted for 16%, Plains MarketingLP accounted for 11% and Duke Energy Field Services accounted for 11%, of our oil and natural gas sales. For the years ended December 31, 2014 and 2013Plains Marketing LP accounted for 29% and 37%, respectively, Lion Oil Trading & Transportation, Inc. accounted for 19% and 23%, respectively, and HighSierra Crude Oil & Marketing accounted for 11% and 15%, respectively, of our oil and natural gas sales.Oil and Gas Derivative ActivitiesThe Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forwardcontracts. The contracts, which are generally placed with major financial institutions or with counterparties which management believes to be of high creditquality, may take the form of futures contracts, swaps, options, or collars. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts areindexed to NYMEX HH prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. TheCompany recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value. For additional discussion, please refer toNote 13 - Derivatives.88 Table of ContentsEarnings Per ShareEarnings per basic and diluted share are calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restrictedstock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share iscalculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-classmethod includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for theperiod. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated tocommon stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated to share in the losses of theCompany, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on the basis of the weighted-averagenumber of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using themore dilutive of the treasury method or two-class method. In periods of net loss, shares that are dilutive become anti-dilutive. For additional discussion,please refer to Note 14 - Earnings Per Share.Stock-Based CompensationThe Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value ofthe award. For additional discussion, please refer to Note 9 - Stock-Based Compensation.Fair Value of Financial InstrumentsThe Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, revolving creditfacility, senior notes, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables and accrued liabilities are carried at cost andapproximate fair value due to the short-term nature of these instruments. Our revolving credit facility has a variable interest rate so it approximates fair value.Our senior notes are recorded at cost, and their fair value is disclosed within Note 12 - Fair Value Measurements. Derivative instruments are recorded at fairvalue. The book value of the contractual obligation for land acquisition approximates fair value due to it being discounted at a market-based interest rate.Prior Year ReclassificationsCertain prior year balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on netincome (loss) or stockholders’ equity previously reported.Recently Issued and Adopted Accounting StandardsEffective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board ("FASB") Update No. 2014-08 -Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update was aimed at reducing the frequency of disposalsreported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results.Subsequent to adoption of this guidance, the Company determined that assets that were deemed as held for sale during 2015 did not qualify for discontinuedoperations. As such, the presentation within the accompanying balance sheets and the consolidated statements of operations and comprehensive income("accompanying statements of operations") reflect them as standard assets held for sale versus our California asset sales that occurred in 2014 and 2012 thatwere presented as discontinued operations. For additional discussion, please refer to Note 2 - Acquisitions and Divestitures and Note 3 - Assets Held for Sale.In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers. The update prescribes two acceptable methods andis effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company has started goingthrough its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company’s financialstatements or disclosures.In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That aPerformance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when anaward provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied eitherprospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company currently does nothave any awards that fall within this guidance, but will apply it if such an award is issued.89 Table of ContentsIn August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements - Going Concern that requires management toevaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after thedate that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and toprovide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods andinterim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact, butdoes not currently believe it will have a material effect on the Company’s financial statements or disclosures. In April 2015, the FASB issued Update No. 2015-03 – Interest – Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs. The updaterequires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of thatdebt liability. This authoritative accounting guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscalyears on a retrospective basis. The Company has taken the necessary steps to be ready for adoption of this update and does not currently believe it will have amaterial effect on the Company’s financial statements or disclosures.In July 2015, the FASB issued Update No. 2015-11 - Inventory. The update requires that inventory be measured at the lower of cost or net realizablevalue. This authoritative guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. The Companyis currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’sfinancial statements or disclosures.In August 2015, the FASB issued Update No. 2015-14 - Revenue from Contracts with Customers to defer the effective date of the new revenuerecognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods,beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning afterDecember 15, 2016. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will havea material effect on the Company’s financial statements or disclosures.In November 2015, the FASB issued Update No. 2015-17 - Income Taxes to simplify the presentation of deferred income taxes by classifyingdeferred tax assets and liabilities as noncurrent only. The new guidance is effective for annual periods, and interim periods within those annual periods,beginning after December 15, 2016. Early application is permitted. The Company has evaluated the provisions of this guidance and determined it will haveminimal impact on the Company’s financial statements and disclosures.In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets andfinancial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. Thisauthoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company is currentlyevaluating the provisions of this guidance and assessing its impact in relation to the Company's derivatives, but does not currently believe it will have amaterial effect on the Company’s financial statements or disclosures.NOTE 2 - ACQUISITIONS AND DIVESTITURESIn July 2014, the Company acquired approximately 34,000 net acres of oil and gas properties, leasehold mineral interests and related assets locatedin the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid approximately $174.6 million (inclusive of customaryacquisition costs) in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, forthe acquired assets. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014. The results of operations for theWattenberg Field Acquisition have been included in the Company’s consolidated financial statements from the date of closing. Pro forma information is notpresented as the pro forma results would not have been materially different from the information presented in the accompanying statements of operations dueto the lack of production and operating activities.The Wattenberg Field Acquisition was recorded using the purchase method of accounting. The following table summarizes the allocation ofconsideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition.90 Table of Contents Asset Valuation Amount (in thousands)Purchase price $223,678 Allocation of purchase price: Proved properties $25,014Unproved properties 198,757Asset retirement obligation (93)Total $223,678On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg Field from the State of Colorado, State Board ofLand Commissioners. The Company paid approximately $12.0 million at closing and $12.0 million in each of July 2013, July 2014, and July 2015. TheCompany will pay approximately $12.0 million in July 2016. The future payments were discounted based on our effective borrowing rate to arrive at thepurchase price of $57.0 million. Future payments include imputed interest and are secured by a $12.0 million letter of credit. Following each payment theamount secured by the letter of credit will be amended to reflect the reduction in obligation.Discontinued OperationsDuring June 2012, the Company sold the majority of its oil and gas properties in California classifying them as discontinued operations with itsremaining property being sold in the first quarter of 2014 for approximately $6.0 million. The Company recorded a gain on sale of oil and gas properties inthe amount of $5.5 million for the year ended December 31, 2014.NOTE 3 - ASSETS HELD FOR SALEAs of December 31, 2015, the accompanying balance sheets present $214.9 million of assets held for sale, net of accumulated depreciation,depletion and amortization, which consists of the Company’s Rocky Mountain Infrastructure, LLC subsidiary (“RMI”), all assets within the Company's Mid-Continent region and all assets in the North Park Basin that the Company no longer intends to develop given the current pricing environment. There is acorresponding asset retirement obligation liability of approximately $10.6 million for assets held for sale recorded in the asset retirement obligations forassets held for sale financial statement line item in the accompanying balance sheets. There were no other material assets or liabilities associated with theassets held for sale. For the year ended December 31, 2015, the Company recorded write-downs to fair value less estimated costs to sell of $321.2 million forits Mid-Continent region assets. These write-downs are recorded in the impairment of oil and gas properties line item in the accompanying statements ofoperations.The previously entered into and announced purchase agreement to divest of RMI was terminated by the company as it did not close. The Companyplans to re-market the assets.The Company adopted Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity onJanuary 1, 2015, which requires a disposal to represent a strategic shift that has a major effect on an entity's operations and financial results to qualify fordiscontinued operations. The Company determined that none of these potential asset sales qualify for discontinued operations accounting as they did notresult in a strategic shift of the Company.NOTE 4 - IMPAIRMENTSFor the year ended December 31, 2015, the Company impaired its assets held for sale within the Mid-Continent region to their fair value resulting inproved property impairments of $321.2 million and $419.3 million of proved property impairments in the Rocky Mountain region due to low commodityprices. The Company incurred unproved properties impairments of $24.8 million for non-core leases expiring within the Wattenberg Field and $8.7 millionof impairment charges to fully impair the North Park Basin due to a change in the Company's development plan during the year. For additional discussion,please refer to Note 12 - Fair Value Measurements.For the year ended December 31, 2014, the Company recorded proved property impairments of $127.3 million in the Dorcheat Macedonia Field dueto low commodity prices, $25.0 million of proved property impairments in the McKamie Patton Field due to low commodity prices and natural field decline,and $15.3 million of proved property impairments in the91 Table of ContentsMcCallum Field due to low commodity prices. The Company did not have any unproved property impairments for 2014, and did not have any proved orunproved property impairments in 2013.NOTE 5 - OTHER ASSETSThe Company has unamortized deferred financing costs related to the revolving credit facility and Senior Notes. As of December 31, 2015 2014 (in thousands)Certificates of deposit $— $228Restricted cash 241 3,000Deposit for acquisition of oil and gas properties — 1,549Deferred financing costs 15,786 18,595Other noncurrent assets $16,027 $23,372NOTE 6 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES Accounts payable and accrued expenses contain the following: As of December 31, 2015 2014 (in thousands)Drilling and completion costs$32,459 $82,844Accounts payable trade1,085 5,493Accrued general and administrative cost10,643 13,541Lease operating expense4,731 3,569Accrued reclamation cost162 162Accrued interest14,231 14,839Production and ad valorem taxes and other33,049 25,340Total accounts payable and accrued expenses$96,360 $145,788NOTE 7 - LONG-TERM DEBT Long-term debt consisted of the following as of December 31, 2015 and 2014: As of December 31, 2015 2014 (in thousands)Revolving credit facility$79,000 $33,0006.75% Senior Notes due 2021500,000 500,000Unamortized premium on 6.75% Senior Notes6,392 7,6195.75% Senior Notes due 2023300,000 300,000Total long-term debt$885,392 $840,619Revolving Credit Facility The revolving credit facility, dated March 29, 2011, as amended, with a syndication of banks, including KeyBank National Association as theadministrative agent and issuing lender, provides for borrowings of up to $1.0 billion. The revolving credit facility provides for interest rates plus anapplicable margin to be determined based on LIBOR or a base rate, at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.50% to2.50% depending on the utilization level,92 Table of Contentsand the base rate borrowings bear interest at the “Bank Prime Rate,” as defined in the revolving credit facility, plus 0.50% to 1.50%.On May 13, 2015, the revolving credit facility was amended (the “2015 Amendment”) to decrease the borrowing base from $600.0 million to $550.0million and subsequently amended on October 19, 2015 to decrease the borrowing base from $550.0 million to $475.0 million. The $475.0 millionborrowing base now equals the commitment level under the Credit Agreement. The borrowing base is redetermined semiannually no later than May 15 andNovember 15 and may be re-determined up to one additional time between such scheduled determinations upon request by the Company or lenders holding662/3% of the aggregate commitments. The revolving credit facility is collateralized by substantially all of the Company’s assets and matures onSeptember 15, 2017. As of December 31, 2015, the Company had $79.0 million outstanding under the revolving credit facility with an available borrowingcapacity of $384.0 million, after reduction for the outstanding letter of credit of $12.0 million. As of December 31, 2014, the Company had $33.0 millionoutstanding under the revolving credit facility with an available borrowing capacity of $543.0 million, if the Company elected to take advantage of theentire $600.0 million borrowing base available at that date, after reduction for the outstanding letter of credit of $24.0 million. For additional discussion onthe letter of credit, please refer to Note 2 - Acquisitions and Divestitures.The revolving credit facility restricts, among other items, certain dividend payments, additional indebtedness, asset sales, loans, investments andmergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, asdefined by the revolving credit facility. The 2015 Amendment (i) removed the maximum total debt to trailing twelve-month debt to earnings beforeinterest, income taxes, depreciation, depletion, and amortization, exploration expense and other non-cash charges (“EBITDAX”) covenant of 4.00 to 1.00 and(ii) introduced both a maximum senior secured debt (defined as borrowings under the revolving credit facility, balances drawn under letters of credit, and anyoutstanding second lien debt) to trailing twelve-month EBITDAX covenant of 2.50 to 1.00 and a minimum trailing twelve-month interest to trailing twelve-month EBITDAX coverage covenant of 2.50 to 1.00. The revolving credit facility also contains a minimum current ratio covenant of 1.00 to 1.00, where theavailable borrowing base is part of current assets. The Company was in compliance with all financial and non-financial covenants as of December 31, 2015,and through the filing date of this report.5.75% Senior NotesOn July 15, 2014, the Company issued $300.0 million aggregate principal amount of 5.75% Senior Notes that mature on February 1, 2023 (“5.75%Senior Notes”). Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and interest is payable on February 1 and August 1 of each year,beginning on February 1, 2015. The 5.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries thatincur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the 5.75% Senior Noteswere $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions.At any time prior to August 1, 2017, subject to certain limitations, the Company may redeem up to 35% of the aggregate principal amount of the5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than thenet cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a“make-whole” premium and accrued and unpaid interest. On or after August 1, 2018, the Company may redeem all or a part of the 5.75% Senior Notes at theredemption price of 102.875% for 2018, 101.438% for 2019, and 100.0% for 2020 and thereafter, during the twelve-month period beginning on August 1 ofeach applicable year, in each case, plus accrued and unpaid interest.6.75% Senior NotesOn April 9, 2013, the Company issued $300.0 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021 ("6.75%Senior Notes"). Interest on the Senior Notes began accruing on April 9, 2013, and interest is payable on April 15 and October 15 of each year, which began onOctober 15, 2013. On November 15, 2013, the Company issued an additional $200.0 million aggregate principal amount of 6.75% Senior Notes as anadditional issuance of its existing 6.75% Senior Notes. The 6.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing andfuture subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Company’s revolving credit facility. The net proceeds fromthe sale of the 6.75% Senior Notes were $496.7 million after the premium and deduction of $12.3 million of expenses and underwriting discounts andcommissions.At any time prior to April 15, 2016, the Company may redeem up to 35% of the aggregate principal amount at a redemption price of 106.75% of theprincipal amount, plus accrued and unpaid interest. The Company may redeem all or a part of the 6.75% Senior Notes at any time prior to April 15, 2017 atthe redemption price equal to 100% of the principal amount,93 Table of Contentsplus the applicable “make-whole” premium and accrued and unpaid interest. On or after April 15, 2017, the Company may redeem all or a part of the 6.75%Senior Notes at the redemption price of 103.375% for 2017, 101.688% for 2018, and 100.0% for 2019 and thereafter, during the twelve-month periodbeginning on April 15 of each applicable year, plus accrued and unpaid interest.On November 12, 2013 and July 15, 2014, the Company filed automatic registration statements on Form S‑3 to register the 5.75% Senior Notes and6.75% Senior Notes, respectively, (“5.75% Senior Notes” and, together with the “6.75% Senior Notes”, the “Senior Notes”) and guarantees of the SeniorNotes. As of December 31, 2015, all of the existing subsidiaries of the Company are guarantors of the Senior Notes, and all such subsidiaries are 100% ownedby the Company. The guarantees by the subsidiaries are full and unconditional (except for customary release provisions) and constitute joint and severalobligations of the subsidiaries. The Company has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. There areno significant restrictions on the Company’s ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as adividend or loan.NOTE 8 - COMMITMENTS AND CONTINGENCIESLegal Proceedings From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in theordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potentialaccrual in its consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when itsoccurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range ofpossible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highlysubjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningfulestimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or theongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of itsaccruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as itrelates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the filing date of this report, there were no materialpending or overtly threatened legal actions against the Company of which it is aware. CommitmentsIn October 2014, the Company entered into two purchase and transportation agreements to deliver fixed determinable quantities of crude oil. Thefirst agreement went into effect during the second quarter of 2015 for 12,580 barrels per day over an initial five-year term. The second agreement is currentlyanticipated to take effect in the fourth quarter of 2016 for 15,000 barrels per day over an initial seven-year term. The aggregate financial commitment fee is$503.7 million at December 31, 2015. While the volume commitment may be met with Company volumes or third-party volumes, delegated by theCompany, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. The Company rents office facilities under various non-cancelable operating lease agreements. The annual minimum payments on the transportationand operating lease agreements for the next five years and total minimum lease payments thereafter are presented below:94 Table of Contents Commitments (in thousands)2016 $69,2782017 92,3082018 92,3602019 92,4132020 55,3732021 and thereafter 114,976Total $516,708 The Company’s office leases extend through 2020. Rent expense for the years ended December 31, 2015, 2014 and 2013 was $2.6 million, $2.0million and $1.4 million, respectively. Subsequent to year-end, we entered into a minimum non-cancelable sublease for a total of $1.5 million payablethrough 2020.NOTE 9 - STOCK-BASED COMPENSATIONManagement Incentive PlanOn December 23, 2010, the Company established the Management Incentive Plan (the “Plan”) for the benefit of certain employees, officers andother individuals performing services for the Company. The maximum number of shares of Class B common stock available under the Plan was 10,000 andthese shares were converted into 437,787 shares of our restricted common stock upon completion of the Company’s initial public offering. The conversionrate was determined based on a formula factoring in the rate of return to the pre-IPO common stockholders. The 437,787 shares of common stock that weregranted were valued at the IPO stated price of $17.00 per share and vested over a three-year period. There was no stock-based compensation expense during2015, as all common stock granted under the Plan was fully vested as of December 31, 2014 with no unrecognized compensation remaining. Stock-basedcompensation expense of $4.8 million and $2.5 million was recorded during the years ended December 31, 2014 and 2013, respectively.BCEC Investment TrustThe BCEC Investment Trust was formed to hold shares of our common stock received by Bonanza Creek Energy Company, LLC, our predecessor, inconnection with our December 23, 2010 corporate restructuring. On February 5, 2013, 13,825 previously issued shares of our common stock that were fullyvested and held by the BCEC Investment Trust were distributed to former employees. While the shares had been issued in December 2010, for accountingpurposes, the date of distribution to former employees was considered the grant date, and these shares were valued at the closing price of our common stockon the grant date, which was $34.18 per share. On February 11, 2013, 59,372 previously issued shares of our common stock that were fully vested and held bythe BCEC Investment Trust were distributed to certain then current employees. While the shares had been issued in December 2010, for accounting purposes,the date of distribution to employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date,which was $34.89 per share. These distributions resulted in stock-based compensation expense of $2.5 million for the year ended December 31, 2013.Long Term Incentive PlanThe Company’s 2011 Long Term Incentive Plan, as amended and restated (the "LTIP"), has different forms of equity issuances allowed under it asfurther described in this section.Restricted Stock under the Long Term Incentive Plan The Company grants shares of restricted stock to directors, eligible employees and officers under its LTIP. Each share of restricted stock representsone share of the Company’s common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-thirdincrements over three years. Each share of restricted stock is entitled to a non-forfeitable dividend, if the Company were to declare one, and has the samevoting rights as a share of the Company’s common stock. Shares of restricted stock are valued at the closing price of the Company’s common stock on thegrant date and are recognized as general and administrative expense over the vesting period of the award. 95 Table of ContentsThe Company granted 568,832, 297,030 and 292,396 shares of restricted stock under the LTIP to certain employees during 2015, 2014 and 2013,respectively. The fair value of the restricted stock granted in 2015, 2014 and 2013 was $13.8 million, $13.9 million and $12.4 million, respectively. TheCompany recognized compensation expense of $11.1 million, $13.9 million and $6.9 million for the years ended December 31, 2015, 2014 and 2013,respectively. As of December 31, 2015 unrecognized compensation cost was $14.4 million and will be amortized through 2018.In 2015, 2014 and 2013, the Company issued 32,450, 12,919 and 18,043 shares, respectively, of restricted common stock under the LTIP to its non-employee directors. The Company recognized compensation expense of $0.7 million, $0.7 million and $0.4 million for the years ended December 31, 2015,2014 and 2013, respectively. These awards vest approximately one year after issuance.A summary of the status and activity of non-vested restricted stock is presented below: For the Years Ended December 31, 2015 2014 2013 RestrictedStock Weighted-AverageGrant-DateFair Value RestrictedStock Weighted-AverageGrant-DateFair Value RestrictedStock Weighted-AverageGrant-DateFair Value Non-vested at beginning of year589,529 $37.66 836,002 $25.11 929,336 $17.06Granted601,282 $24.04 309,949 $45.87 310,439 $39.89Vested(335,419) $32.09 (524,818) $25.95 (371,956) $17.44Forfeited(123,574) $34.86 (31,604) $32.73 (31,817) $24.09Non-vested at end of year731,818 $29.47 589,529 $37.66 836,002 $25.11Cash flows resulting from excess tax benefits are to be classified as part of cash flows from financing activities. Excess tax benefits are realized taxbenefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock.The Company recorded no excess tax benefits for the years ended December 31, 2015 and 2014. The Company recorded $0.1 million for the year endedDecember 31, 2013 as cash inflows from financing activities.Performance Stock Units under the Long Term Incentive PlanThe Company grants performance stock units (“PSUs”) to certain officers under its LTIP. The number of shares of the Company’s common stock thatmay be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. PSUs granted prior to 2014 are determined based on the Company’sperformance over a three-year measurement period and vest in their entirety at the end of the measurement period. Satisfaction of the performance conditionsfor the PSUs granted in 2014 and thereafter are determined at the end of each annual measurement period over the course of the three-year performance cyclein an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs maybe earned during the performance cycle). For all grants, the PSUs will be settled in shares of the Company’s common stock following the end of the three-yearperformance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The performance criterion for the PSUs isbased on a comparison of the Company’s total shareholder return (“TSR”) for the measurement period compared with the TSRs of a group of peer companiesfor the same measurement period. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurementperiod. 96 Table of ContentsThe fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is amathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iteratingthe equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict withcertainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company cancreate multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stockprice will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically theMonte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulationinclude the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurementperiod, as well as the volatilities for each of the Company’s peers.The following table presents the assumptions used to determine the fair value of the PSUs granted during the years ended December 31, 2015, 2014and 2013. For the For the Years Ended 2015 2014 2013Expected term of award3 3 3Risk-free interest rate0.15% - 0.99% 0.12% - 0.9% 0.4% - 0.9%Expected volatility65% 40% - 45% 40% During 2015, 2014 and 2013, the Company granted 144,363, 82,312 and 41,622 PSUs, respectively, under the LTIP to certain officers. The fairvalue of the PSUs granted in 2015, 2014 and 2013 was $4.8 million, $3.5 million and $1.2 million, respectively. The Company recognized compensationexpense of $2.8 million, $1.3 million and $0.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015,unrecognized compensation expense for PSUs was $4.7 million and will be amortized through 2018. A summary of the status and activity of PSUs is presented in the following table: For the Years Ended December 31, 2015 2014 2013 PSUWeighted-AverageGrant-DateFair Value PSU Weighted-AverageGrant-DateFair Value PSU Weighted-AverageGrant-DateFair ValueNon-vested at beginning of year(1)94,173 $37.55 40,191 $32.05 — $—Granted(1)144,363 $33.44 82,312 $41.94 41,622 $32.01Vested(1)(107,053) $34.84 (28,330) $42.50 — $—Forfeited(1)(16,650) $37.00 — $— (1,431) $30.85Non-vested at end of year(1)114,833 $35.27 94,173 $37.55 40,191 $32.05___________________________(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’scommon stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of theperformance condition.During the year ended December 31, 2015, PSUs awarded in 2013 and the second tranche of the 2014 awards were earned at a 1.00-times multiplierand 0.91-times multiplier, respectively, in accordance with the terms of the respective PSU awards. The earned shares are settled and released at the end of thethree-year performance cycle.During the year ended December 31, 2014, the first tranche of the PSUs awarded in 2014 , which were earned at a 1.33-times multiplier in accordancewith the terms of the PSU awards. The earned shares are settled and released at the end of the three-year performance cycle.401(k) PlanThe Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974.The 401(k) Plan allows eligible employees to contribute up to the contribution limits established under the IRC. The Company matches each employee’scontribution up to six percent of the employee’s base salary. The97 Table of ContentsCompany’s matching contributions to the 401(k) Plan were $1.9 million, $1.4 million and $0.8 million for the years ended December 31, 2015, 2014 and2013, respectively.NOTE 10 - INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable orrefundable currently or in future years related to cumulative temporary differences between the tax bases of assets and liabilities and amounts reported in theCompany’s balance sheet. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilitiesdetermines the periodic provision for deferred taxes. The provision for income taxes consists of the following: For the Years Ended December 31, 2015 2014 2013 (in thousands)Current tax expense (benefit) Federal $(192) $165 $122State 965 (16) 126Deferred tax expense (benefit) (165,667) 12,986 42,432Total income tax expense (benefit) $(164,894) $13,135 $42,680Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred taxliability result from the following components: As of December 31, 2015 2014 (in thousands)Deferred tax liabilities: Oil and gas properties $— $201,635Derivative asset 11,328 40,060Total deferred tax liabilities 11,328 241,695Deferred tax assets: Federal and state tax net operating loss carryforward 82,013 59,952Oil and gas properties 93,712 —Reclamation costs 9,907 8,344Stock compensation 3,907 3,845AMT credit 402 812State bonus depreciation addback 1,613 2,083Other long-term liabilities 322 992Total deferred tax assets 191,876 76,028Less: Valuation allowance 180,548 —Total deferred tax assets after valuation allowance 11,328 76,028Total non-current net deferred tax liability $— $165,667The Company has $218.7 million and $177.3 million of net operating loss carryovers for federal income tax purposes of which $14.5 million is notrecorded as a benefit for financial statement purposes as it relates to tax deductions that are different from the stock-based compensation expense recorded forfinancial statement purposes as of December 31, 2015 and 2014, respectively. The federal net operating loss carryforward begins to expire in 2031. Thebenefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable.98 Table of ContentsFederal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate toincome before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences, as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands)Federal statutory tax expense (benefit) $(318,654) $11,696 $39,152Increase (decrease) in tax resulting from: State tax expense net of federal benefit (30,178) 1,106 3,834Rate change and other 3,390 333 (306)Valuation allowance 180,548 — —Total income tax expense (benefit) $(164,894) $13,135 $42,680Reconciliation of the Company’s effective tax rate to the expected federal tax rate of 35% in 2015, 2014, and 2013 is as follows: For the Years Ended December 31, 2015 2014 2013Expected federal tax rate 35.00 % 35.00% 35.00 %State income taxes 3.31 % 3.29% 3.43 %Change in tax rate (0.37)% 1.01% (0.28)%Valuation allowance (19.83)% —% — %Effective tax rate 18.11 % 39.30% 38.15 %During the year ended December 31, 2015, the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets.Total deferred income tax benefit in the accompanying statements of operations is $165.7 million. The valuation allowance increased by $181.7 million in2015.During the year ended December 31, 2014, the increase in tax rate was primarily due to an increase in permanent differences. Total deferred incometax expense in the accompanying statements of operations is $13.0 million.During the year ended December 31, 2013, the decrease in tax rate was primarily due to a decrease in taxable income apportioned to California andArkansas and an increase in taxable income apportioned to Colorado. The decrease in the effective tax rate with the change in tax rate was applied to theJanuary 1, 2013 deferred income tax liability resulting in a decrease to the net deferred tax liability and deferred income tax expense of $0.4 million. Thetotal deferred income tax expense in the accompanying statements of operations was $42.4 million.The Company had no unrecognized tax benefits as of December 31, 2015, 2014 and 2013. NOTE 11 - ASSET RETIREMENT OBLIGATIONSThe Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligationis recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to thecarrying value of the asset which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amountadded to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives ofthe properties.99 Table of ContentsThe Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives,estimated costs to abandon the wells and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time theliability is incurred and ranges from 8% to 18%. A reconciliation of the Company’s asset retirement obligation is as follows: As of December 31, 2015 2014 (in thousands)Beginning of year $21,626 $11,218Additional liabilities incurred 560 4,190Accretion expense 1,944 1,382Obligations on properties sold — (833)Liabilities settled (469) (557)Revisions to estimate 2,027 6,226End of year $25,688 $21,626Revisions to the liability could occur due to changes in the estimated economic lives, abandonment costs of the wells, inflation rates, credit-adjusted risk-free rates, along with newly enacted regulatory requirements. In 2015, accretion expense increased over 2014 primarily due to the increase inthe credit-adjusted risk-free rate, as well as an increased well count from the drilling and completion of new wells in the current year and from the wells addedwith the Wattenberg Field Acquisition in 2014. Revisions to estimates for the year ended December 31, 2015 were a result of decreased estimated economicwell lives coupled with an increase in the inflation rate on wells that had an asset retirement obligation as of the beginning of the year. For each of the years ended December 31, 2015 and 2014, the Company has accrued approximately $0.2 million of asset retirement obligations inaccounts payable and accrued expenses on the accompanying balance sheets. The Company has accrued $10.6 million of asset retirement obligations in theasset retirement obligations for assets held for sale on the accompanying balance sheets for the year ended December 31, 2015.For additional discussion, please refer to Note 6 - Accounts Payable and Accrued Expenses.NOTE 12 - FAIR VALUE MEASUREMENTS The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value tomeasure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the pricethat would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Thestatement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservableinputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing theasset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect theCompany’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in thecircumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets thatare not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observableLevel 3: Significant inputs to the valuation model are unobservable Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair valuemeasurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect thevaluation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.100 Table of Contents The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31,2015 and 2014 and their classification within the fair value hierarchy: As of December 31, 2015 Level 1 Level 2 Level 3 (in thousands)Derivative assets(1)$— $29,566 $—Proved properties(2)$— $— $811,913Unproved properties(2)$— $— $185,530Asset retirement obligations(3)$— $— $2,027 As of December 31, 2014 Level 1 Level 2 Level 3 (in thousands)Derivative assets(1)$— $104,005 $—Proved properties(2)$— $— $407,900Asset retirement obligations(3)$— $— $6,226_______________________________(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 thatwas subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Proved Oiland Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion.(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 anonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion. Derivatives Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forwardprices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as otherrelevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’scommodity swaps and collars are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and aredesignated as Level 2 within the valuation hierarchy. As of December 31, 2015, all derivative arrangements were concentrated with four counterparties, all ofwhich are lenders under the Company’s revolving credit facility. Subsequent to year end, the derivative arrangements were concentrated with threecounterparties, all of which are lenders under the Company's revolving credit facility. Proved Oil and Gas PropertiesProved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceedthe sum of the undiscounted cash flows. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique,which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of risk-adjusteddiscount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discountrate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representativeof current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/ortiming of cash flows, the risk premium and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from theNYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for theseestimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price,101 Table of Contentsas evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the incomevaluation technique discussed above. The Company impaired the Mid-Continent region which had a carrying value of $431.2 million to its fair value of$110.0 million and recognized an impairment of $321.2 million for the year ended December 31, 2015. The Company impaired the Rocky Mountain regionwhich had a carrying value of $1,121.2 million to its fair value of $701.9 million and recognized an impairment of $419.3 million for the year endedDecember 31, 2015. The Company impaired the Dorcheat Macedonia Field which had a carrying value of $519.2 million to its fair value of $391.9 millionand recognized an impairment of $127.3 million for the year ended December 31, 2014. The Company impaired the McKamie Patton Field which had acarrying value of $41.0 million to its fair value of $16.0 million and recognized an impairment of $25.0 million for the year ended December 31, 2014. TheCompany impaired the McCallum Field which had a carrying value of $15.3 million to its fair value of zero and recognized an impairment of $15.3 millionfor the year ended December 31, 2014. For additional discussion on impairments, please refer to Note 4 - Impairments. Unproved Oil and Gas Properties Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs maynot be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, whichtakes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life andestimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidencedby the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company uses the price received for similaracreage in recent transactions by the Company or other market participants in the principal market. The Company impaired non-core acreage in theWattenberg Field due to lease expirations, which had a carrying value of $210.3 million to its fair value of $185.5 million and recognized an impairment ofunproved properties for the year ended December 31, 2015 of $24.8 million. The Company also fully impaired the North Park Basin in June 2015, due to achange in the Company’s development plan, recognizing an impairment of unproved properties of $8.7 million. There were no unproved properties measuredat fair value as of December 31, 2014. Asset Retirement Obligation The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inceptionby applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, tothe undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation atfair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability isdeemed to use Level 3 inputs. The Company had $2.0 million and $6.2 million of asset retirement obligations recorded at fair value as of December 31, 2015and 2014, respectively. Long-term Debt As of December 31, 2015, the Company had $500.0 million of outstanding 6.75% Senior Notes and $300.0 million of outstanding 5.75% SeniorNotes, all of which are unsecured senior obligations. The 6.75% Senior Notes are recorded at cost, plus the unamortized premium, on the accompanyingbalance sheets at $506.4 million and $507.6 million as of December 31, 2015 and 2014, respectively. The fair value of the 6.75% Senior Notes as ofDecember 31, 2015 and 2014 was $301.3 million and $440.0 million, respectively. The 5.75% Senior Notes are recorded at cost on the accompanyingbalance sheets at $300.0 million as of December 31, 2015 and 2014. The fair value of the 5.75% Senior Notes as of December 31, 2015 and 2014 was $163.1million and $243.0 million, respectively. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’srevolving credit facility approximates fair value as the applicable interest rates are floating. The outstanding balance under the revolving credit facility as ofDecember 31, 2015 and 2014 was $79.0 million and $33.0 million, respectively. NOTE 13 - DERIVATIVES The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodityprices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps andcollar arrangements for oil and none of the derivative instruments qualify as having hedging relationships.102 Table of ContentsIn a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, the Companyreceives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company paysthe difference. If the index price is below the strike price of our short-puts associated with the Company’s three-way collars, the Company will receive apayment from our hedging counterparty equal to the difference between the strike prices of the short-put and long-put multiplied by the monthly volumeassociated with the three-way collar.As of December 31, 2015, and as of the filing date of this report, the Company had the following derivative commodity contracts in place: SettlementPeriod DerivativeInstrument Total Volumes(Bbls per day) AverageShort FloorPrice AverageFloorPrice AverageCeilingPrice Fair MarketValue of Assets (in thousands)Oil 2016 3-Way Collar 5,500 $70.00 $85.00 $96.83 $29,566Total $29,566 Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets andliabilities. The following tables contain a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of December 31,2015 and 2014: As of December 31, 2015 Balance Sheet Location Fair Value (in thousands)Derivative Assets: Commodity contractsCurrent assets $29,566Commodity contractsNoncurrent assets —Derivative Liabilities: Commodity contractsCurrent liabilities —Commodity contractsLong-term liabilities —Total derivative asset $29,566 As of December 31, 2014 Balance Sheet Location Fair Value (in thousands)Derivative Assets: Commodity contractsCurrent assets $86,240Commodity contractsNoncurrent assets 17,765Derivative Liabilities: Commodity contractsCurrent liabilities —Commodity contractsLong-term liabilities —Total derivative asset $104,005The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations:103 Table of Contents For the Years Ended December 31, 2015 2014 2013 (in thousands)Derivative cash settlement gain (loss): Oil contracts(1) $128,258 $11,523 $(11,755)Gas contracts 2,738 715 425Total derivative cash settlement gain (loss)(2) $130,996 $12,238 $(11,330) Change in fair value gain (loss) $(74,438) $109,377 $(1,142) Total derivative gain (loss)(3) $56,558 $121,615 $(12,472)___________________________(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 fourthquarters of 2015, to two-way collars.(2)Derivative cash settlement gain (loss) for the years ended December 31, 2015, 2014 and 2013 is reported in the derivative cash settlements line item onthe accompanying statements of cash flows within the net cash used in investing activities.(3)Total derivative gain (loss) for the years ended December 31, 2015, 2014 and 2013 is reported in the derivative (gain) loss line item on theaccompanying statements of cash flows within the net cash provided by operating activities. NOTE 14 - EARNINGS PER SHARE The Company issues shares of restricted stock entitling the holders to receive non-forfeitable dividends, if and when, the Company was to declare adividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-classmethod. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders and losses tocommon shareholders only. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company’s common stockthat range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on thenumber of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the measurement periodapplicable to such PSUs. Please refer to Note 9 - Stock-Based Compensation for additional discussion.104 Table of ContentsThe following table sets forth the calculation of income (loss) per basic and diluted shares from continuing and discontinued operations and netincome (loss) for the years ended December 31, 2015, 2014 and 2013: For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share amounts)Income (loss) from continuing operations: Income (loss) from continuing operations $(745,547) $16,982 $69,582Less: undistributed income (loss) to unvested restricted stock — 315 1,673Undistributed income (loss) to common shareholders (745,547) 16,667 67,909Basic income (loss) per common share from continuing operations $(15.57) $0.42 $1.73Diluted income (loss) per common share from continuing operations $(15.57) $0.41 $1.72 Income (loss) from discontinued operations: Income (loss) from discontinued operations $— $3,301 $(398)Less: undistributed income (loss) to unvested restricted stock — 62 (10)Undistributed income (loss) to common shareholders — 3,239 (388)Basic income (loss) per common share from discontinued operations $— $0.08 $(0.01)Diluted income (loss) per common share from discontinued operations $— $0.08 $(0.01) Net income (loss): Net income (loss) $(745,547) $20,283 $69,184Less: undistributed income (loss) to unvested restricted stock — 377 1,663Undistributed income (loss) to common shareholders (745,547) 19,906 67,521Basic net income (loss) per common share $(15.57) $0.50 $1.72Diluted net income (loss) per common share $(15.57) $0.49 $1.71 Weighted-average shares outstanding - basic 47,874 40,139 39,337Add: dilutive effect of contingent PSUs — 151 66Weighted-average shares outstanding - diluted 47,874 40,290 39,403The Company was in a net loss position for the year ended December 31, 2015, which made the 277,634 potentially dilutive shares, anti-dilutive.The Company had no anti-dilutive shares for the years ended December 31, 2014 and 2013. The participating shareholders are not contractually obligated toshare in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding common shareholders.NOTE 15 - CAPITAL STOCK On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.7 millionafter deducting underwriter discounts, commissions and offering expenses of approximately $6.6 million. The Company used a portion of the net proceeds torepay all of the then outstanding borrowings under its revolving credit facility and for general corporate purposes, including its drilling and developmentprogram and other capital expenditures.NOTE 16 - OIL AND GAS ACTIVITIESThe Company’s oil and natural gas activities are entirely within the United States. Costs incurred in oil and natural gas producing activities are asfollows:105 Table of Contents For the Years Ended December 31, 2015 2014 2013 (in thousands)Acquisition(1) $16,270 $228,616 $13,797Development(2)(3) 393,187 659,633 452,455Exploration 6,284 5,345 2,590Total(4) $415,741 $893,594 $468,842_________________________(1)Acquisition costs for unproved properties for the years ended December 31, 2015, 2014 and 2013 were $15.3 million, $202.7 million and $3.4 million,respectively. Acquisition costs for proved properties for the years ended December 31, 2015, 2014 and 2013 were $1.0 million, $25.9 million and $10.4million, respectively.(2)Development costs include workover costs of $10.0 million, $9.8 million and $6.0 million charged to lease operating expense during the years endedDecember 31, 2015, 2014 and 2013, respectively.(3)Development costs include gas plant capital expenditures of $0.1 million and $4.3 million for the years ended December 31, 2015 and 2013,respectively.(4)Includes amounts relating to asset retirement obligations of $2.4 million, $6.3 million and $2.8 million for the years ended December 31, 2015, 2014 and2013, respectively.Suspended Well CostsDuring the year ended December 31, 2015, the Company incurred $9.5 million of drilling costs for three exploratory wells, one of which was locatedin the North Park Basin and the other two were outside of the Company's current development area in southern Arkansas and deemed them all dry holes bythe end of 2015. During the year ended December 31, 2014, the Company incurred drilling costs for one exploratory well of $1.0 million and deemed it a dryhole by the end of 2014. During the year ended December 31, 2013, the Company incurred drilling costs for one exploratory well of $0.6 million and deemedit a dry hole by the end of 2013.NOTE 17 - DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)The proved reserve estimates at December 31, 2015 and 2014 are internally generated with an audit performed by NSAI, our third party independentreserve engineers, whereas the December 31, 2013 proved reserve estimates were prepared by NSAI. The estimates of proved reserves are inherently impreciseand are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.106 Table of ContentsAll of BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changesin quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2015, 2014 and 2013 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl)(1) (MMcf) (MBbl)(1)Balance-December 31, 2012 33,266 118,548 —Extensions and discoveries(2) 20,123 59,936 —Production (4,257) (9,976) —Purchases of minerals in place 1,228 3,958 —Revisions to previous estimates(3) (3,878) (32,852) —Balance-December 31, 2013 46,482 139,614 —Extensions and discoveries(2) 13,222 41,963 —Sales of minerals in place (43) (73) —Production (6,018) (14,114) —Purchases of minerals in place 709 1,214 —Revisions to previous estimates(3) 3,760 19,947 —Balance-December 31, 2014 58,112 188,551 —Three stream conversion adjustment (3,352) — 3,352Extensions and discoveries(2) 6,936 15,849 2,430Production (6,072) (14,110) (1,676)Purchases of minerals in place 719 3,521 234Revisions to previous estimates(3) 1,050 (49,584) 15,578Balance-December 31, 2015 57,393 144,227 19,918Proved developed reserves: December 31, 2013 22,273 59,250 —December 31, 2014 30,542 94,494 —December 31, 2015 28,892 77,480 10,359Proved undeveloped reserves: December 31, 2013 24,209 80,364 —December 31, 2014 27,570 94,057 —December 31, 2015 28,501 66,747 9,559________________________(1)Natural gas liquid reserves were classified with oil reserves through December 31, 2014. Natural gas liquids are separately accounted for effective as ofJanuary 1, 2015, resulting in three-stream presentation. Effective January 1, 2015 the Company revised the agreements with its natural gas processors inthe Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from thenatural 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, 2015, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of11,708 MBoe, which is 97% of our total additions of 12,008 MBoe. The remainder of the additions were the result of vertical drilling during the year inthe Dorcheat Macedonia Field, Mid-Continent region.At December 31, 2014, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of18,980 MBoe, which is 94% of our total additions of 20,216 MBoe. The remainder of the additions came from our Dorcheat Madedonia Field, Mid-Continent region.107 Table of ContentsAt December 31, 2013, horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of28,908 MBoe, which is 96% of our total additions of 30,112 MBoe. The remainder of the additions came from our Dorcheat Madedonia and McKamiePatton Fields, Mid-Continent region.(3)As of December 31, 2015, the Company revised its proved reserves upward by 8,364 Mboe. The Company was successful in offsetting the negativepricing revision of 28,810 Mboe that resulted from a decrease in commodity price from $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year endedDecember 31, 2014 to $50.28 per Bbl WTI and $2.59 per MMBtu HH for the year ended December 31, 2015, by reducing the costs to drill and completewells in both the Rocky Mountain and Mid-Continent regions and improving reserves by increasing productivity of proved developed producing wellsin the Wattenberg Field horizontal program. Total positive engineering revisions as of December 31, 2015, were 37,174 MBoe, of which 30,086 MBoe(81%) related to reserve changes in the Wattenberg Field. In the Wattenberg Field, the majority of the positive revisions resulted from a combination ofdecreased drilling and completion costs of 29% ($3.0 million per standard reach lateral well as of December 31, 2015 compared to $4.2 million as ofDecember 31, 2014) and an increase in productivity from horizontal proved developed producing wells which increased the offsetting provedundeveloped reserves. The increase in proved developed producing reserves is primarily attributed to the installation of infrastructure in the east side ofthe Wattenberg Field. Another significant contribution to the positive reserve revision in the Wattenberg Field is a contract change as of January 1, 2015which gives the Company ownership of the natural gas liquids from the Company's gas production. This conversion from two stream (wet gas and oil) tothree stream (dry gas, natural gas liquids and oil) added 8,560 MBoe to the Company's proved reserves as of December 31, 2015.As of December 31, 2014, we revised our proved reserves upward by 7,333 Mboe, excluding pricing revisions, due primarily to the addition of 49 newproved undeveloped locations on 80-acre spacing, directly offsetting economic proved producing wells drilled prior to 2014, 21 diagonal offsets toeconomic proved producing wells and 12 proved undeveloped locations greater than one offset to economic proved producing wells but withindeveloped areas and surrounded by proved producing wells. As of December 31, 2014, approximately 70% of our horizontal development in theWattenberg Field was in the Niobrara B formation. A total of 119 horizontal proved undeveloped locations were added to the proved reserves atDecember 31, 2014 to either extensions and discoveries or revisions to previous estimates. The positive engineering revision was offset by a smallnegative performance revision of approximately 540 MBoe. A small negative pricing revision of 248 MBoe resulted from a decrease in averagecommodity price from $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 perMMBtu HH for the year ended December 31, 2014. At December 31, 2013, we revised our proved reserves downward by 9,867 MBoe, excluding pricing revisions, due primarily to the change in focus fromvertical to horizontal development in the Wattenberg Field. This accounted for 69% of the downward revision and included the elimination of 45 netvertical locations from proved undeveloped, the elimination of all proved non‑ producing reserves associated with vertical well refracs andrecompletions, and lower performance from the vertical producers due to increased line pressure. The high line pressure also affected the horizontalreserves creating a negative revision of 1.8 MMBoe, or 18% of the total downward revision. We had a small positive pricing revision of 514 MBoe froman increase in commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and$3.67 per MMBtu HH for the year ended December 31, 2013. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance withaccounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production anddevelopment costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on costs and assuming continuation of existing economic conditions.Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil andnatural gas reserves. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and naturalgas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. Thiscalculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company's oil and natural gas properties.108 Table of ContentsThe standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands)Future cash flows $3,122,574 $5,780,745 $4,799,149Future production costs (1,706,607) (2,257,572) (1,681,419)Future development costs (697,045) (952,041) (776,512)Future income tax expense — (457,625) (576,024)Future net cash flows 718,922 2,113,507 1,765,19410% annual discount for estimated timing of cash flows (391,106) (1,006,131) (839,911)Standardized measure of discounted future net cash flows $327,816 $1,107,376 $925,283Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end.The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands)Beginning of period $1,107,376 $925,283 $683,441Sale of oil and gas produced, net of production costs (197,643) (435,792) (346,679)Net changes in prices and production costs (1,117,624) (331,930) 94,881Extensions, discoveries and improved recoveries 76,429 492,144 571,384Development costs incurred 84,180 116,958 67,063Changes in estimated development cost 178,003 (15,131) 127,034Purchases of minerals in place (971) 30,919 5,442Sales of minerals in place — (1,173) —Revisions of previous quantity estimates (170,277) 122,169 (212,034)Net change in income taxes 233,086 68,856 (150,704)Accretion of discount 134,046 122,722 83,468Changes in production rates and other 1,211 12,351 1,987End of period $327,816 $1,107,376 $925,283The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2015, 2014and 2013 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2015 2014 2013Oil (per Bbl) $44.00 $84.28 $92.03Gas (per Mcf) $2.33 $5.24 $4.67Natural gas liquids (per Bbl) $12.90 N/A N/A109 Table of ContentsNOTE 18 - QUARTERLY FINANCIAL DATA (UNAUDITED)The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2015 and 2014: Three Months Ended March 31 June 30 September 30 December 31 (in thousands, except per share data)2015 Oil and gas sales $73,076 $90,422 $72,149 $57,032Operating 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)2014 Oil and gas sales(2) $127,395 $151,682 $156,371 $123,185Operating profit(1)(2) 58,432 63,284 59,579 25,707Net income (loss) 13,531 1,158 48,782 (43,188)Basic net income (loss) per common share $0.34 $0.03 $1.18 $(1.05)Diluted net income (loss) per common share $0.34 $0.03 $1.18 $(1.06)_________________________(1)Oil and gas sales less lease operating expense, severance and ad valorem taxes, depreciation, and depletion and amortization.(2)Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold as ofDecember 31, 2014.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.None. Item 9A. Controls and Procedures.Evaluation of Disclosure Controls and ProceduresOur management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of ourdisclosure controls and procedures as of December 31, 2015. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e)under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by acompany in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified inSEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required tobe disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management,including its principal executive and principal financial officers and internal audit function, as appropriate to allow timely decisions regarding requireddisclosure. Based on the evaluation of our disclosure controls and procedures as of December 31, 2015, our principal executive officer and principal financialofficer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance ofachieving their objectives and management necessarily applies its judgment in evaluating the cost‑benefit relationship of possible controls and procedures.To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internalcontrol system is supported by written policies and procedures, contains self-monitoring mechanisms and is audited by the internal audit function.Appropriate actions are taken by management to correct deficiencies as they are identified.Management’s Assessment of Internal Control Over Financial ReportingThe Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined inExchange Act Rule 13a-15(f). The Company’s internal control over financial reporting is a process110 Table of Contentsdesigned under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding thereliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principlesgenerally accepted in the United States. Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or processes may deteriorate.As of December 31, 2015, management assessed the effectiveness of our internal control over financial reporting based on the criteria for effectiveinternal control over financial reporting established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of theTreadway Commission in 2013. Based on the assessment, management determined that the Company maintained effective internal control over financialreporting as of December 31, 2015, based on those criteria. Management included in its assessment of internal control over financial reporting allconsolidated entities.Hein & Associates LLP, the independent registered public accounting firm that audited the consolidated financial statements included in thisAnnual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2015, whichis included in the consolidated financial statements in Item 8, Part II of this Annual Report on Form 10-K.Changes in Internal Control over Financial ReportingThere were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the year ended December 31, 2015 that materially affected, or are reasonably likely to materially affect, our internal controlover financial reporting.REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and StockholdersBonanza Creek Energy Inc.We have audited Bonanza Creek Energy Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in InternalControl - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Bonanza Creek Energy Inc.’smanagement is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal controlover financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to expressan opinion on the company’s internal control over financial reporting based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all materialrespects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, andtesting and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such otherprocedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.111 Table of ContentsIn our opinion, Bonanza Creek Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015,based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissionin 2013.We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheetsof Bonanza Creek Energy, Inc. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations and comprehensiveincome, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015, and our report dated February 29, 2016expressed an unqualified opinion./s/ Hein & Associates LLPDenver, ColoradoFebruary 29, 2016Item 9B. Other Information.None.112 Table of ContentsPART IIIItem 10. Directors, Executive Officers and Corporate Governance.The information required by this item is incorporated by reference to Bonanza Creek Energy, Inc.’s Proxy Statement for its 2016 Annual Meeting ofStockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2015.Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is available onour website (www.bonanzacrk.com) under “Corporate Governance” under the “For Investors” tab. We will provide a copy of this document to any person,without charge, upon request, by writing to us at Bonanza Creek Energy, Inc., Investor Relations, 410 17th Street, Suite 1400, Denver, Colorado 80202. Weintend to satisfy the disclosure requirement under Item 406(c) of Regulation S‑K regarding an amendment to, or waiver from, a provision of our Code ofBusiness Conduct and Ethics by posting such information on our website at the address and the location specified above.Item 11. Executive Compensation.The information required by this item is incorporated by reference to Bonanza Creek Energy, Inc.’s Proxy Statement for its 2016 Annual Meeting ofStockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2015.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.The information required by this item is incorporated by reference to Bonanza Creek Energy, Inc.’s Proxy Statement for its 2016 Annual Meeting ofStockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2015.Item 13. Certain Relationships and Related Transaction and Director Independence.The information required by this item is incorporated by reference to Bonanza Creek Energy, Inc.’s Proxy Statement for its 2016 Annual Meeting ofStockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2015.Item 14. Principal Accounting Fees and Services.The information required by this item is incorporated by reference to Bonanza Creek Energy, Inc.’s Proxy Statement for its 2016 Annual Meeting ofStockholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2015.113 Table of ContentsPART IVItem 15. Exhibits, Financial Statement Schedules.(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:See Item 8. Financial Statements and Supplementary Data.(2)Financial Statement Schedules:None.(3)Exhibits:The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report onForm 10-K.114 Table of ContentsSIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed onits behalf by the undersigned, thereunto duly authorized. BONANZA CREEK ENERGY, INC. By:/s/ Richard J. Carty Richard J. Carty, President and Chief Executive Officer(principal executive officer) February 29, 2016KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Richard J. Carty, William J.Cassidy, Christopher I. Humber and Wade E. Jaques and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power toact with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any orall amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and ExchangeCommission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of theundersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposesand as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes maylawfully do or cause to be done by virtue hereof.115 Table of ContentsPursuant to the requirements of the Securities Exchange Act of 1934, this annual report has been signed by the following persons on behalf of theregistrant and in the capacities and on the dates indicated.Date:February 29, 2016By:/s/ Richard J. Carty Richard J. Carty,President, Chief Executive Officer, and Director(principal executive officer)Date:February 29, 2016By:/s/ William J. Cassidy William J. Cassidy,Executive Vice President and Chief Financial Officer(principal financial officer)Date:February 29, 2016By:/s/ Wade E. Jaques Wade E. Jaques,Vice President and Chief Accounting Officer (principal accounting officer)Date:February 29, 2016By:/s/ James A. Watt James A. Watt,Chairman of the BoardDate:February 29, 2016By:/s/ Marvin M. Chronister Marvin M. Chronister,DirectorDate:February 29, 2016By:/s/ Kevin A. Neveu Kevin A. Neveu,DirectorDate:February 29, 2016By:/s/ Gregory P. Raih Gregory P. Raih,DirectorDate:February 29, 2016By:/s/ Jeff E. Wojahn Jeff E. Wojahn,Director116 Table of ContentsINDEX TO EXHIBITSExhibitNumberDescription3.1Second Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc., filed with the Secretary of State of theState of Delaware on December 16, 2011 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8‑K filed onDecember 22, 2011)3.2Third Amended and Restated Bylaws of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Current Reporton Form 8‑K filed on August 1, 2013)4.1Form of Senior Debt Indenture (incorporated by reference to Exhibit 4.4 to the Registration Statement on Form S‑3 filed onJanuary 15, 2013)4.2Form of Subordinated Debt Indenture (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S‑3 filed onJanuary 15, 2013)4.3Registration Rights Agreement, dated April 9, 2013, among Bonanza Creek Energy, Inc., the guarantors named therein and WellsFargo Securities, LLC, as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.2 of theCurrent Report on Form 8‑K filed on April 11, 2013)4.4Indenture, 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)4.5Indenture, 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)4.6First Supplemental Indenture, dated July 18, 2014, among Bonanza Creek Energy, Inc., the subsidiary guarantors named therein andWells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filedon July 18, 2014)4.7First Supplemental Indenture, dated January 27, 2015, among Rocky Mountain Infrastructure, LLC, Bonanza Creek Energy, Inc., thesubsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.7to the Annual Report on Form 10-K filed on February 27, 2015).4.8Second 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 Exhibit4.8 to the Annual Report on Form 10-K filed on February 27, 2015).10.1Credit Agreement, dated as of March 29, 2011, among Bonanza Creek Energy, Inc., BNP Paribas, as Administrative Agent, and thelenders party thereto (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S‑1 filed on June 7, 2011)10.2Amendment No. 1, dated as of April 29, 2011, to the Credit Agreement, among Bonanza Creek Energy, Inc., BNP Paribas, asAdministrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Registration Statement onForm S‑1 filed on June 7, 2011)10.3Amendment No. 2 & Agreement, dated as of September 15, 2011, to the Credit Agreement, among Bonanza Creek Energy, Inc., BNPParibas, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.14 to the RegistrationStatement on Form S‑1/A filed on November 4, 2011)10.4Resignation, 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 tothe Quarterly Report on Form 10‑Q filed on May 11, 2012)10.5Amendment No. 3 & Agreement, dated as of May 8, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBankNational Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to theQuarterly Report on Form 10‑Q filed on May 11, 2012)10.6Amendment No. 4, dated as of July 31, 2012 to the Credit Agreement among Bonanza Creek Energy, Inc., Key Bank NationalAssociation, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.5 to the Quarterly Reporton Form 10‑Q filed on August 13, 2012)10.7Amendment No. 5, dated as of October 30, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank NationalAssociation, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Quarterly Reporton Form 10‑Q filed on November 9, 2012)10.8Amendment No. 6, dated as of March 29, 2013, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank NationalAssociation, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Reporton Form 10‑Q filed on May 10, 2013)117 Table of Contents10.9Amendment No. 7, dated as of May 16, 2013 to the Credit Agreement among Bonanza Creek Energy, Inc., Key Bank NationalAssociation, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.7 to the Quarterly Reporton Form 10‑Q filed on August 9, 2013)10.10Amendment 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 byreference to Exhibit 99.1 to the Current Report on Form 8‑K filed on November 8, 2013)10.11Amendment No. 9 and Agreement, dated as of May 14, 2014, to the Credit Agreement, among Bonanza Creek Energy, Inc., theGuarantors, 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)10.12Amendment No. 10 and Agreement, dated as of September 30, 2014, to the Credit Agreement, among Bonanza Creek Energy, Inc., theGuarantors, 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)10.13Amendment No. 11 and Agreement, dated as of May 13, 2015, to the Credit Agreement, among Bonanza Creek Energy, Inc., theGuarantors, 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)10.14Letter 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)10.15Registration Rights Agreement, among Bonanza Creek Energy, Inc., Project Black Bear LP, Her Majesty the Queen in Right ofAlberta, 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 byreference 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 theCurrent 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 TermIncentive 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 TermIncentive 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‑Kfiled 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 onForm 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 byreference 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 byreference 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 byreference to Exhibit 10.2 to the Current Report on Form 8-K filed on November 14, 2014)10.26*Employment Letter Agreement effective April 29, 2013 between Bonanza Creek Energy, Inc. and Christopher I. Humber(incorporated by reference to Exhibit 10.5 to the Current Report on Form 8‑K filed on May 3, 2013)10.27*Employment Letter Agreement, dated August 6, 2013, between Bonanza Creek Energy, Inc. and William J. Cassidy (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8‑K filed on August 13, 2013)10.28*Employment Letter Agreement, dated August 7, 2013, between Bonanza Creek Energy, Inc. and Anthony G. Buchanon (incorporatedby reference to Exhibit 10.2 to the Current Report on Form 8‑K filed on August 13, 2013)118 Table of Contents10.29*Form of Employment Letter Agreement (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8‑K filed onMarch 29, 2013)10.30*Bonanza Creek Energy, Inc. Amended and Restated Executive Change in Control and Severance Plan (incorporated by reference toExhibit 10.3 of the Quarterly Report on Form 10‑Q filed on July 28, 2015)10.31Membership Interest Purchase Agreement dated November 5, 2015 by and among Bonanza Creek Energy Operating Company, LLCand Meritage Midstream Services IV, LLC (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed onNovember 10, 2015).10.32Purchase and Sale Agreement by and between DJ Resources, LLC, Bonanza Creek Energy Operating Company, LLC and BonanzaCreek Energy, Inc. dated May 21, 2014 (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on May23, 2014).21.1†List of subsidiaries23.1†Consent of Hein & Associates LLP23.2†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 theSarbanes‑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 theSarbanes‑Oxley Act of 2002 (furnished herewith)99.1†Report of Independent Petroleum Engineers, Netherland, Sewell & Associates, Inc. for reserves as of December 31, 2015101†The following material from the Bonanza Creek Energy, Inc. Annual Report on Form 10‑K for the year ended December 31, 2015 (andrelated periods), formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated BalanceSheets, (ii) the Condensed Consolidated Statements of Operations and Comprehensive Income, (iii) the Condensed ConsolidatedStatements of Stockholders’ Equity, (iv) the Condensed Consolidated Statements of Cash Flows, and (v) Notes to the CondensedConsolidated Financial Statements, tagged as blocks of text_________________________* Management Contract or Compensatory Plan or Arrangement† Filed or furnished herewith119 Exhibit 21.1Subsidiaries of Bonanza Creek Energy, Inc., a Delaware corporationBonanza Creek Energy Operating Company, LLC, a Delaware limited liability companyBonanza Creek Energy Resources, LLC, a Delaware limited liability companyBonanza Creek Energy Upstream LLC, a Delaware limited liability companyBonanza Creek Energy Midstream, LLC, a Delaware limited liability companyHolmes Eastern Company, LLC, a Delaware limited liability companyRocky Mountain Infrastructure, LLC, a Delaware limited liability company Exhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in the Registration Statements on Form S‑3 (Registration Nos. 333‑186019, 333‑192258, 333-197413,333-197901 and 333-206398) and the Registration Statements on Form S‑8 (Registration Nos. 333‑179207 and 333-206399) of Bonanza Creek Energy, Inc.of our reports dated February 29, 2016, relating to our audits of the consolidated financial statements and internal control over financial reporting, includedin the Annual Report on Form 10‑K of Bonanza Creek Energy, Inc. for the year ended December 31, 2015./s/ HEIN & ASSOCIATES LLPDenver, ColoradoFebruary 29, 2016 Exhibit 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSThe undersigned hereby consents to the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of BonanzaCreek Energy, Inc. for the year ended December 31, 2015. We hereby further consent to the use of information contained in our reserves report dated January15, 2014, and our audit letter dated January 14, 2015, which set forth estimates of revenues from Bonanza Creek Energy, Inc.'s oil and gas reserves as ofDecember 31, 2013, and December 31, 2014, respectively. We further consent to the incorporation by reference thereof into Bonanza Creek Energy, Inc.’sRegistration Statements on Form S‑8 (Registration Nos. 333‑179207 and 333-206399) and on Form S‑3 (Registration Nos. 333‑186019, 333‑192258, 333-197413, 333-197901 and 333-206398). 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 February 29, 2016 Exhibit 31.1CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a‑ 14(a)I, Richard J. Carty, certify that:1.I have reviewed this Annual Report on Form 10‑k for the year ended December 31, 2015 of Bonanza Creek Energy, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for theregistrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal 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 theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’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 arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting.Date: February 29, 2016 /s/ Richard J. Carty Richard J. Carty President and Chief Executive Officer Exhibit 31.2CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a‑ 14(a)I, William J. Cassidy, certify that:1.I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2015 of Bonanza Creek Energy, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the periods covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for theregistrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal 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 theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’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 arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting.Date: February 29, 2016 /s/ William J. Cassidy William J. Cassidy Executive Vice President and Chief Financial Officer Exhibit 32.1Certification of the Chief Executive OfficerPursuant to 18 U.S.C. Section 1350,As Adopted Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002In connection with the Annual Report of Bonanza Creek Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2015 as filedwith the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard J. Carty, President and Chief Executive Officer of the Company,certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:(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 theCompany.Date: February 29, 2016 /s/ Richard J. Carty Richard J. Carty President and Chief Executive Officer Exhibit 32.2Certification of the Chief Financial OfficerPursuant to 18 U.S.C. Section 1350,As Adopted Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002In connection with the Annual Report of Bonanza Creek Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2015 as filedwith the Securities and Exchange Commission on the date hereof (the “Report”), I, William J. Cassidy, Executive Vice President and Chief Financial Officerof the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:(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 theCompany.Date: February 29, 2016 /s/ William J. Cassidy William J. Cassidy Executive Vice President and Chief Financial Officer Exhibit 99.1January 19, 2016 Mr. Marvin ChronisterReserves Committee of Bonanza Creek Energy, Inc.c/o Bonanza Creek Energy, Inc.410 Seventeenth Street, Suite 1400Denver, Colorado 80202Dear Mr. Chronister:In accordance with your request, we have audited the estimates prepared by Bonanza Creek Energy, Inc. (BCEI), as of December 31, 2015, of theproved reserves and future revenue to the BCEI interest in certain oil and gas properties located in the United States. It is our understanding thatthe proved reserves estimated herein constitute all of the proved reserves owned by BCEI. We have examined the estimates with respect toreserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using thedefinitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and futurerevenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of futureincome taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit onor about the date of this letter. This report has been prepared for BCEI's use in filing with the SEC; in our opinion the assumptions, data, methods,and procedures used in the preparation of this report are appropriate for such purpose.The following table sets forth BCEI's estimates of the net reserves and future net revenue, as of December 31, 2015, for the audited properties: Net Reserves Future Net Revenue (M$) Oil NGL Gas Present WorthCategory (MBBL) (MBBL) (MMCF) Total at 10% Proved Developed Producing 27,572.9 10,012.7 72,910.4 596,669.6 388,534.2Proved Developed Non-Producing 1,318.8 346.7 4,569.6 23,853.5 20,874.5Proved Undeveloped(1) 28,501.4 9,558.5 66,747.1 98,399.3 (81,592.90) Total Proved 57,393.1 19,918.0 144,227.2 718,922.4 327,815.8Totals may not add because of rounding.(1) These reserves have been included based on the operators' intent to drill these wells.The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL);a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature andpressure bases.When compared on a lease-by-lease basis, some of the estimates of BCEI are greater and some are less than the estimates of Netherland, Sewell& Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of BCEI's reserves and future revenue are reasonable whenaggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society ofPetroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in theSPE Standards. We are satisfied with the methods and procedures used by BCEI in preparing the December 31, 2015, estimates of reserves andfuture revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as preparedby BCEI.The estimates shown herein are for proved reserves. BCEI's estimates do not include probable or possible reserves that may exist for theseproperties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.BCEI has included estimates of proved undeveloped reserves for certain locations that generate positive future net revenue but have negativepresent worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These locationshave been included based on the operators' intent to drill these wells, as evidenced by BCEI's internal budget, reserves estimates, and priceforecast. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and productionstatus. The estimates of reserves and future revenue included herein have not been adjusted for risk.Prices used by BCEI are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the periodJanuary through December 2015. For oil and NGL volumes, the average West Texas Intermediate spot price of $50.28 per barrel is adjusted forquality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted forenergy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The averageadjusted product prices weighted by production over the remaining lives of the properties are $44.00 per barrel of oil, $12.90 per barrel of NGL, and$2.330 per MCF of gas.Operating costs used by BCEI are based on historical operating expense records. For the nonoperated properties, these costs include the per-welloverhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.Operating costs for the operated properties are limited to direct lease- and field-level costs and BCEI's estimate of the portion of its headquartersgeneral and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Capital costs used by BCEI are based on authorizations for expenditure and actual costs from recentactivity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used areBCEI's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Operating, capital, and abandonment costsare not escalated for inflation.The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oiland gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimatesof reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.In addition to the primary economic assumptions discussed herein, estimates of BCEI and NSAI are based on certain assumptions including, butnot limited to, that the properties will be developed consistent with current development plans as provided to us by BCEI, that the properties will beoperated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner torecover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, therevenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies anduncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may varyfrom assumptions made while preparing these estimates. It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consistedprimarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independentlyverified the accuracy and completeness of information and data furnished by BCEI with respect to ownership interests, oil and gas production, welltest data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of theproperties and sales of production. However, if in the course of our examination something came to our attention that brought into question thevalidity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questionsrelating thereto or had independently verified such information or data. Our audit did not include a review of BCEI's overall reserves managementprocesses and practices.We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, andanalogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gasevaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarilyrepresent only informed professional judgment.Supporting data documenting this audit, along with data provided by BCEI, are on file in our office. The technical persons primarily responsible forconducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.Dan Paul Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since1980 and has over 7 years of prior industry experience. John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has beenpracticing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. We are independent petroleumengineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingentbasis.Sincerely,NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-2699/s/ C.H. (Scott) Rees IIIBy: C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer/s/ Dan Paul Smith /s/ John G. HattnerBy: By: Dan Paul Smith, P.E. 49093 John G. Hattner, P.G. 559Senior Vice President Senior Vice PresidentDate Signed: January 19, 2016 Date Signed: January 19, 2016DPS:AHA Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document isintended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions statedin the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digitaldocument.

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