Civitas Resources
Annual Report 2018

Plain-text annual report

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, 2018OR¨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 $0.01 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 ofthis chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). 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, a smaller reporting company, or an emerging growthcompany. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer xAccelerated filer ¨Non-accelerated filer ¨Smaller reporting company ¨ Emerging growth company ¨ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No xIndicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent tothe distribution of securities under a plan confirmed by a court. Yes x No ¨The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates on June 30, 2018, based upon the closing price of $37.87 of theregistrant’s common stock as reported on the New York Stock Exchange, was approximately $776,136,334. Excludes approximately 13,858 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 25, 2019: 20,558,591Documents Incorporated By Reference:Portions of the registrant’s definitive proxy statement, will be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, as incorporated byreference into Part III of this report for the year ended December 31, 2018. 1Table of ContentsBONANZA CREEK ENERGY, INC.FORM 10-KFOR THE YEAR ENDED DECEMBER 31, 2018TABLE OF CONTENTS PAGE Glossary of Oil and Natural Gas Terms5PART IItem 1.Business11Item 1A.Risk Factors35Item 1B.Unresolved Staff Comments52Item 2.Properties52Item 3.Legal Proceedings52Item 4.Mine Safety Disclosures53PART IIItem 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities53Item 6.Selected Financial Data56Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations58Item 7A.Quantitative and Qualitative Disclosure about Market Risk72Item 8.Financial Statements and Supplementary Data75Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure119Item 9A.Controls and Procedures119Item 9B.Other Information122PART IIIItem 10.Directors, Executive Officers and Corporate Governance123Item 11.Executive Compensation123Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters123Item 13.Certain Relationships and Related Transactions and Director Independence123Item 14.Principal Accountant Fees and Services123PART IVItem 15.Exhibits, Financial Statement Schedules1242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;•reserves estimates;•estimated sales volumes;•amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;•ability to modify future capital expenditures;•anticipated costs;•compliance with debt covenants;•ability to fund and satisfy obligations related to ongoing operations;•compliance with government regulations, including environmental, health and safety regulations and liabilities thereunder;•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;•impact of effectiveness of vapor control systems at central tank batteries;•natural gas, oil and natural gas liquid prices and factors affecting the volatility of such prices;•impact of lower commodity prices;•sufficiency of impairments;•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;•impact of potentially disruptive technologies;•our estimated revenues and losses;•the timing and success of specific projects;•our implementation of standard and 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;•stated 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, C, and Codell benches in our legacy, French Lake, and northern acreage;•our ability to replace oil and natural gas reserves;3Table of Contents•our ability to convert PUDs to producing properties within five years of their initial proved booking;•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;•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 and completion 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;•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;•our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and naturalgas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;•costs and other risks associated with curing title for mineral rights in some of our properties;•continued hostilities in the Middle East, South America, 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.” 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.5Table of Contents“Basin.” A large natural depression on the earth’s surface in which sediments generally deposited via water accumulate.“Completion.” The process of stimulating a drilled well followed by the installation of permanent equipment to allow for the production of crude oiland/or natural gas, 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 acres.” 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 theoil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costsof development 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 vapor 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 cash costs of the operation. The value of the products that generate revenue shall be determined at the terminal point ofoil and 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.“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.6Table of Contents“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.“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.“Gross Wells.” The total wells in which an entity owns a working interest.“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 into the wellbore.“Infill drilling.” The addition of wells in a field that decreases average well spacing.“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 in100 acres 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 theirnatural states and original locations; (ii) the acquisition of property rights or properties for the purpose of further exploration or for the purpose of removingthe oil or gas from such properties; (iii) the construction, drilling and production activities necessary to retrieve oil and gas from their natural reservoirs,including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as lifting the oil and gas to the surface andgathering, treating and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (iv) extraction of saleable hydrocarbons, in thesolid, liquid, or gaseous state, from oil sands, shale, coal beds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oilor gas, and activities undertaken with a view to such extraction.7Table of Contents“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.“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.” The sealing off of all gas and liquids in the strata penetrated by a well so that the gas and liquids from one stratumwill not escape into another stratum or to the surface.“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 reasonablecertainty to 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, and8Table of Contents(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.(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 tofootnote 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.“Reclamation.” The process to restore the land and other resources to their original state prior to the effects of oil and gas development.“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.9Table of Contents“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.“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.” Drilling programs targeted at regionally distributed oil or natural gas accumulations. Successful exploitation of these reservoirs isdependent upon new technologies such as horizontal drilling and multi-stage fracture stimulation to access large rock volumes in order to produce economicquantities 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 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. Typical spacing for unconventional wells is either 640 acres or 1,280 acres for both oil and gas.“Standard reach lateral equivalent well.” Equates to a ratio of one well to one well for a standard reach lateral well, one and half wells to one wellfor a medium reach lateral well, and two wells to one well for an extended reach lateral well. Standard reach laterals typically include lengths of up to onemile, medium reach laterals of up to one and a half miles, and extended reach laterals of up to two miles.“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. BusinessWhen 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 a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in theRocky Mountain region of the United States. Bonanza Creek Energy, Inc. was incorporated in Delaware on December 2, 2010 and went public in December2011.The Company's assets and operations are concentrated in the rural portions of unincorporated Weld County within the Wattenberg Field. We operateapproximately 80% of all our productive wells allowing us to control the pace, costs and completion techniques used in the development of our reserves. TheWattenberg Field has a low cost structure, mature infrastructure, strong production efficiencies, multiple producing horizons, multiple service providers,established reserves and prospective drilling opportunities, which helps facilitate predictable production and reserve growth.The challenging commodity price environment that began in late 2014 and continued through 2017 improved steadily during the majority of 2018.While commodity prices improved, they continued to be volatile. Nevertheless, we believe we remain well-positioned in this environment due to our healthybalance sheet, ample liquidity, improved inventory of economic drilling locations, and our operational flexibility which allows us to respond to commodityprice fluctuations. During 2018, we demonstrated our operational focus on achieving best-in-class execution by lowering our cost of operations on a per unit basis. Weincreased drilling efficiencies and improved well performance via enhanced completion designs, which contributed to a significant growth in reserves.Additionally, we maintained our conservative balance sheet and significantly improved our available liquidity by entering into a larger, more flexible,reserve-based credit facility. We intend to continue our operational focus in 2019, emphasizing full-cycle returns and capital discipline. We will continue tomonitor the ongoing commodity price environment and expect to retain the operational flexibility to adjust our drilling and completion plans in response tomarket conditions.Our Business StrategiesThe Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources. We seek to accomplishthis through development of existing inventory and value-accretive acquisition and divestiture activity. We seek to balance production growth withmaintaining a conservative balance sheet. Key aspects of our strategy include:•Multi-well pad development across our leasehold. We believe horizontal development is the most efficient and safest way to recover thehydrocarbons located within our leasehold.•Enhanced completions. We continuously evaluate completion designs to increase well productivity and apply a multivariate regression analysiswith the objective of optimizing economic returns. Petrophysical, geological and geophysical analysis is used in conjunction with spacingevaluations and individualized well designs to increase value of each spacing unit.•Continuous safety improvement and strict adherence to health and safety regulations. Our goal is to utilize industry best practices to meet orexceed regulatory requirements and consistently engage stakeholders in our development planning. We strive to maintain a safe workplace for ouremployees and contractors at all times.•Environmental stewardship. We constantly strive to control and reduce emissions and seek to comply with all applicable air quality and otherenvironmental rules and regulations. We employ best practices including pipeline gathering and takeaway as well as vapor recovery and leakdetection equipment. Additionally, we work closely with our service providers to help ensure they stay in compliance with environmentalregulations when operating on our behalf.11Table of Contents•Disciplined approach to acquisitions and divestitures. Opportunities are evaluated in the context of maintaining development flexibility and ahealthy balance sheet. We pursue value-accretive acquisitions and strive to maximize scale and minimize financial and operational risk.•Prudent risk management. The Company believes a healthy balance sheet, focus on cost control, and minimizing long-term commitments are criticalto controlling risk. A low debt profile and judicious use of hedging practices help reduce cash flow volatility. Continually striving to be a cost-efficient operator and maintaining a flexible capital spending program enable us to respond to changing market conditions. Hedge a portion of itsproduction to reduce realized price volatility allowing for enhanced certainty of development program rates of return and improved capitalallocation decisions.Significant Developments in 2018LeadershipDuring 2018, the Company secured key leadership roles in order to help develop and achieve the Company's strategies.Effective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greager hasover 20 years of experience in the oil and gas industry, including exposure to both the operating and technical aspects of the industry. Mr. Greagerpreviously served as a Vice President and General Manager at Encana Oil & Gas (USA) Inc.Effective November 13, 2018, the Company appointed Brant H. DeMuth as the new Executive Vice President and Chief Financial Officer andprincipal financial officer of the Company. Mr. DeMuth has 34 years of management and finance experience in capital markets and the oil and gas industry.Mr. DeMuth previously served as Vice President of Finance and Treasurer at SRC Energy Inc.OperationsIn order to focus on and partially fund the development of our core assets, we divested of our Mid-Continent region and North Park Basin assets. Wesuccessfully sold our Mid-Continent assets on August 6, 2018 for net proceeds of $102.9 million which resulted in a gain of $27.3 million. The Companysold its North Park Basin assets on March 9, 2018 for minimal net proceeds and full release of all current and future obligations.We continued to take steps to improve our access to gas processing in the DJ Basin, which resulted in improved costs, greater reliability, and greateroptionality than available to many other operators in the basin while enhancing the value of our Rocky Mountain Infrastructure, LLC (“RMI”) system. RMIprovides low gathering system pressures at the wellhead and access to four gas processors through eleven interconnects. This flexibility helps ensure productflow from both existing and new wells. We will continue to look for ways to improve our access to gas gathering and processing services.Our cost reductions in 2018 were focused primarily around compression contracts, water services, labor, and well servicing. Through these costsaving efforts the Company experienced a 46% reduction in Wattenberg Field lease operating expense per Boe when comparing the fourth quarters of 2018and 2017. Further efficiency improvements will continue to be a focus for the Company, with our per-unit costs continuing to benefit from production growthin 2019 and beyond. The Company incurred some non-recurring costs in the first half of the year, including one-time facility emissions modeling andcompressor replacement costs.The Company accelerated its development in the DJ Basin while testing enhanced completion designs on large, efficient multi-well pads throughoutthe Company’s acreage position. Enhanced completion designs varied to ensure that thorough knowledge could be applied to future drilling programs. Fluidvolumes and types, proppant volumes and types, stage spacing, well spacing, and flowback techniques were the primary variables that were tested throughoutthe 2018 program. The Company will continue to monitor industry trends, public data, and information from non-operated wells to further define optimumcompletion techniques. We deployed one rig in the first half of 2018 with a second rig added mid-year to coincide with our access to additional gasprocessing capacity. We discontinued our use of the second rig in late 2018 in response to the weakening commodity price environment. Wattenberg salesvolumes increased by approximately 48% when comparing the fourth quarters of 2018 and 2017.12Table of ContentsConsistent with the Company's 2018 budget, our capital program equaled approximately $275.3 million, which resulted in the drilling of 77 grossoperated wells, turning to sales 41 gross operated wells and participating in the drilling and completion of one non-operated well.The following table summarizes our estimated proved reserves as of December 31, 2018: Natural Crude Natural Gas Total Oil Gas Liquids ProvedEstimated Proved Reserves (MBbls) (MMcf) (MBbls) (MBoe)Developed Rocky Mountain 23,725 79,630 11,703 48,699Undeveloped Rocky Mountain 40,629 85,382 13,227 68,086Total Proved 64,354 165,012 24,930 116,785Total Wattenberg Field proved reserves as of December 31, 2018 increased by approximately 29% over the comparable period in 2017. The following table summarizes our PV-10 reserve value, sales volumes, and projected capital spend as of December 31, 2018: Sales Volumes for the Year Ended Gross Proved Estimated Proved Reserves at December 31, Undeveloped December 31, 2018(1) 2018 Drilling Average Net Projected Locations Total Daily Sales 2019 Capital as of Proved % of % Proved PV-10 Volumes % of Expenditures December 31, (MBoe) Total Developed ($ in MM)(2) (Boe/d) Total ($ in millions) 2018(4)Rocky Mountain 116,785 100% 42% $955.0 15,844 90% $230-255 300Mid-Continent(3) — —% —% — 1,728 10% — —Total 116,785 100% 42% $955.0 17,572 100% $230-255 300_____________________(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 $65.56 per Bbl WTI and $3.10 per MMBtu HH.Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $6.27 per Bbl for crude oil and adecrease of $0.82 per MMBtu for 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 in the “Reserves” subsection of Item 1 below.(3)Mid-Continent sales volumes were 1,728 Boe/d for 2018, which is comprised of 1,550 Boe/d of production net to our interest and 178 Boe/d salesvolumes from our percentage-of-proceeds contracts. We sold all of our assets within the Mid-Continent region on August 6, 2018.13Table of Contents(4)The Company has 444.5 standard reach lateral equivalent gross proved undeveloped drilling locations as of December 31, 2018.Our OperationsAs of December 31, 2018, our operations are solely focused in the rural portions of the Wattenberg Field in the Rocky Mountain region. TheCompany sold all of its assets within the Mid-Continent region and North Park Basin on August 6, 2018 and March 9, 2018, respectively.Rocky Mountain RegionOur Rocky Mountain Region consists of one operating area in the Wattenberg Field in Weld County, Colorado. As of December 31, 2018, ourestimated proved reserves in the Rocky Mountain region were 116,785 MBoe, which represented 100% of our total estimated proved reserves andcontributed 15,844 Boe/d, or 90%, of sales volumes during 2018.Wattenberg Field - Weld County, Colorado. Our operations are located in the rural portions of the oil and liquids-weighted extension area of theWattenberg Field targeting the Niobrara and Codell formations. As of December 31, 2018, our Wattenberg position consisted of approximately 92,000 gross(65,000 net) acres.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 has beendelineated on our western legacy acreage. Our northern and southern acreage positions are currently being delineated.As of December 31, 2018, we had a total of 695 gross producing wells, of which 507 were horizontal wells. Our sales volumes for the fourth quarterof 2018 were 17,748 Boe/d. As of December 31, 2018, our working interest for all producing wells averaged approximately 80% and our net revenue interestwas approximately 66%.We drilled and participated in drilling 116.5 gross (92.2 net) standard reach lateral (“SRL”) equivalent wells in 2018 in the Wattenberg Field. As ofDecember 31, 2018, we have an identified drilling inventory of approximately 300 gross (200.3 net) proved undeveloped (“PUD”) drilling locations (444.5gross SRL equivalents) on our acreage.The following table summarizes our drilling and completion activity for SRL wells, medium reach lateral wells (“MRL”), and extended reach lateralswells (“XRL”) on a gross basis for the year ended December 31, 2018. SRL MRL XRL Drilled Completed Drilled Completed Drilled CompletedNiobrara - Operated 34 16 7 2 33 20Codell - Operated 2 3 — — 1 —Niobrara - Non-operated — — — — 1 1The Company’s Rocky Mountain Infrastructure (“RMI”) gathering asset has eleven interconnects to four independent gas processors. This systemimproves flow assurance and operates at relatively low line pressure at the wellhead. Reduced gathering system pressure at the wellhead enhances wellperformance and the system’s interconnects provide for delivery flexibility, enabling the Company to maximize available price realizations.The Company’s 2019 capital budget contemplates the continuous use of one drilling rig. The rig is scheduled to drill large-scale five to eighteenwell pads throughout our legacy west, central and east acreage position. The Company plans to complete wells in 2019 using slickwater designs similar tothe techniques used in 2018 that resulted in significant well improvements. The Company will continue to remain agile and modify drilling and completiontechniques as additional data from both operated and non-operated wells becomes available.Assuming a one rig drilling program, the Company anticipates 2019 Wattenberg production growth to be greater than 30% year-over-year ascompared to Wattenberg-only production realized in 2018. Furthermore, the Company anticipates being able to grow Wattenberg production byapproximately 20% in 2020 as compared to 2019 using a one-and-a-half operated rig program.14Table of ContentsOur drilling and completion capital investment in 2019 is expected to be approximately $210.0 million to $220.0 million, which will supportdrilling 59 gross wells and turning to sales 45 gross wells. This drilling and completion capital budget includes an estimated $15.0 million for non-operatedactivity. An additional $20.0 million to $35.0 million in capital is contemplated for investments in infrastructure, land, and seismic. The 2019 drilling andcompletion program by well type is presented in the following table. SRL MRL XRL Drilled Completed Drilled Completed Drilled CompletedNiobrara 33 24 — 5 26 16North Park Basin - Jackson County, Colorado. We successfully sold all of our North Park assets on March 9, 2018 for minimal net proceeds and fullrelease of all current and future obligations. Our sales volumes for 2018, prior to the divestiture, were10 Boe/d.Mid-Continent RegionWe successfully sold our Mid-Continent assets on August 6, 2018 for $117.0 million, prior to customary closing adjustments, which resulted in netproceeds of $102.9 million. We achieved a sales volume rate for 2018 of 1,728 Boe/d prior to the divestiture, or 10% of sales volume for 2018. At December31, 2017, the Company had 300 gross producing vertical wells and proved reserves of approximately 10,419 MBoe.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. Our estimated proved reserves for the years ended December 31, 2018, 2017 and 2016 were determined using thepreceding twelve month unweighted arithmetic average of the first-day-of-the-month prices. For a definition of proved reserves under the SEC rules, pleasesee the Glossary of Oil and Natural Gas Terms included in the beginning of this report.Reserve estimates are inherently imprecise, and estimates for undeveloped properties are more imprecise than reserve estimates for producing oil andgas properties. Accordingly, all of these estimates are expected to change as new information becomes available. The PV-10 values shown in the followingtable are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actualquantities and present values of our estimated proved reserves may vary from what we have estimated.The table below summarizes our estimated proved reserves as of December 31, 2018, 2017 and 2016 for each of the regions and currently producingfields in which we operate. The proved reserve estimates as of December 31, 2018 and 2017 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”),our third-party independent reserve engineers. The proved reserves as of December 31, 2016 are based on reports prepared by our internal corporate reservoirengineering group, of which 100% were audited by NSAI. For more information regarding our independent reserve engineers, please see Independent ReserveEngineers below. The information in the following table is not intended to represent the current market value of our proved reserves nor does it give anyeffect to or reflect our commodity derivatives or current commodity prices.15Table of Contents At December 31, Region/Field 2018 2017 2016 (MMBoe) Rocky Mountain 116.8 90.5 78.0 Wattenberg 116.8 90.3 77.8 North Park — 0.2 0.2 Mid-Continent — 11.5 12.7 Dorcheat Macedonia — 10.4 11.6 McKamie Patton — 1.1 1.1 Total 116.8 102.0 90.7 The following table sets forth more information regarding our estimated proved reserves at December 31, 2018, 2017 and 2016: At December 31, 2018 2017 2016 Reserve Data(1): Estimated proved reserves: Oil (MMBbls) 64.4 52.9 50.1 Natural gas (Bcf) 165.0 157.7 138.0 Natural gas liquids (MMBbls) 24.9 22.8 17.5 Total estimated proved reserves (MMBoe)(2) 116.8 102.0 90.7 Percent oil and liquids 76% 74% 75% Estimated proved developed reserves: Oil (MMBbls) 23.7 25.8 26.3 Natural gas (Bcf) 79.6 92.7 86.0 Natural gas liquids (MMBbls) 11.7 12.7 10.0 Total estimated proved developed reserves (MMBoe)(2) 48.7 53.9 50.6 Percent oil and liquids 73% 71% 72% Estimated proved undeveloped reserves: Oil (MMBbls) 40.6 27.1 23.8 Natural gas (Bcf) 85.4 65.0 52.0 Natural gas liquids (MMBbls) 13.2 10.1 7.5 Total estimated proved undeveloped reserves (MMBoe)(2) 68.1 48.1 40.1 Percent oil and liquids 79% 77% 78% ____________________(1)Proved reserves were calculated using the preceding twelve month unweighted arithmetic average of the first-day-of-the-month prices, which were$65.56 per Bbl WTI and $3.10 per MMBtu HH, $51.34 per Bbl WTI and $2.98 per MMBtu HH, and $42.75 per Bbl WTI and $2.48 per MMBtu HH forthe years ended December 31, 2018, 2017 and 2016, respectively. Adjustments were made for location and grade.(2)Determined using the ratio of 6 Mcf of natural gas to one Bbl of crude oil.Proved 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, 2018 reserve report are included in our development plan and are16Table of Contentsscheduled to be drilled within five years from the date they were initially recorded. The Company’s management evaluated the proved undeveloped drillingplan using NYMEX strip prices, the liquidation model for general and administrative costs, updated capital expenditures and lease operating costs to matchrevised bids and actuals from year-end. The reserve report factored in a one-rig program for 2019, a one-and-a-half rig program in 2020, and two rigs startingin the second half of 2022, which allows all PUDs to be drilled within the allotted five-year window. We typically book proved undeveloped locations withinone development spacing area from developed producing locations. For the instances where a proved undeveloped location is beyond one spacing area froma developed producing location, we utilized reliable geologic and engineering technology. The reliable technologies used to establish our proved reservesare a combination of pressure performance, geologic mapping, offset productivity, electric logs, seismic, and production data.As of December 31, 2018, the total proved undeveloped gross location count in our Wattenberg Field was 300.0 (444.5 SRL equivalents), comparedto 205.0 (248.0 SRL equivalents) gross location counts as of December 31, 2017. Our five-year drilling program captures these proved undevelopedlocations. For the year ending December 31, 2018, approximately 60% of the proved undeveloped locations are spaced on 80 acres within a single bench andapproximately 40% are planned to be drilled on 80/40 geometry, which involves drilling wells on 80 acre spacing on each of two benches with a 40 acreoffset between wells on the upper and lower bench.The Company-wide and Wattenberg Field estimated proved reserves at December 31, 2018 were 116.8 MMBoe, a 14% and 29% increase from theCompany-wide and Wattenberg Field estimated proved reserves at December 31, 2017, respectively. The net increase in our Company-wide reserves of 14.8MMBoe is the result of a 28.8 MMBoe increase from PUD and capital additions, coupled with a 3.8 MMBoe increase in cost and engineering revisions, and a2.3 MMBoe increase due to pricing, offset by divested reserves of 11.2 MMBoe, 2.5 MMBoe of undeveloped reserves removed from our five-year drillingprogram, and 2018 production of 6.4 MMBoe.Positive adjustments to the estimated proved reserves during 2018 consisted of pricing and LOE changes, reserve additions from capital and PUDdevelopments, and engineering revisions. The positive pricing revision of 2,333 Mboe resulted from an increase in average commodity price from $51.34 perBbl WTI and $2.98 per MMBtu HH for the year ended December 31, 2017 to $65.56 per Bbl WTI and $3.10 per MMBtu HH for the year ended December 31,2018. The 1,536 MBoe LOE revision is due to continued decreases in LOE as a result of numerous cost-cutting initiatives completed over the past few years.The 28,832 Mboe in PUD and capital additions is the result of turning to sales 41 operated horizontal locations in the Niobrara and Codell formations in theWattenberg Field during 2018 and adding infill and extension PUD locations that are on the 2019 rig schedule.Estimated proved reserves at December 31, 2017 were 102.0 MMBoe, a 13% increase from estimated proved reserves of 90.7 MMBoe at December31, 2016. Approximately 89% of our December 31, 2017 proved reserves were attributed to the Rocky Mountain region, and 99.8% of the Rocky Mountainproved reserves were attributed to the Wattenberg Field. The net increase in our reserves of 11.3 MMBoe was the result of a 15.5 MMBoe increase from PUDand capital additions, coupled with a 7.1 MMBoe increase in net positive cost revisions (reserve prices less drilling and completion costs and LOE), and a 2.1MMBoe increase due to positive engineering revisions, offset by PUD demotions of 7.6 MMBoe and 2017 production of 5.7 MMBoe.Positive adjustments to the estimated proved reserves during 2017 consisted of pricing and LOE changes, reserve additions from capital and PUDdevelopments, and engineering revisions. The positive pricing revision of 5,405 Mboe resulted from an increase in average commodity price from $42.75 perBbl WTI and $2.48 per MMBtu HH for the year ended December 31, 2016 to $51.34 per Bbl WTI and $2.98 per MMBtu HH for the year ended December 31,2017. The 1,672 MBoe LOE revision was due to continued decreased LOE as a result of numerous cost-cutting initiatives completed over the past few years.The 15,547 Mboe in PUD and capital additions was the result of turning to sales 10 operated and 24 non-operated unproved horizontal locations in theNiobrara and Codell formations in the Wattenberg Field during 2017 and adding infill PUD locations that were the 2018 rig schedule, offset by PUDlocations that were removed due to a shift within our development strategy.Estimated proved reserves at December 31, 2016 were 90.7 MMBoe, a 10% decrease from estimated proved reserves of 101.3 MMBoe at December31, 2015. The net decrease in our reserves of 10.6 MMBoe was the result of 2016 production of 7.8 MMBoe coupled with writing off 16.4 MMBoe of PUDsand 1.9 MMBoe of other engineering revisions, offset by additions in extensions, discoveries, and infills of 10.8 MMBoe and net positive cost revisions(reserve prices less drilling and completion costs and LOE) of 4.7 MMBoe.The 10.8 MMBoe addition in extensions, discoveries, and infills in 2016 was primarily the result of turning to sales five operated and six non-operated unproved horizontal locations in the Niobrara formation that were in progress at year-end 2015, and drilling and completing three non-operatedunproved horizontal wells and one operated unproved vertical well in the17Table of ContentsNiobrara formation in the Wattenberg Field during 2016. In 2016 our five-year drilling plan was adjusted to focus on locations that were adjacent to existingproduction facilities. As a result, 42 PUD locations were added and 38 PUD locations under the prior plan were removed.Total Company positive engineering revisions as of December 31, 2016, were 28,625 Mboe, of which 32,899 Mboe were related to positive reservechanges in the Wattenberg Field and 4,416 Mboe were related to negative reserve changes in the Dorcheat Macedonia Field. The overall positiveengineering revision is offset by a negative pricing revision of 39,222 Mboe in the Wattenberg Field and 2,778 Mboe in the Dorcheat Macedonia Field. Thenegative pricing revision of 42,143 Mboe for the Company resulted from a decrease in average commodity price from $50.28 per Bbl WTI and $2.59 perMMBtu HH for the year ended December 31, 2015 to $42.75 per Bbl WTI and $2.48 per MMBtu HH for the year ended December 31, 2016. The majority ofthe positive revisions in the Wattenberg Field resulted from a combination of decreased drilling and completion costs and a continued decrease in LOE,which had begun in 2015. Our total proved undeveloped location count in the Wattenberg Field as of December 31, 2016 was 210 (226 standard reach lateralequivalents) and 204 as of December 31, 2015.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. We use this measure when assessing the potential return on investment related to our oiland natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Neither our PV-10 measure or the Standardized Measure purportto present the fair value of our oil and natural gas reserves.The following table provides a reconciliation of PV-10 to Standardized Measure at December 31, 2018, 2017 and 2016: December 31, 2018 2017 2016 (in millions)PV-10 $955.0 $598.5 $276.9Present value of future income taxes discounted at 10%(1) — — —Standardized Measure $955.0 $598.5 $276.9____________________________(1) The tax basis of our oil and gas properties as of December 31, 2018, 2017, and 2016 provides more tax deduction than income generated from our oil andgas properties when the reserve estimates were prepared using $65.56 per Bbl WTI and $3.10 per MMBTU HH, $51.34 per Bbl WTI and $2.98 per MMBtuHH, and $42.75 per Bbl WTI and $2.48 per MMBtu HH, respectively.Proved Undeveloped Reserves Net Reserves, MBoe At December 31, 2018 2017 2016Beginning of year 48,082 40,057 49,184Converted to proved developed (8,643) (2,196) (1,352)Additions from capital program 27,978 11,717 —Removed from capital program (2,527) (7,577) Acquisitions — — —Revisions 3,196 6,081 (7,775)End of year 68,086 48,082 40,05718Table of ContentsAt December 31, 2018, our proved undeveloped reserves were 68,086 MBoe, all of which are scheduled to be drilled within five years from the datethey were initially recorded. During 2018, the Company converted 18% of its proved undeveloped reserves (29 gross wells representing net reserves of 8,643MBoe) at a cost of $127.8 million. The net increase of 27,978 Mboe in PUD additions is the result of adding 92 XRL and 18 SRL infill PUD locations in theCompany's southern “French Lake” area and 14 XRL and 12 SRL PUD locations in other areas that are captured in our five-year drilling program. TwelvePUD locations were removed from our reserve base as they were no longer part of our five-year drilling program.At December 31, 2017, our proved undeveloped reserves were 48,082 MBoe, all of which were scheduled to be drilled within five years of theirinitial proved booking date. During 2017, the Company converted 6% of its proved undeveloped reserves (seven gross wells representing net reserves of2,196 MBoe) at a cost of $26.1 million. The net increase of 4,140 Mboe in PUD additions are the result of adding infill PUD locations that were on the 2018rig schedule, offset by PUD locations that were removed due to a changes in our development strategy. The increase in revisions was primarily due to theforecasted production uplift resulting from enhanced completion designs.At December 31, 2016, our proved undeveloped reserves were 40,057 MBoe, all of which were scheduled to be drilled within five years of theirinitial proved booking date. During 2016, the Company converted 3% of its proved undeveloped reserves (seven gross wells representing net reserves of1,352 MBoe) at a cost of $16.2 million. Our 2016 capital program was suspended after the first quarter, and no proved undeveloped locations were added as aresult of drilling. The net decrease in our PUD reserves from December 31, 2015 to December 31, 2016 was mainly the result of removing 7.8 MMBoe ofPUDs in the Mid-Continent region, as drilling focus shifted entirely to the Wattenberg Field. Thirty-eight Wattenberg proved undeveloped locations notwithin areas in close proximity to existing CPFs were demoted and were replaced with 42 infill proved undeveloped locations that were near existing CPFs.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. The reserves estimates for the year ended December 31, 2018 and2017 shown herein have been independently prepared by NSAI. These NSAI reserve estimates are reviewed by our in-house petroleum engineer who overseesand controls preparation of the reserve report data by working with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI for theirevaluation process. The Company's technical person who was primarily responsible for overseeing the preparation of our reserve estimates was our Managerof Corporate Reserves who has over 30 years of experience in the oil and gas industry, including four years in her role at the Company. Her professionalqualifications include a bachelor's degree in Petroleum Engineering from the University of Wyoming and a master's degree in Petroleum Engineering fromthe Colorado School of Mines.For the year ended December 31, 2016 the Company prepared the reserves estimate, which were audited by NSAI. The responsibility for compliancein reserves estimation was delegated to our internal corporate reservoir engineering group. The Company's Corporate Reserves Manager, at that time, had aBachelor of Science degree in Geological Engineering and a Master of Science degree in Mineral Economics from the Colorado School of Mines and hadbeen in the petroleum industry for 41 years. Our internal corporate reservoir engineering group had over 85 years of industry experience.Independent Reserve EngineersThe reserves estimates shown herein for December 31, 2018 and 2017 have been independently evaluated by Netherland, Sewell & Associates, Inc.(NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 andperforms consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technicalpersons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Benjamin W. Johnson and Mr. JohnG. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAIsince 2007 and has over 2 years of prior industry experience. He graduated from Texas Tech University in 2005 with a Bachelor of Science Degree inPetroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geophysics (No. 559), has been practicing consultingpetroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with aBachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from SaintMary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, andexperience requirements set forth19Table of Contentsin the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both areproficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reservesdefinitions and guidelines.Production, Revenues and Price HistoryOil and gas prices fluctuated significantly during 2018 and the beginning of 2019. Oil prices are impacted by production levels, crude oilinventories, real or perceived geopolitical risks in oil producing regions, the relative strength of the U.S. dollar, weather and the global economy. Duringperiods of favorable pricing, we expect increased industry activity, which could moderate the magnitude of price increases throughout the year.Sensitivity AnalysisIf oil and natural gas SEC prices declined by 10%, our proved reserve volumes would decrease by 0.3% and our PV-10 value as of December 31,2018 would decrease by approximately 23% or $223.1 million. If oil and natural gas SEC prices increased by 10%, our proved reserve volumes wouldincrease by 0.4% and our PV-10 value as of December 31, 2018 would increase by approximately 24% or $229.8 million.ProductionThe following table sets forth information regarding oil, natural gas, and natural gas liquids production, sales prices, and production costs for theperiods indicated. For additional information on price calculations, please see information set forth in Part II, Item 7. Management’s Discussion and Analysisof Financial Condition and Results of Operations.20Table of Contents Successor Predecessor For the YearEnded December31, 2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April 28,2017 For the YearEnded December31, 2016Oil: Total Production (MBbls) 3,840.8 2,012.7 1,068.5 4,309.9 Wattenberg Field 3,500.2 1,568.5 834.4 3,470.7 Dorcheat Macedonia Field 340.6 379.9 193.2 750.0Average sales price (per Bbl), including derivatives(3) $54.77 $46.44 $48.29 $39.57Average sales price (per Bbl), excluding derivatives(3) $59.38 $47.18 $48.29 $35.32Natural Gas: Total Production (MMcf) 8,591.2 5,767.5 3,242.5 11,906.3 Wattenberg Field 7,408.3 4,588.1 2,564.9 9,574.8 Dorcheat Macedonia Field 1,182.8 1,179.3 677.6 2,331.4Average sales price (per Mcf), including derivatives(4) $2.39 $2.29 $2.57 $1.76Average sales price (per Mcf), excluding derivatives(4) $2.45 $2.29 $2.57 $1.76Natural Gas Liquids: Total Production (MBbls) 1,141.2 712.9 422.7 1,491.1 Wattenberg Field 1,048.3 656.2 391.1 1,354.3 Dorcheat Macedonia Field 92.8 56.8 31.6 136.8Average sales price (per Bbl), including derivatives $22.46 $18.38 $17.52 $12.39Average sales price (per Bbl), excluding derivatives $22.46 $18.38 $17.52 $12.39Oil Equivalents: Total Production (MBoe) 6,413.8 3,686.9 2,031.6 7,785.4 Wattenberg Field 5,783.2 2,989.4 1,653.0 6,420.8 Dorcheat Macedonia Field 630.6 633.2 337.7 1,275.4Average Daily Production (Boe/d) 17,572.0 15,048.4 16,930.4 21,271.7 Wattenberg Field 15,844.0 12,201.5 13,774.9 17,543.4 Dorcheat Macedonia Field 1,728.0 2,584.5 2,814.3 3,484.5Average Production Costs (per Boe)(1)(2) $7.11 $9.28 $8.20 $7.25_________________________(1)Excludes ad valorem and severance taxes.(2)Represents lease operating expense and gas plant and midstream operating expense per Boe using total production volumes of 6,413.8 MBoe, 3,686.9MBoe, 2,031.6 MBoe, and 7,785.4 MBoe for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and the 2016 PredecessorPeriod, respectively. Total production volumes exclude volumes from our percentage-of-proceeds contracts in our Mid-Continent region of 65.0 MBoe,77.9 MBoe, 41.9 MBoe, and 150.1 MBoe for the Current Successor Period 2017 Successor Period, 2017 Predecessor Period, and the 2016 PredecessorPeriod, respectively.(3)Crude oil sales excludes $0.6 million, $0.2 million, $0.1 million, and $0.5 million of oil transportation revenues from third parties, which do not haveassociated sales volumes, for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and the 2016 Predecessor Period,respectively.(4)Natural gas sales excludes $1.3 million, $0.8 million, $0.4 million, and $1.5 million of gas gathering revenues from third parties, which do not haveassociated sales volumes, for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and the 2016 Predecessor Period,respectively.Principal CustomersOne of our customers, NGL Crude Logistics, LLC comprised 66% of our total revenue for the year ended December 31, 2018. No other single non-affiliated customer accounted for 10% or more of our oil and natural gas sales in 2018. We believe the loss of any one customer would not have a materialeffect on our financial position or results of operations because there are numerous potential customers for our product.21Table of ContentsDelivery CommitmentsThe Company entered into a new purchase agreement upon emergence from bankruptcy. The terms of the agreement consists of defined volumecommitments over an initial seven-year term. The Company will be required to make periodic deficiency payments for any shortfalls in delivering minimumvolume commitments, which are set in six-month periods beginning in January 2018. The Company's capital program is designed to exceed these minimumvolume commitments. During 2018, the average minimum volume commitment was approximately 10,100 barrels per day and increased by approximately41% from 2018 to 2019 and approximately 3% each year thereafter for the remainder of the contract, to a maximum of approximately 16,000 barrels per day.The aggregate financial commitment fee over the seven-year term, based on the minimum volume commitment schedule (as defined in the agreement) and theapplicable differential fee, is $136.3 million as of December 31, 2018. Please refer to Part II, Item 8, Note 8 - Commitments and Contingencies for additionaldiscussion.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, 2018. Oil(2) Natural Gas(1) Total(2) Operated(2) Gross Net Gross Net Gross Net Gross NetRocky Mountain 695.0 556.1 — — 695.0 556.1 580.0 464.1__________________________(1)All gas production is associated gas from producing oil wells.(2)Count was obtained 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, 2018, along with the PV-10 value. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary. Undeveloped Developed Acres Acres Total Acres Gross Net Gross Net Gross Net PV-10Wattenberg Field - Rocky Mountain 66,479 54,681 25,685 10,739 92,164 65,420 955.0 Total 66,479 54,681 25,685 10,739 92,164 65,420 $955.0Undeveloped acreageWe critically review and consider at-risk leasehold with attention to our ability either to convert term leasehold to held-by-production status orobtain term extensions. Decisions to let leasehold expire generally relate to areas outside of our core area of development or when the expirations do not posematerial impacts to development plans or reserves.The following table sets forth the number of net undeveloped acres by area as of December 31, 2018 that will expire over the next three years unlessproduction is established within the spacing units covering the acreage or the applicable leases are extended prior to the expiration dates: Expiring 2019 Expiring 2020 Expiring 2021 Gross Net Gross Net Gross NetRocky Mountain 1,019 432 7,962 2,959 2,723 1,42922Table of ContentsDrilling ActivityThe following table describes the exploratory and development wells we drilled and completed during the years ended December 31, 2018, 2017,and 2016. For the Years Ended December 31, 2018 2017 2016 Gross Net Gross Net Gross NetExploratory Productive Wells — — — — — —Dry Wells — — — — — — Total Exploratory — — — — — —Development Productive Wells 27 21.9 4 4.0 4 3.9Dry Wells — — — — — — Total Development 27 21.9 4 4.0 4 3.9Total 27 21.9 4 4.0 4 3.9The following table describes the present operated drilling activities as of December 31, 2018. As of December 31, 2018 Gross NetExploratory Rocky Mountain — — Total Exploratory — —Development Rocky Mountain 50 40.4 Total Development 50 40.4Total 50 40.4Capital Expenditure BudgetThe Company's 2019 capital budget of $230.0 million to $255.0 million assumes a continuous one-rig development pace. The drilling andcompletion portion of the budget is expected to be approximately $210.0 million to $220.0 million, which will support drilling 59 gross wells and turning tosales 45 gross wells. Included in the drilling completion budget is $15.0 million for non-operated capital. Of the operated wells planned to be drilled,approximately 26 are XRL wells and 33 are SRL wells. Of the wells planned to be completed, 16 are XRL wells, five are MRL wells, and 24 are SRL wells.The remaining 2019 capital budget of $20.0 million to $35.0 million is to support infrastructure and leasehold costs. Actual capital expenditures could varysignificantly based on, among other things, market conditions, commodity prices, drilling and completion costs, well results, and changes in the borrowingbase under our Current Credit Facility.Derivative ActivityIn addition to supply and demand, oil and gas prices are affected by seasonal, economic, local and geo-political factors that we can neither controlnor predict. We attempt to mitigate a portion of our exposure to potentially adverse market changes in commodity prices and the associated impact on cashflows through the use of derivative contracts. We have successfully hedged approximately 54% and 59% of our average 2019 guided production as ofDecember 31, 2018 and as of the filing date of this report, respectively.As of December 31, 2018, the Company had entered into the following commodity derivative contracts:23Table of Contents Crude Oil (NYMEX WTI) Natural Gas (NYMEX Henry Hub) Natural Gas (CIG Basis) Natural Gas (CIG) Bbls/day Weighted Avg. Price perBbl MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu1Q19 Cashless Collar 4,000 $50.88/$63.83 7,600 $2.75/$3.22 — — — —Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 10,000 $2.17Put 500 $55.00 — — — — — —2Q19 Cashless Collar 5,330 $54.42/$67.57 2,505 $2.75/$3.22 — — — —Swap 3,500 $57.84 — — — — 16,703 $2.11Put 500 $55.00 — — — — — —3Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — —Swap 5,000 $59.92 — — — — 20,000 $2.10Put 500 $55.00 — — — — — —4Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — —Swap 5,000 $59.92 — — — — 20,000 $2.10Put 500 $55.00 — — — — — —1Q20 Swap 3,000 $63.48 — — — — — —As of the filing date of this report, the Company had entered into the following commodity derivative contracts: Crude Oil (NYMEX WTI) Natural Gas (NYMEX Henry Hub) Natural Gas (CIG Basis) Natural Gas (CIG) Bbls/day Weighted Avg. Price perBbl MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu1Q19 Cashless Collar 4,656 $51.46/$65.40 7,600 $2.75/$3.22 — — — —Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 11,639 $2.20Put 172 $55.00 — — — — — —2Q19 Cashless Collar 6,330 $54.51/$68.74 2,505 $2.75/$3.22 — — — —Swap 3,500 $57.84 — — — — 19,203 $2.15Put — — — — — — — —3Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — —Swap 5,000 $59.92 — — — — 22,500 $2.13Put — — — — — — — —4Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — —Swap 5,000 $59.92 — — — — 22,500 $2.13Put — — — — — — — —1Q20 Swap 3,000 $63.48 — — — — 2,500 $2.40Collar 2,000 $55.00/$62.00 — — — — — —Bankruptcy Proceedings under Chapter 11On January 4, 2017, the Company and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions under Chapter11 in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors received bankruptcy court confirmation of theirThird Amended Joint Prepackaged Plan of Reorganization, dated April 6, 2017 (the “Plan”), and emerged from bankruptcy on April 28, 2017 (the “EffectiveDate”). For additional information about our bankruptcy proceedings and emergence, please refer to Part II, Item 8, Note 15 - Chapter 11 Proceedings andEmergence.24Table of ContentsUpon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. Uponadoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date, which differed materially from therecorded values of those same assets and liabilities in the Predecessor Company. As a result, our balance sheets and statement of operations subsequent to theEffective Date are not comparable to our balance sheets and statements of operations prior to the Effective Date. For additional information about ourapplication of fresh-start accounting, please refer to Part II, Item 8, Note 16 - Fresh-Start Accounting. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequentto April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or priorto April 28, 2017. References to “2017 Successor Period” relates to the period of April 29, 2017 through December 31, 2017. References to “2017Predecessor Period” relate to the period of January 1, 2017 through April 28, 2017. References to “2016 Predecessor Period” relate to the period of January 1,2016 through December 31, 2016.Title to PropertiesOur properties are subject to customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for currenttaxes, other industry‑related constraints, and certain other leasehold restrictions. We do not believe that any of these burdens materially interfere with our useof the properties in the operation of our business. We believe that we have satisfactory title to all of our producing properties. We undergo a thorough titlereview process upon receipt of title opinions received from outside legal counsel before we commence drilling operations. Although title to our properties issubject to complex interpretation of multiple conveyances, deeds, reservations, and other instruments that serve to affect mineral title, we believe that none ofthese risks will materially detract from the value of our properties or from our interest therein or otherwise materially interfere with the operation of ourbusiness.CompetitionThe oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that often have greaterresources. Many of these companies explore for, produce, and market oil and natural gas, carry on refining operations, and market the resultant products on aworldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drillingand development 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 andpotential impacts of these risks are difficult to accurately predict.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, 2018 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oilprices. During the year ended December 31, 2018, the daily NYMEX WTI oil spot price ranged from a high of $77.41 per Bbl to a low of $44.48 per Bbl, andthe NYMEX natural gas HH spot price ranged from a high of $6.24 per MMBtu to a low of $2.49 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 customary, or because premium costs are considered cost prohibitive. A loss not fully covered by insurance could have a material adverse effecton our financial position, results of operations, or cash flows.Regulation 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. The jurisdiction in which we own and operateproperties or assets for oil and natural gas production has statutory provisions regulating the exploration for and production of oil and natural gas, including,among other things, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method ofdrilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of25Table of Contentswater used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws andregulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and theunitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose certainrequirements regarding the ratability or fair apportionment of production 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. Because such laws and regulations are frequently revised and amended through various legislative actions andrulemakings, it is difficult to predict the future costs or impact of compliance. Additional rulemakings that affect the oil and natural gas industry are regularlyconsidered at the federal, state, and various local government levels, including statutorily and through powers granted to various agencies that regulate ourindustry, and various court actions. We cannot predict when or whether any such rulemakings may become effective or if the outcomes will negatively affectour operations.We believe that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cashflows, or results of operations. However, current regulatory requirements may change, currently unforeseen incidents may occur, or past noncompliance withlaws or regulations may be discovered.Regulation 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, among other things, permits for drilling operations, drilling bonds, and reports concerningoperations. Colorado, the state in which we own and operate all of our properties, has regulations governing conservation matters, including provisions forthe spacing and unitization or pooling of oil and natural gas properties, the regulation of well spacing and well density, and procedures for proper pluggingand abandonment of wells. The intent of these regulations is to promote the efficient recovery of oil and gas reserves while reducing waste and protectingcorrelative rights. By collaborating with industry’s exploration and development operations, these regulations effectively identify where wells can be drilled,well densities by geologic formation, and the appropriate spacing and pooling unit size to effectively drain the resources. Operators can apply for exceptionsto such regulations, including applications to increase well densities to more effectively recover the oil and gas resources. Moreover, Colorado imposes aproduction or severance 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 one U.S. state, Colorado. This state regulates drilling and operating activities by requiring, amongother things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, themethod of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells.Colorado laws also govern a number of environmental and conservation matters, including the handling and disposal of waste materials, air pollution, thesize of drilling and spacing units or proration units, the density of wells that may be drilled, and the unitization and pooling of oil and gas properties.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 the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastaterates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way thatis materially different from how it affects operations of our competitors who are similarly situated.26Table of ContentsRegulation 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.FERC 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 appropriations forgrants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Actof 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, in connectionwith the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation more accessible to natural gas servicessubject to the jurisdiction of FERC, for any entity, directly or indirectly, (1) 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,environmental, and, in some circumstances, nondiscriminatory-take requirements. Although nondiscriminatory-take regulation has not generally beenaffirmatively applied by 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 such27Table of Contentscommodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning marketinformation 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 the state in which we operate and ship natural gas on an intrastate basis will not affectour operations in any way that is materially different from how it affects operations of our competitors. Like the regulation of interstate transportation rates,the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our naturalgas.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.Regulation of derivativesThe 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.Environmental, Health and Safety RegulationOur natural gas and oil exploration and production operations are subject to numerous stringent federal, regional, state, and local laws andregulations governing safety and health, the discharge of materials into the environment, or otherwise relating to protection of the environment or naturalresources, noncompliance with which can result in substantial administrative, civil, and criminal penalties and other sanctions, including suspension orcessation of operations. These laws and regulations may, among other things, require the acquisition of permits before drilling or other regulated activitycommences; restrict the types, quantities, and concentrations of various substances that can be released into the environment; govern the sourcing anddisposal of water used in the drilling and completion process; limit or prohibit drilling activities that impact threatened or endangered species or that occur incertain areas and on certain lands lying within wilderness, wetlands, frontier, and other protected areas; require some form of investigation or remedial actionto prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteriaaddressing worker and natural resource protection and impose substantial liabilities for pollution resulting from operations or failure to comply withregulatory filing obligations. Cumulatively, these laws and regulations may impact our rate of production.The following is a summary of the more significant existing environmental and health and safety laws and regulations to which we are subject andfor which compliance may have a material adverse impact on our capital expenditures, results of operations, or financial position.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, transmission,and storage operations to regulation under the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. These regulations establishspecific new requirements regarding emissions28Table of Contentsfrom production-related wet seal and reciprocating compressors and from certain pneumatic controllers and storage vessels. The EPA issued revised rules in2013 and 2014 in response to requests for reconsideration of portions the 2012 NESHAP rules from industry and the environmental community. In May2016, the EPA issued New Source Performance Standards (“NSPS”) rules focused on achieving additional methane and volatile organic compound reductionsfrom oil and natural gas operations. Among other things, these revisions impose new requirements for leak detection and repair, control requirements for oilwell completions, and additional control requirements for gathering, boosting, and compressor stations. EPA proposed further revisions to the NSPS rules onSeptember 11, 2018 intended to roll back parts of the 2016 rules. The proposed revisions address certain technical issues raised in administrative petitionsand include proposed changes to, among other things, the frequency for monitoring fugitive emissions at well sites and compressor stations.In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) adopted new andrevised air quality regulations that impose stringent new requirements to control emissions from both existing and new or modified oil and gas facilities inColorado. The regulations include new emissions control, monitoring, recordkeeping, and reporting requirements on oil and gas operators in Colorado. Forexample, the regulations impose Storage Tank Emission Management (“STEM”) requirements for certain new and existing storage tanks. The STEMrequirements require us to install costly emission control technologies as well as monitoring and recordkeeping programs at most of our new and existingwell production facilities. The new Colorado regulations also impose a Leak Detection and Repair (“LDAR”) program for well production facilities andcompressor stations. The LDAR program primarily targets hydrocarbon (i.e., methane) emissions from the oil and gas sector in Colorado and represents asignificant new use of state authority regarding these emissions.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 standard non-attainment status from “marginal”to “moderate.” Oil and natural gas operations in ozone non-attainment areas, including in the DM/NFR area, may be subject to increased regulatory burdensin the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. Based on 2018 air qualitymonitoring data, the DM/NFR area may be reclassified to “serious” non-attainment on January 1, 2020 because the area does not meet the 2008 NAAQS for2018. A “serious” classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent airquality control requirements applicable to our operations and significant operating costs and delays in obtaining necessary permits for new and modifiedproduction facilities.In May 2016, the EPA also finalized a rule regarding source determination, including defining the term “adjacent” under the CAA, which affectshow major sources are defined, particularly regarding criteria for aggregating multiple small surface sites into a single source for air quality permittingpurposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major sources, therebytriggering more stringent air permitting requirements. These EPA rulemakings will have nominal effect on our operations, because the rule clarified ourexisting presumption on “adjacent” and presents no conflict with the state of Colorado definitions.The EPA also published Control Technique Guidelines (“CTGs”) in October 2016 aimed at providing states with guidance and setting apresumptive floor for Reasonably Achievable Control Technology (“RACT”) for the oil and gas industry in areas of ozone non-attainment, including theDM/NFR area. In November 2017, as required following issuance of the CTGs, the Colorado Air Quality Control Commission AQCC adopted additionalRACT and other air quality regulations that increased emissions control, monitoring, recordkeeping, and reporting requirements on oil and gas operators inthe DM/NFR area, and to some extent state-wide.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.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 to29Table of Contentshydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water,the potential for hydrocarbon migration, the disclosure of the chemicals used in fracturing, or other matters. Colorado, for example, comprehensively updatedits oil and gas regulations in 2008 and adopted significant additional amendments in 2011, 2013, 2014, 2015, 2016, and 2018. Among other things, theupdated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additionalinformation regarding wellbore integrity, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance betweenoccupied structures and oil and gas wells, undertake additional mitigation for nearby residents, implement additional groundwater testing, undertake certainmeasures to minimize flood risks, and comply with new requirements for the installation and operation of flowlines. In 2014, Colorado enacted legislation toincrease the potential sanctions for statutory, regulatory and other violations. Among other things, this legislation and its implementing regulations mandatemonetary penalties for certain types of violations, require a penalty to be assessed for each day of violation and significantly increase the maximum dailypenalty amount. Colorado has also expanded its inspection and enforcement of staff. In early 2016, Colorado adopted rules imposing additional permittingrequirements for certain large scale facilities in urban mitigation areas and additional notice requirements prior to engaging in operations near certainmunicipalities. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increaseour operating costs and cause delays or interruptions of our operations. In 2018, Colorado adopted rules requiring new wells and production facilities to besited at least 1,000 feet from school facilities and child care centers.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 the definitionof “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for EOR is not excluded.Federal agencies have periodically considered additional regulation of hydraulic fracturing. The EPA has published guidance for issuingunderground injection permits that would regulate hydraulic fracturing using diesel fuel. This guidance eventually could encourage other regulatoryauthorities to adopt permitting and other restrictions on the use of hydraulic fracturing. As noted above, in June 2016, EPA finalized regulations that addressdischarges of wastewater pollutants from onshore unconventional extraction facilities to publicly-owned treatment works. Regulated entities are required tocome into compliance with these standards by August 29, 2019. The EPA also published a study of the impact of hydraulic fracturing on drinking waterresources in December 2016, which concluded that drinking water resources can be affected by hydraulic fracturing under specific circumstances. The resultsof this study could result in additional regulations, which could lead to operational burdens similar to those described above. As also noted above, in January2017, the EPA issued a proposed rule to include natural gas processing facilities in the Toxic Release Inventory (“TRI”) program. The United StatesDepartment of the Interior also finalized a new rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellboreintegrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission andthe rule as promulgated are subject to ongoing litigation. Additionally, in early 2016, the Bureau of Land Management (“BLM”) proposed rules related tofurther controlling the venting and flaring of natural gas on BLM land. On September 28, 2018, the BLM published a final rule that revises the 2016 rules.The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, wellcompletion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule alsorevised provisions related to venting and flaring. Environmental groups and the states of California and New Mexico have filed challenges to the 2018 rulein the United States District Court for the Northern District of California.Apart from these ongoing federal and state initiatives, some local governments have adopted their own new requirements on hydraulic fracturingand other oil and gas operations. Voters in Colorado have proposed or advanced initiatives restricting or banning oil and gas development in Colorado, butthese initiatives have failed to date. Legislation has also been introduced in Colorado to increase local control regarding oil and gas development. Althoughthis legislation was not adopted, similar legislation could be enacted in the future. Any successful bans or moratoriums where we operate could increase thecosts of our operations, impact our profitability, and even prevent us from drilling in certain locations. In addition, in light of concerns about seismic activitybeing triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismicsafety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states with areas of increased rates of induced seismicity thatcould be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost ofdoing business could cause have a material adverse effect on our business.30Table of ContentsAt 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. We cannot assure you that any suchoutcome 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 the Rocky Mountain region.Typical hydraulic fracturing treatments are made up of water, chemical additives, and sand. We utilize major hydraulic fracturing service companieswho track and report additive chemicals that are used in fracturing as required by the appropriate government agencies, including FracFocus, the nationalhydraulic fracturing chemical registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. Each of theservice companies we use fracture stimulate a multitude of wells for the industry each year.We periodically review our plans and policies regarding oil and gas operations, including hydraulic fracturing, in order to minimize any potentialenvironmental impact. 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.Other 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. On August 22, 2017, Colorado Governor John Hickenlooper announced seven policy initiatives developed during the Colorado’sreview of oil and gas operations. One rulemaking initiative resulting from Colorado’s review was a strengthening of COGCC’s flowline regulations andrequirements. COGCC finalized the new flowline rules on February 19, 2018. The new rule includes: increased registration requirements, flowline designrequirements, integrity management requirements, and leak detection programs, and requirements for abandoned flowlines. Over the past several years, theCOGCC has also approved new rules regarding various other matters, including wellbore integrity, hydraulic fracturing, well control, waste management,spill reporting, spacing of wells and pooling of mineral interests, and an increase in potential sanctions for COGCC rule violations. Additionally, the COGCCapproved rules regarding minimum setbacks, groundwater monitoring, large-scale facilities in urban mitigation areas, and public notice requirements that areintended to prevent or mitigate environmental impacts of oil and gas development and include the permitting of wells. Depending on how these and anyother new rules are applied, they could add substantial increases in well costs for our Colorado operations. The rules could also impact our ability to operateand extend the time necessary to obtain drilling permits, which would create substantial uncertainty about our ability to meet future drilling plans and thusproduction 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 early 2016, COGCC finalized a rulemaking to implement rules applicable to the permittingof large-scale oil and gas facilities in urban mitigation areas and rules requiring operators to register with and provide operational information, includingadvance notice for certain operations, to municipalities prior to conducting oil and gas operations.In 2016, the Colorado Supreme Court ruled that the cities of Fort Collins and Longmont do not have authority to ban oil and gas operations withintheir jurisdictional limits. Although we do not own or lease minerals or operate within any of these municipal areas, the Colorado Supreme Court decision hasbearing on our ability to continue to operate in Colorado. Further, Weld County completed implementation of a revised local government permitting processfor land use approval, and Boulder County substantially revised its oil and gas regulations. We do not expect that these local government regulations willhave any material impact on our operations.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 on certain classes of persons who are considered to beresponsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where therelease occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these potentially“responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released31Table of Contentsinto the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners andother third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We areable to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wellsoperated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributedto us. We generate materials in the course of our operations that may be regulated as or contain CERCLA hazardous substances but we are not aware of anyliabilities for which we may be held responsible that would materially or adversely affect us.The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage,disposal, and cleanup of hazardous wastes, and distinguishes between hazardous and non-hazardous or solid wastes. With the approval of the EPA, theindividual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent hazardous wasterequirements, while all states regulate solid waste. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development,and production of natural gas and oil are currently regulated under RCRA’s non-hazardous waste provisions and state solid waste laws. However, legislationhas been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certainnatural gas and oil exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling,disposal, and clean-up requirements. For example, in May 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District ofColumbia that seeks to compel the EPA to review and, if necessary, revise its regulations regarding existing exemptions for exploration and productionrelated wastes. On December 28, 2016, the EPA entered into a consent decree with those environmental groups to settle the lawsuit, which requires the EPAby March 15, 2019 to either propose new regulations regarding exploration and production related wastes or sign a determination that revision of suchregulations is not necessary. If the EPA proposes new rulemaking, the 2016 consent decree requires the EPA to take final action on such rules no later thanJuly 15, 2021.We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore for and produce oiland natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, exploration and production fluidsand gases may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where thesehydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whosetreatment and disposal or release of hydrocarbons and wastes were not under our control. These properties and wastes disposed thereon may be subject toCERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastesdisposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators),to pay for damages for the loss or impairment 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 in January 2017, EPA issued a proposed ruleto include natural gas processing facilities in the TRI program. EPA review of comments on this proposed rule is ongoing.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 penalties, liability for natural resourcesdamages, and significant business interruption. The U.S. Department of Transportation has adopted safety regulations with respect to the design,construction, operation, maintenance, inspection, and management of our pipeline and storage facilities. These regulations contain requirements for thedevelopment and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction ofanomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators developcomprehensive 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, the Pipeline and Hazardous Materials Safety Administration(“PHMSA”) has issued new rules to strengthen federal pipeline safety enforcement programs. In 2015, PHMSA proposed to expand its regulations in anumber of ways, including through the32Table of Contentsincreased regulation of gathering lines, even in rural areas. In 2016, PHMSA increased its regulations to require crude oil sampling and reporting as an“offeror” (as defined under the PHMSA) and increased its civil penalty structure.Climate changeBased on EPA findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public healthand the environment, the EPA adopted regulations under the CAA that, among other things, established Prevention of Significant Deterioration (“PSD”),construction, and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions ofregulated pollutants. In a subsequent ruling, the U.S. Supreme Court upheld a portion of EPA’s GHG stationary source program, but also invalidated a portionof it, holding that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACTrequirements, but that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with EPA’s GHG BACT requirements.Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case tothe extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above theapplicable major source thresholds. In October 2016, EPA issued a proposed rule to further revise its PSD and Title V regulations applicable to GHGs inaccordance with these court rulings, including a proposed de minimis level of GHG emissions below which BACT is not required. This rulemaking process isongoing. Depending on an EPA’s final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smallerstationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations, and may also adversely affectdemand for the oil and natural gas that we produce.In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGs from specified onshore and offshore oil and gas productionsources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordancewith the GHG emissions reporting rule.In August of 2015, the EPA finalized rules to further reduce GHG emissions, primarily from coal-fired power plants, under its Clean Power Plan(“CPP”). On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the CPP regulations. Following the Executive Order, onApril 4, 2017, the EPA announced that it was formally reviewing the CPP. On October 9, 2017, the EPA published a proposed rule to repeal the Clean PowerPlan. The comment period on the proposed rule closed on April 26, 2018. On August 21, 2018, EPA proposed the Affordable Clean Energy (“ACE”) rule,which would establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACEwould replace the CPP, and the rulemaking process is ongoing.Congress has, from time to time, considered but not yet passed legislation to reduce emissions of GHGs. In addition, a number of state and regionalefforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources ofGHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.Additional GHG regulation may also result from the December 2015 agreement that the United States reached during the December 2015 UnitedNations climate change conference in Paris, France (the “Paris Agreement”). Within the Paris Agreement, the United States agreed to reduce its GHGemissions by 26-28% by the year 2025 as compared with 2005 levels, and provide periodic updates on its progress. On June 1, 2017, President Trumpannounced that the United States would withdraw from the Paris Agreement. Although President Trump has the authority to unilaterally withdraw the UnitedStates from the Paris Agreement, it is not clear at this time what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether anew agreement can be negotiated, or what terms would be included in such an agreement.Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impactour business, any such future laws and regulations imposing reporting obligations on, or limiting, emissions of GHGs from our equipment and operationscould require us to incur costs to reduce emissions of GHGs associated with our operations. Severe limitations on GHG emissions could adversely affect ourproduction operations and/or demand for the oil and natural gas we produce. Moreover, incentives to conserve energy or use alternative energy sources as ameans of addressing climate change could also reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potentialeffects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds,and other sources of capital restricting or eliminating their investment in oil and natural gas activities.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 of the U.S., including spills and leaks33Table of Contentsof hydrocarbons and produced water. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for thedischarge of wastewater or storm water and are required to develop and implement spill prevention, control, and countermeasure plans, also referred to as“SPCC plans,” in connection with on-site storage of significant quantities of oil. As properties are acquired, we determine the need for new or updated SPCCplans and, where necessary, will develop or update such plans to implement physical and operation controls, the costs of which are not expected to bematerial. In June 2015, the EPA and the U.S. Army Corps of Engineers adopted a new regulatory definition of “waters of the U.S.” (“WOTUS”), which governswhich waters and wetlands are subject to the CWA. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters ofthe United States until 2020. On August 16, 2018, the U.S. District Court for South Carolina found that the EPA and the Corps failed to comply with theAdministrative Procedure Act and struck the 2018 rule that attempted to delay the applicability date of the 2015 rule. Other district courts, however, haveissued rulings temporarily enjoining the applicability of the 2015 rule itself. On December 11, 2018, the EPA and the Corps issued a proposed new rule thatwould differently revise the definition of “waters of the United States” and essentially replace both the 1986 rule and the 2015 rule. According to theagencies, the proposed new rule is “intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of theUnited States’ federally regulated under the Act.” If finalized, this new definition of “waters of the United States” will likely be challenged and sought to beenjoined in federal court. Until that time, regulations are being implemented as they were prior to August 2015. Additionally, in June 2016, the EPA finalizednew CWA pretreatment standards that would prevent onshore unconventional oil and natural gas wells from discharging wastewater pollutants to publicly-owned treatment facilities. Regulated entities are required to come into compliance with these pretreatment standards by August 29, 2019.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 and suitable habitat areas are designated was finalized by the U.S. Fish and Wildlife Service in 2016. Some of our facilities may belocated in areas that are designated as habitat for endangered or threatened species. The designation of previously unidentified endangered or threatenedspecies could cause us to incur additional costs or become subject to 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 (“OSHA”), andcomparable state statutes, the purpose of which are to protect the health and safety of workers. In 2016, there were substantial revisions to the regulationsunder OSHA that may impact our operations. These changes include among other items: record keeping and reporting, revised crystalline silica standard(which requires the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021),naming oil and gas as a high hazard industry, and requirements for a safety and health management system. In addition, OSHA’s hazard communicationstandard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable statestatutes, requires that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided toemployees, state and local government authorities, and citizens.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. The vast majority of our exploration and productionactivities are not on federal lands. This environmental impact assessment process has the potential to delay or limit, or increase the cost of, the developmentof natural gas and oil projects on federal lands. 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 the34Table of ContentsU.S. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply insome circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted fromviolation of a federal safety, construction, or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limitslikewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including thepreparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred inconnection with an oil spill.EmployeesAs of December 31, 2018, we had 144 employees, of which 20 full-time employee equivalents were dedicated to our Rocky Mountain Infrastructure,LLC operations. We also utilized the services of numerous independent contractors to perform various field and other services. Our future success will dependpartially on our ability to attract, retain, and motivate qualified personnel. We are not a party to any collective bargaining agreements and have notexperienced any strikes or work stoppages.OfficesAs of December 31, 2018, we leased 63,783 square feet of office space in Denver, Colorado at 410 17th Street where our principal offices are located,and we leased 7,780 square feet near our operations in Weld County, Colorado, where we have a field office and storage facilities. We also own a field officein Evans, Colorado.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 is not incorporated by reference into thisAnnual 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 BusinessFurther declines, in oil and, to a lesser extent, natural gas prices, will adversely affect our business, financial condition or results of operations, and ourability 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,access to capital, present value and quality of our reserves, the nature and scale of our operations, and future rate of growth. Oil and natural gas arecommodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, themarkets 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 donot necessarily fluctuate in direct relation to each other. Because approximately 76% of our estimated proved reserves as of December 31, 2018 were oil andNGLs, our financial results are more sensitive to movements in oil prices. Since mid-2014, the price of crude oil has significantly declined and has notregained previous highs. As a result, we experienced significant decreases in crude oil revenues and recorded asset impairment charges. A prolonged period oflow market prices for oil, natural35Table of Contentsgas, and NGLs or further declines in the market prices for oil and natural gas, could result in capital expenditures being further reduced and will adverselyaffect our business, financial condition, and liquidity and our ability to meet obligations, targets, or financial commitments. During the year endedDecember 31, 2018, the daily New York Mercantile exchange (“NYMEX”) WTI oil spot price ranged from a high of $77.41 per Bbl to a low of $44.48 perBbl, and the NYMEX natural gas HH spot price ranged from a high of $6.24 per MMBtu to a low of $2.49 per MMBtu. As of February 25, 2019, the dailyNYMEX WTI oil spot price and NYMEX natural gas HH spot price was $55.33 per Bbl and $2.84 per MMBtu, 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;•variability in subsurface reservoir characteristics, particularly in areas with immature development history;•the availability of pipeline capacity and infrastructure; and•the price and availability of alternative fuels.Substantially all of our production is sold to purchasers under contracts at market-based prices. Declines in commodity prices may have thefollowing 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 reduction in our liquidity and inability to payour liabilities as they come due;•certain properties in our portfolio becoming economically unviable;•delay or postponement of some of our capital projects;•significant reductions in future capital programs, resulting in a reduced ability to develop our reserves;•limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;•reduction to the borrowing base under our Current Credit Facility or limitations in our access to sources of capital, such as equity or debt;•declines in our stock price;•reduction in industry demand for crude oil;•reduction in storage availability for crude oil;36Table of Contents•reduction in pipeline and processing industry demand and capacity for natural gas;•reduction in the ability of our vendors, suppliers, and customers to continue operations due to the prevailing adverse market conditions; and•asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment.Our production is not fully hedged, and we are exposed to fluctuations in the price of oil and will be affected by continuing and prolonged declines in theprice of oil and natural gas.Oil and natural gas prices are volatile. We hedge a portion of our oil and natural gas production to reduce our exposure to adverse fluctuations inthese prices. We have stated limitations as prescribed in our Current Credit Facility as to the percentage of our production that can be hedged. The limitationsrange from 85% to 100% of our projected production from our proved developed properties and 65% to 85% of our projected production from our totalproved properties, dependent on the duration of the hedge. Due to the Current Credit Facility's restrictions and/or management's decision to hedge less than100% of our projected production, some of our future production will be sold at market prices, exposing us to fluctuations in the price of crude oil andnatural gas. Currently, we have approximately 59% of our guided 2019 production hedged. To the extent that the price of oil and natural gas decline belowcurrent levels, our results of operations and financial condition would be materially adversely impacted. See the Derivative Activity section in Part I, Item I ofthis 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 any indebtedness could be adversely affected.Oil, natural gas, and NGL prices have significantly declined since mid-2014 and have not regained previous highs. This depressed priceenvironment resulted in a reduction in our available liquidity until we negotiated a new reserve based credit facility in late 2018. However, we havesubstantial capital needs, including in connection with the continued development of our oil and gas assets. We may not have the ability to generatesufficient cash flows from operations and our credit facility's borrowing base may be reduced in the future. Therefore, we may have insufficient liquidity tomeet our anticipated working capital, debt service, and other liquidity needs.Terrorist attacks could have a material adverse effect on our business, financial condition, or results of operations.Terrorist attacks may significantly affect the energy industry, including our operations and those of our current and potential customers, as well asgeneral economic conditions, consumer confidence and spending, and market liquidity. Strategic targets, such as energy-related assets, may be at greater riskof future attacks than other targets in the United States. Our insurance may not protect against such occurrences. Consequently, it is possible that any of theseoccurrences, or a combination of them, could have a material adverse effect on our business, financial condition, and results of operations.We recently emerged from bankruptcy, which could adversely affect our business and relationships.It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect ourbusiness and relationships with customers, employees, and suppliers. Due to uncertainties, many risks exist, including the following:•key suppliers could terminate their relationship or require financial assurances or enhanced performance;•the ability to renew existing contracts and compete for new business may be adversely affected;•the ability to attract, motivate, and/or retain key executives and employees may be adversely affected;•employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and•competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition, and reputation. There canbe no assurance that having been subject to bankruptcy protection will not adversely affect our operations in the future.37Table of ContentsOur actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of theimplementation of our reorganization plan and the transactions contemplated thereby and the adoption of fresh-start accounting.In connection with the disclosure statement we filed with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”),and the hearing to consider confirmation of our Third Amended Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code, datedApril 6, 2017 (the “reorganization plan”), we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of thereorganization plan and our ability to continue operations upon emergence from bankruptcy. Those projections were prepared solely for the purpose of thebankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they wereprepared, the projections reflected numerous assumptions concerning anticipated future performance and with respect to prevailing and anticipated marketand economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial andnumerous uncertainties and to a wide variety of significant business, economic, and competitive risks, and the assumptions underlying the projections and/orvaluation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As aresult, investors should not rely on these projections.In addition, upon emergence from bankruptcy, we adopted fresh-start accounting, as a consequence of which our assets and liabilities were adjusted tofair value and our accumulated deficit was restated to zero. Accordingly, our future financial conditions and results of operations following our emergence arenot comparable to the financial condition or results of operations reflected in our historical financial statements. The lack of comparable historical financialinformation may discourage investors from purchasing our common stock.The Current Credit Facility has restrictive covenants that could limit our growth and our ability to finance our operations, fund capital needs, respond tochanging conditions, and engage in other business activities that may be in our best interests.The Current Credit Facility contains restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Ourability to borrow under the Current Credit Facility is subject to compliance with certain financial covenants, including the maintenance of certain financialratios, including a minimum current ratio and a maximum leverage ratio. In addition, the Current Credit Facility contains covenants that, among other things,limit our ability to:•incur or guarantee additional indebtedness;•issue preferred stock;•sell or transfer assets;•pay dividends on, redeem, or repurchase capital stock;•repurchase or redeem subordinated debt;•make certain acquisitions and investments;•create or incur liens;•engage in transactions with affiliates;•enter into agreements that restrict distributions or other payments from restricted subsidiaries to us;•consolidate, merge, or transfer all or substantially all of our assets; and•engage in certain other 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 of ourindebtedness. We would not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of ouroutstanding indebtedness. As of the date of this Annual Report on Form 10-K, we are in compliance with all financial and non-financial covenants.We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictivecovenants contained in the Current Credit Facility. Our ability to comply with the financial ratios and38Table of Contentsfinancial condition tests under the Current 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.Borrowings under the Current Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.Beginning on May 1, 2019, the borrowing base under the Current Credit Facility will be redetermined at least semiannually and up to twoadditional times per year between scheduled determinations upon request of us or lenders holding more than 50% of the aggregate commitments.Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility toreduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of our bank debt to the extent ouroutstanding borrowings at such time exceed the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could resultin a default under the terms of the facility and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing, or sellsignificant assets, all of which could have a material adverse effect on our business and financial results.Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financialcondition, or 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, lease, 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 and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Anysignificant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves below.Our cost of drilling, completing, and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks thatcan make a particular project uneconomical. Further, many factors, including, but not limited to, the following, may result in substantial losses, includingpersonal injury or loss of life, penalties, damage or destruction of property and equipment, and curtailments, delays, or cancellations of our scheduleddrilling, completion, and infastructure 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 extreme cold temperatures, blizzards, ice storms, tornadoes, floods, and fires;•reductions in oil and natural gas prices;•delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays;•proximity to and capacity of transportation facilities;•title problems;•safety concerns; and•limitations in the market for oil and natural gas.Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to beinaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of ourreserves.39Table of ContentsThe process of estimating oil and natural gas reserves and the production possible from our oil and gas wells is complex. It requires interpretations ofavailable technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Anysignificant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in thisAnnual Report on Form 10-K. See Estimated Proved Reserves under Part I, Item 1 of this Annual Report on Form 10-K for information about our estimated oiland natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2018, 2017 and 2016.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 reserves information contained herein is reviewed by independentreserves engineers, estimates of oil and natural gas reserves are inherently imprecise, particularly as they relate to state-of-the-art technologies beingemployed such 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 recoverableoil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value ofreserves shown in this Annual Report on Form 10-K and potential impairment charges. In addition, we may adjust estimates of proved reserves to reflectproduction history, results of exploration and development, prevailing oil and natural gas prices, and other factors, many of which are beyond our control.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, 2018, 2017, and 2016, we based the estimated discounted futurenet revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months(after adjustment for location and quality differentials), without giving effect to derivative transactions. Actual future net revenues from our oil and naturalgas 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;•wellbore productivity realizations above or below type curve forecast models;•the supply and demand of oil and natural gas; and•changes in governmental regulations or taxation.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.As a result of the predominately sustained decrease in prices for oil, natural gas, and NGLs since the fourth quarter of 2014, we have taken write-downs ofthe carrying value of our properties and may be required to take further write-downs if oil and natural gas prices remain depressed or decline further or ifwe have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs, or deterioration in ourdrilling 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 not regained previous highs. Additionally, given the history of price volatility in the oil and natural gas40Table of Contentsmarkets, 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 and completion. Horizontaldevelopment operations can be more operationally challenging and costly relative to our historic vertical drilling operations.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 program. Risks associated with our horizontal drilling program include, but are not limited to, the following, any of whichcould materially and adversely impact the success of our horizontal drilling program and, thus, our cash flows and results of operations:•successfully drilling and maintaining the wellbore to planned total depth;•landing our wellbore in the desired hydrocarbon reservoir;•effectively controlling the level of pressure flowing from particular wells;•staying in the desired hydrocarbon reservoir while drilling horizontally through the formation;•running our casing through the entire length of the wellbore;•running tools and other equipment consistently through the horizontal wellbore;•fracture stimulating the planned number of stages;•preventing downhole communications with other wells;•successfully cleaning out the wellbore after completion of the final fracture stimulation stage; and•designing and maintaining efficient forms of artificial lift throughout the life of the well.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 and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance withapplicable environmental 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 (including during times of droughts), or to dispose of or recycle the waterused in our operations, could adversely impact our operations. The imposition of new environmental initiatives and regulations could include restrictions onour ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids, andother wastes associated with the exploration, development, or production of oil and natural gas. Compliance with environmental regulations and permitrequirements governing the withdrawal, storage, and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase ouroperating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, and all of which could have anadverse effect on our operations and financial condition.The unavailability or high cost of additional drilling rigs, pressure pumping fleets, equipment, supplies, personnel, and oilfield services could adverselyaffect our ability to execute our exploration and development plans within our budget and on a timely basis.Shortages or the high cost of drilling rigs, pressure pumping fleets, equipment, supplies, personnel, or oilfield services could delay or adverselyaffect our development and exploration operations or cause us to incur significant expenditures that41Table of Contentsare not provided for in our capital budget, which could have a material adverse effect on our business, financial condition, or results of operations and maylead 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. At this time, we intend to financefuture capital expenditures primarily through cash flows provided by operating activities and borrowings under the Current Credit Facility. Declines incommodity prices coupled with our financing needs may require us to alter or increase our capitalization substantially through the issuance of additionalequity securities or debt securities or the strategic sale of assets. The issuance of additional debt may require that a portion of our cash flows provided byoperating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital,capital expenditures, and acquisitions. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), ourborrowing base under the Current Credit Facility would be reduced. The issuance of additional equity securities could have a dilutive effect on the value ofour 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 new and 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 the Current Credit Facility decreases or if our revenues 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 favorable terms, or at all. If cash generated by operations or cash available underthe Current Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of ouroperations relating to development of our drilling locations, which in turn could lead to a possible expiration of our undeveloped leases and a decline in ouroil and natural gas reserves, and an adverse effect on our business, financial condition, and results of operations.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 one core area may increase our risk of production loss.Our assets and operations are currently concentrated in one core area: the Wattenberg Field in Colorado. The core area currently provides 100% ofour current sales volumes and development projects.During the first quarter of 2018, we established a plan to sell all of our assets within our Mid-Continent region and North Park Basin, at which pointthey were deemed held for sale. We sold our North Park Basin assets on March 9, 2018. On August 6, 2018, we divested of our assets within the Dorcheat andMacedonia Fields in southern Arkansas.Because our operations are not as diversified geographically as some of our competitors, the success of our operations and our profitability may bedisproportionately exposed to the effect of any regional events, including: fluctuations in prices of crude oil, natural gas, and NGLs produced from wells inthe area, accidents or natural disasters, restrictive governmental42Table of Contentsregulations, curtailment of production, interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resultingdelays or interruptions of production from existing or planned new wells. Similarly, the concentration of our assets within a single producing formationexposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to the formation. Inaddition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, we are subject toincreasing competition for drilling rigs, pressure pumping fleets, oilfield equipment, services, supplies, and qualified personnel, which may lead to periodicshortages or delays. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capitalcosts.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 our core operating area could have a significant negative impact on our cash flows and profitability.As a Colorado-only oil and gas operator, we face disproportionate risk associated with the long-term trend toward increased activism against oil and gasexploration and development activities in Colorado.Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often thetarget 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 state government lands and delay or cancel certain projects such asthe development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling in theUnited States, even in jurisdictions that are among the most stringent in their regulation of the industry. Further 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;•mandatory and lengthy distances between drilling locations and buildings and/or bodies of water;•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.Specifically in Colorado, anti-development activity has both increased and become more effective in recent years. For example, anti-developmentactivists succeeded in adding a measure to the November 6, 2018 ballot in Colorado, which sought to require a minimum 2,500 foot setback from occupiedstructures and vulnerable areas for all new oil and gas development on non-federal land. This initiative was rejected by voters, but if it had been successful, itmay have resulted in dramatically reducing the area of future oil and gas development in Colorado. More recently, the same anti-development activists fileda lawsuit challenging the constitutionality of the statutory pooling provision of the Colorado Oil and Gas Act. If successful, the lawsuit could result insignificantly reducing the area of oil and gas development in the state. Additionally, Colorado’s newly elected governor, Jared Polis, has vowed to increaselocal governmental control over oil and gas development in the state, which could serve to increase anti-development initiatives in certain communities.Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development inColorado or outright banning oil and gas development in Colorado.43Table of ContentsWe 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.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 oil production and, in the Wattenberg Field, gathering andprocessing systems to deliver our natural gas production. These systems have limited capacity and at times have experienced service disruptions.Curtailments, disruptions, or lack of availability in these systems interfere with our ability to market the oil and natural gas we produce, and couldmaterially and adversely affect our cash 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 ofoil and 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. Anysignificant curtailment in gathering, processing, or pipeline system capacity, significant delay in the construction of necessary facilities, or lack ofavailability of transport, would interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect our cash flowand results of operations, and the expected results of our development program.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 58% of our total proved reserves were classified as proved undeveloped as of December 31, 2018. 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, financialcondition, and 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.44Table of ContentsWe 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 soil, surface water, groundwater, and shoreline contamination;•releases of natural gas and hazardous air pollutants or other substances into the atmosphere (including releases at our oil and gas 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 down-hole tools or casing collapse;•cratering (catastrophic failure);•downhole communication leading to migration of contaminants;•personal injuries and death; and•natural disasters.Any 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 and facility locations. In addition, our operations in Colorado are susceptible to damage from natural disasters such asflooding, wildfires, tornadoes, and other natural phenomena and weather conditions, including extreme temperatures, 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 integral to our operations, they are covered by our insurance against claims made for bodily injury,property damage, and clean-up costs stemming from a sudden and accidental pollution event. However,45Table of Contentswe may not have coverage if the operator is unaware of the pollution event and unable to report the “occurrence” to the insurance company within therequired time frame. We also do not 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 we draw from available data from other wells, more fully explored locations or producingfields will be applicable to our drilling locations. Further, initial production 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, and operating 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 development. 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 well performance. 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 categories any proved undeveloped reserves that are not developed within this five-year time frame. Theselimitations may 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 often stipulate that the lease will terminate if not held by production, rentals, or some form of an extensionpayment to extend the term of the lease. As of the filing date of this report, approximately 10,739 net acres of our properties were not held by production. Forthese properties, if production in paying quantities is not established on units containing these leases during the next year, then approximately 432 net acreswill expire in 2019, approximately 2,959 net acres will expire in 2020, and approximately 1,429 net acres will expire in 2021 and thereafter. While someexpiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Itis possible 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 or cause us to lose the leases entirely. 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. As46Table of Contentsis industry standard, we may rely upon a land professional’s careful examination of public records prior to purchasing or leasing a mineral interest. Once amineral or leasehold interest has been acquired, we typically defer the expense of obtaining further title verification by a practicing title attorney untilapproval to drill a well that includes the acquired mineral interest is required. We perform the necessary curative work to correct deficiencies in themarketability of the title, and we have compliance and control measures to ensure any associated business risk is approved by the appropriate Companyauthority. In cases involving more serious title deficiencies, all or part of a mineral or leasehold interest may be determined to be invalid or unleased, and, asa result, the target area may be deemed to be undrillable until owners can be contacted and curative measures performed to adequately perfect title. In othercases, title deficiencies may result in our failure to have paid royalty owners correctly. Certain title deficiencies may also result in litigation to quiet the titleand effectively agree or render a decision upon title ownership.We are subject to health, safety, and environmental laws and regulations that may expose us to significant costs and liabilities.We are subject to stringent and complex federal, state, and local laws and regulations governing health and safety aspects of our operations, thedischarge of materials into the environment, and the protection of the environment. These laws and regulations may impose on our operations numerousrequirements, including the obligation to obtain a permit before conducting drilling or underground injection activities; restrictions on the types, quantities,and concentration of materials that may be released into the environment; limitations or prohibitions of drilling or completion activities that impactthreatened or endangered species or that occur on certain lands lying within wilderness, wetlands, and other sensitive or protected areas; the application ofspecific health and safety criteria to protect workers; and the responsibility for cleaning up pollution resulting from operations. Numerous governmentalauthorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued underthem, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil,and criminal penalties; the imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing some or all of ouroperations; delays in granting permits; or even the cancellation of leases.There is an inherent risk of incurring significant environmental costs and liabilities in our operations, some of which may be material, due to ourhandling of petroleum hydrocarbons and wastes, our emissions into air and water, the underground injection or other disposal of our wastes, the use anddisposition of hydraulic fracturing fluids, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations,we may be liable for the full cost of removing or remediating contamination, regardless of whether we were at fault, and even when multiple partiescontributed to the release and the contaminants were released in compliance with all applicable laws then in effect. In addition, accidental spills or releaseson or off our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations.Aside from government agencies, the owners of properties where our wells are located, the owners or operators of facilities where our petroleum hydrocarbonsor wastes are taken for reclamation or disposal or otherwise come to be located, and other private parties may be able to sue us to enforce compliance withenvironmental laws and regulations, collect penalties for violations, or obtain damages for any related personal injury, or damage and property damage, andcertain trustees may seek natural resource damages. Some sites we operate are located near current or former third-party oil and natural gas operations orfacilities, and there is a risk that historic contamination has migrated from those sites to ours. Changes in environmental laws and regulations occurfrequently, and any changes that result in more stringent or costly requirements could require us to make significant expenditures to attain and maintaincompliance or may otherwise have a material adverse effect on our own results of operations, competitive position, or financial condition. We may not beable to recover some or any of these costs from insurance.Evolving 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.Some activists have attempted to link hydraulic fracturing to various environmental problems, including potential adverse effects to drinking watersupplies, migration of methane and other hydrocarbons into groundwater, increased seismic activity, and human health effects. The federal government hasperiodically studied the environmental risks associated with hydraulic fracturing and evaluated whether to adopt, and in some cases have adopted, additionalregulatory requirements.47Table of ContentsIn some instances certain state and local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Somecounties in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other localgovernments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. In addition, voters in Colorado haveproposed or advanced ballot initiatives restricting or banning oil and gas development in Colorado. Because a substantial portion of our operations andreserves are located in Colorado, the risks we face with respect to such ballot initiatives are greater than other companies with more geographically diverseoperations.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 operations, delay orprevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alterthe demand for and consumption of our products. We cannot assure you that any such outcome would not be material, and any such outcome could have amaterial 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 the demand for and consumption of our products (due to potential changes in bothcosts and weather patterns).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. Information in such reporting may form the basisfor further GHG regulation. Further, the EPA has continued with its comprehensive strategy for further reducing methane emissions from oil and gasoperations, with a final rule being issued in May 2016 as part of “Quad O” discussed above. The EPA’s GHG rules could adversely affect our operations andrestrict or delay our ability to obtain air permits for new or modified facilities.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 to comply with new regulatory or reporting requirements. If we areunable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it couldhave a material 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. Moreover, incentives to conserve energy or use alternativeenergy sources as a means of addressing climate change could reduce demand for the oil and natural gas we produce. In addition, parties concerned about thepotential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financialinstitutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities.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 andnatural gas industry. Many of our competitors possess and employ financial, technical, and personnel resources substantially greater than ours. Thosecompanies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for, andpurchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better ableto withstand unsuccessful drilling attempts and sustained periods of48Table of Contentsvolatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resultingfrom changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, other companies may be able to offerbetter compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future inacquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel, 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. Competition forexperienced senior management, technical, and other professional personnel remains strong.If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, theloss of experienced personnel could lead to a loss of technical expertise. We do not maintain, nor do we plan to obtain, any insurance against the loss of anyof these individuals.Our 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 have, and may inthe future enter into additional, derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We havenot in the past designated any of our derivative instruments as hedges for accounting purposes and have recorded all derivative instruments on our balancesheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly asa result of changes 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 may limit the benefit we would receive from increases in the prices for oil and natural gas andmay expose us to cash margin requirements. Further, our credit facility provides for certain limitations to the extent of our hedging, which may expose us tounfavorable fluctuations in the prices of oil and natural gas.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, which were $38.3 million atDecember 31, 2018, joint interest and other receivables of $47.6 million at December 31, 2018, and the sale of our oil, natural gas, and NGLs production of$31.8 million in receivables at December 31, 2018, 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, 2018, sales to NGL Crude Logistics, LLC comprised 66% of our total sales. Beginning in 2017 and continuing for seven years, we havecontracted to sell up to 16,000 barrels per day of our crude oil produced in the Wattenberg Field to NGL Crude Logistics, LLC.49Table of ContentsWe are exposed to credit risk in the event of default of our counterparty, principally with respect to hedging agreements, but also with respect toinsurance contracts and bank lending commitments. We do not require most of our customers to post collateral. The inability or failure of our significantcustomers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Deterioration in the credit markets mayimpact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness toenter into future transactions 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 our use of derivative as a result of the Dodd-Frank Act and regulations, our results of operations may be morevolatile 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 cases that may result in substantial liabilities.Like many oil and gas companies, we are from time to time involved in various legal and other cases, such as title, royalty or contractual disputes,regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. Such legal cases are inherentlyuncertain, and their results cannot be predicted. Regardless of the outcome, such cases could have an adverse impact on us because of legal costs, diversion ofmanagement and other personnel, and other factors. In addition, it is possible that a resolution of one or more such cases could result in liability, penalties, orsanctions, as well as judgments, consent decrees, or orders requiring a change in our business practices, which could materially and adversely affect ourbusiness, operating results, and financial condition. Accruals for such liability, penalties, or sanctions may be insufficient. Judgments and estimates todetermine accruals or range of losses related to legal and other cases could change from one period to the next, and such changes could be material.In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), alleging failure to obtain requiredpermits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the DenverMetropolitan and North Front Range of Colorado, among other things. The NOI letter appears to challenge long-established federal and state regulations andpolicies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Actand state counterpart statutes. Because the allegations made in the NOI letter are based on novel and unprecedented interpretations of complex federal andstate air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit or will lead to actual suitby WEG against the Company.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 (i) impose taxes on the oil and natural gas products we sell, and (ii) formany of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources orstate taxes associated with the extraction of hydrocarbons and additional increases may occur. In addition, there has been a significant amount of discussionby legislators 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.50Table of ContentsAny such changes in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respectto oil and gas exploration and 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 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,suppliers, and 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, weaknessesin the cyber security of our vendors, suppliers, and other business partners could facilitate an attack on our technologies, systems, and networks. In addition,certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing andthe controversy generated by its 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 securityrisks 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.Risks Relating to our Common StockWe do not intend to pay, and are subject to certain restrictions on our ability to pay dividends on our common stock, and consequently, our stockholders’likely only opportunity 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, our Current Credit Facility places certainrestrictions on our ability to pay dividends. Consequently, our stockholders’ only likely opportunity to achieve a return on their investment in us will be ifthe market price of our common stock appreciates, which may not occur, and the stockholders sell their shares at a profit. There is no guarantee that the priceof 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 2018 calendar year, the sales price of our common stock ranged from a low of $18.41 per share to a high of $40.38 per share. The trading price ofour common stock may be affected by a number of factors, including the volatility of oil, natural gas, and NGL prices, our operating results, changes in ourearnings estimates, additions or departures of key personnel, our financial condition and liquidity, drilling activities, legislative and regulatory changes,general conditions in the oil and natural gas exploration and development industry, general economic conditions, and general conditions in the securitiesmarkets. In particular, a significant or extended decline in oil, natural gas, and NGL prices could have a material adverse effect our sales price of our commonstock. Other risks described in this annual report could also materially and adversely affect our share price.51Table of ContentsAlthough 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.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:•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.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 of which we are aware, except as set forth below.During 2015, the Company voluntarily instigated an internal audit of its storage tank facilities located in the Wattenberg Field (the “Audit”). Thepurpose of the Audit was to determine compliance with applicable air quality regulations. Based on the results of the Audit, the Company self-reported inDecember 2015 and January 2016 several potential noncompliance issues to the Colorado Department of Public Health and Environment (“CDPHE”) underColorado’s Environmental Audit Privilege and Immunity Law (the “Environmental Audit Law”). Independently, in October 2015, CDPHE issued to theCompany a compliance advisory (the “Compliance Advisory”) for certain facilities that was closely related to the matters voluntarily disclosed as a result ofthe Audit.The Company vigorously defended against the CDPHE allegations of violation while also cooperating with CDPHE in its investigation and firmlyasserting the Company’s right to civil penalty immunity for voluntarily disclosed violations under the Environmental Audit Law. In February 2017,following further interaction between the CDPHE and the Company, the CDPHE proposed settlement terms under which the Company would be required topay an administrative penalty and perform certain mitigation projects and adopt certain procedures and processes addressing the monitoring, reporting, andreduction of emissions with respect to the Company’s storage tank facilities in the Wattenberg Field.Following negotiations with CDPHE, on October 3, 2017, the Company agreed to a Compliance Order on Consent (the “COC”) with the CDPHE. Aspart of the COC, the Company was required to pay a $0.2 million penalty. Additionally, as further required by the COC, the Company will perform certainmitigation projects and adopt certain procedures and processes52Table of Contentsaddressing the monitoring, reporting, and control of air emissions with respect to the Company’s storage tank facilities in the Wattenberg Field. The COCfurther sets forth compliance requirements and criteria for continued operations and contains provisions regarding record-keeping, modifications to the COC,circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownership interestscovered by the COC. In order to be in compliance, the Company incurred $1.2 million and $0.7 million in 2018 and 2017, respectively, and currentlyanticipates spending $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHEapproval.In September 2018, the Company reached a settlement in a case in which it was one of several plaintiffs seeking reimbursement of ad valorem taxesthat were assessed by a special metropolitan district in Colorado. Pursuant to that settlement, the Company received a gross reimbursement of ad valoremtaxes paid in the amount of $7.4 million. The Company estimates that $2.3 million of the reimbursement is due to the Company’s associated interest ownersas shown in the accounts payable and accrued expenses line item in the accompanying balance sheets. The remaining net settlement amount of $5.1 millionis presented as a reimbursement in the accompanying statements of operations within the severance and ad valorem taxes line item. This net settlementamount will be further reduced to reflect the reimbursement to the State of Colorado of a certain amount of severance tax credits received in connection withad valorem taxes historically paid by the Company.In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well productionfacilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one ofseven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and stateregulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere underthe Clean Air Act and state counterpart statutes. Because the allegations made in the NOI letters are based on novel and unprecedented interpretations ofcomplex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit orwill lead to actual suit by WEG against the Company and other operators, but the Company will vigorously defend against such allegations if sued, and willcoordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities.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”.Holders. As of February 25, 2019, there were approximately 34 registered holders of our common stock.Dividends. We have not paid any cash dividends since our inception. Covenants contained in our Current Credit Facility restrict the payment ofcash dividends on our common stock, as discussed further in Part II, Item 7, Liquidity and Capital Resources. We currently intend to retain all future earningsfor the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in theforeseeable future.Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the CurrentSuccessor Period.53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, 2018 - March 31, 201837 $27.89 — —April 1, 2018 - June 30, 201824,013 $30.56 — —July 1, 2018 - September 30, 20181,941 $32.67 — —October 1, 2018 - December 31, 2018— $— — —Total25,991 $30.71 — —_________________________(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 year ended December 31, 2018.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 May 1, 2017 (the first trading day of our common stock on the NYSE upon emergence) and each fiscal quarter thereafterthrough December 31, 2018. The graph assumes that $100 was invested on May 1, 2018 in each of the common stock of the Company, the S&P 500 Indexand the S&P O&G E&P Index and assumes reinvestment of any dividends. The stock price performance on the following graph is not necessarily indicativeof future stock price performance.54Table of Contents55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 for the period indicated (in thousands, except per share amounts). Predecessor Successor Year EndedDecember 31,2014 Year EndedDecember 31, 2015 Year EndedDecember 31, 2016 January 1, 2017through April 28,2017 April 29, 2017throughDecember 31,2017 Year EndedDecember 31,2018 Statement of Operations Data: Total operating net revenues (1) $558,633 $292,679 $195,295 $68,589 $123,535 $276,657Income (loss) from operations (1) (47,506) (907,444) (129,110) (1,600) 12,009 112,394Net income (loss) 20,283 (745,547) (198,950) 2,660 (5,020) 168,186Basic net income (loss) per common share $0.50 $(15.57) $(4.04) $0.05 $(0.25) $8.20Basic weighted-average common shares outstanding 40,139 47,874 49,268 49,559 20,427 20,507Diluted net income (loss) per common share $0.49 $(15.57) $(4.04) $0.05 $(0.25) $8.16Diluted weighted-average common shares outstanding 40,290 47,874 49,268 50,971 20,427 20,603Selected Cash Flow Data: Net cash (used for) provided by operating activities $339,958 $226,023 $14,563 $(19,884) $27,574 $116,598Net cash used in investing activities (837,232) (452,573) (67,460) (6,022) (82,641) (164,376)Net cash (used for) provided by financing activities $319,276 $245,307 $112,062 $15,406 $(2,398) $47,998Sales Volumes: Oil (MBbls)(2) 5,618.7 6,072.3 4,309.9 1,068.5 2,012.7 3,840.8Natural gas (MMcf)(3) 15,395.8 14,551.1 12,231.3 3,336.1 5,938.0 8,591.2Natural gas liquids (MBbls) 396.3 1,821.9 1,587.0 449.0 762.4 1,141.2Average Sales Price (before derivatives): Oil (MBbls)(2) $81.95 $40.95 $35.31 $48.29 $47.18 $59.38Natural gas (MMcf)(3) $5.11 $1.77 $1.76 $2.57 $2.29 $2.45Natural gas liquids (MBbls) $49.14 $9.49 $12.39 $17.52 $18.38 $22.46Average Sales Price (after derivatives): Oil (MBbls) $84.00 $62.07 $39.57 $48.29 $46.44 $54.77Natural gas (MMcf) $5.16 $1.95 $1.76 $2.57 $2.29 $2.39Natural gas liquids (MBbls) $49.14 $9.49 $12.39 $17.52 $18.38 $22.46Expense per BOE: Lease operating expense and gas plant and midstream operatingexpense $8.44 $7.40 $7.12 $8.04 $9.09 $7.11Severance and ad valorem taxes $5.88 $1.81 $1.93 $2.73 $2.55 $2.96Depreciation, depletion, and amortization $26.66 $23.73 $14.01 $13.54 $5.66 $6.53General and administrative $9.51 $6.81 $9.71 $7.28 $11.34 $6.62____________________(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.(2)Crude oil sales excludes $0.6 million, $0.2 million, $0.1 million, $0.5 million, and $0.2 million of oil transportation revenues from third parties, whichdo not have associated sales volumes, for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, 2016 Predecessor Period, and2015 Predecessor Period, respectively.(3)Natural gas sales excludes $1.3 million, $0.8 million, $0.4 million, $1.5 million, and $0.8 million of gas gathering revenues from third parties, which donot have associated sales volumes, for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, 2016 Predecessor Period, and 2015Predecessor Period, respectively.56Table of ContentsThe following table sets forth selected historical financial data of the Company as of the period indicated (in thousands). Predecessor Successor As of December 31, As ofDecember 31,2017 As of December31, 2018 2014 2015 2016 Balance Sheet Data: Cash and cash equivalents $2,584 $21,341 $80,565 $12,711 $12,916Property and equipment, net (excludes assets held for sale) 1,756,477 922,344 1,018,968 774,082 917,974Oil and gas properties held for sale, net of accumulated depreciation,depletion, and amortization — 214,922 — — —Total assets 1,990,086 1,259,641 1,134,478 830,371 1,061,534Debt Current Credit Facility — — — — 50,000 Prior Credit Facility 33,000 79,000 191,667 — — Senior Notes, net of unamortized premium and deferred financing costs 791,616 792,666 793,698 — — Total stockholders’ equity $740,071 $209,407 $19,061 $688,334 $863,913 Estimated Proved Reserves: Oil (MMBbls) 54.7 57.4 50.1 52.9 64.4Natural gas (Bcf) 188.6 144.2 138.0 157.7 165.0Natural gas liquids (MMBbls) 3.4 19.9 17.5 22.8 24.9Total proved reserves (MMBoe) 89.5 101.3 90.7 102.0 116.857Table of ContentsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Executive SummaryWe are an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil andassociated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets and operations are concentrated in the rural portions of theWattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codellformations in the DJ Basin. We intend to continue to develop our reserves and increase production through drilling and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives. The majority of ourrevenues are generated through the sale of oil, natural gas, and natural gas liquids production.Financial and Operating ResultsOur 2018 financial and operational results include:•Wattenberg Field lease operating expense decreased 18% on a per Boe basis for the year ended December 31, 2018 when compared to the sameperiod in 2017;•Net cash provided by operating activities was $116.6 million as of December 31, 2018;•Total liquidity of $312.9 million at December 31, 2018, consisting of our year-end cash balance plus funds available under the Current CreditFacility;•Wattenberg Field sales volumes increased by 24% for the year ended December 31, 2018 when compared to the same period in 2017;•Rapidly improving well performance yielded over 1,000 SRL equivalent economic drilling locations in Wattenberg Field;•Secured our $750.0 million Current Credit Facility with a borrowing base of $350.0 million on December 7, 2018;•Wattenberg Field proved reserves of 116.8 MMBoe as of December 31, 2018 increased 29% when compared to the same period in 2017;•PV-10 reserve value increased by 60% to $955.0 million as of December 31, 2018 when compared to the same period in 2017; •Divested of our Mid-Continent assets for net proceeds of $102.9 million and our North Park Basin assets for minimal net proceeds and full release ofall current and future obligations;•Invested $275.3 million to drill 78 gross wells and turning to sales 42 gross wells;•Continued to increase our takeaway capacity utilizing four gas processors via eleven interconnects.Chief Executive Officer AppointmentEffective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greager hasover 20 years of experience in the oil and gas industry, including exposure to both the operating and technical aspects of the industry. Mr. Greager, 47,previously served as a Vice President and General Manager at Encana Oil & Gas (USA) Inc. Mr. Greager joined Encana in 2006 and served in variousmanagement and executive positions, including as a member of the boards of directors of Encana Procurement Inc. and Encana Oil & Gas (USA) Inc. Mr.Greager previously served on the board of directors of Western Energy Alliance and the board of managers of Hunter Ridge Energy Services. Mr. Greagerreceived his Master’s Degree in Economics from the University of Oklahoma and his Bachelor’s Degree in Engineering from the Colorado School of Mines.58Table of ContentsChief Financial Officer AppointmentEffective November 13, 2018, the Company appointed Brant H. DeMuth as the new Executive Vice President and Chief Financial Officer andprincipal financial officer of the Company. Mr. DeMuth previously served as Vice President of Finance and Treasurer at SRC Energy Inc. from October 2014until November 2018. Prior to joining SRC Energy, Mr. DeMuth served as Interim Chief Financial Officer of DJ Resources, LLC from August 2013 toSeptember 2014 and as Executive Vice President of Strategy and Corporate Development of Gevo, Inc. from June 2011 to May 2013. Mr. DeMuth currentlyserves on the University of Northern Colorado’s Monfort College of Business Dean’s Leadership Council. Mr. DeMuth is a Chartered Financial Analyst andreceived his M.B.A. in Oil and Gas Finance from the University of Denver and his B.S. in Business Administration from Colorado State University.2019 Capital BudgetThe Company’s 2019 capital budget of $230.0 to $255.0 million assumes a continuous one-rig development pace. The drilling and completionportion of the budget is expected to be approximately $210.0 million to $220.0 million, which will support drilling 59 gross wells and turning to sales 45gross wells. Included in the drilling completion budget is $15.0 million for non-operated capital. Of the wells planned to be completed, 16 are XRL wells,five are MRL wells, and 24 are SRL wells. The remaining 2019 capital budget of $20.0 million to $35.0 million is to support infrastructure and leaseholdcosts. Actual capital expenditures could vary significantly based on, among other things, market conditions, commodity prices, drilling and completioncosts, well results, and changes in the borrowing base under our Current Credit Facility.Results of Operations The 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 Company conducted standard business operations throughout the bankruptcy proceedings and during the application of fresh-start accounting,resulting in specific financial statement line items following normal course of business trends. The trends associated with the non-impacted financialstatement line items are explained throughout the results of operations and include revenues, lease operating expense, gas plant and midstream operatingexpense, severance and ad valorem taxes, and exploration expense. The financial statement line items that were specifically impacted by the bankruptcyproceedings and application of fresh-start accounting are discussed within the confines of the presented periods and include depreciation, depletion, andamortization, general and administrative expense, interest expense, and reorganization items, net.References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequentto April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or priorto April 28, 2017. Throughout this Management's Discussion and Analysis, the Company refers to the 2017 annual period which is comprised of bothSuccessor and Predecessor periods. References to “Current Successor Period” relate to the year ended December 31, 2018. References to “2017 SuccessorPeriod” relate to the period of April 29, 2017 through December 31, 2018. References to the “2017 Predecessor Period” and “2016 Predecessor Period” relateto the periods of January 1, 2017 through April 28, 2017 and January 1, 2016 through December 31, 2016, respectively. For additional information about ourbankruptcy proceedings and emergence, please refer to Part II, Item 8, Note 15 - Chapter 11. For additional information about our application of fresh-startaccounting, please refer to Part II, Item 8, Note 16 - Fresh-Start Accounting.59Table of ContentsThe table below presents revenues, sales volumes, and average sales prices for the periods indicated (in thousands, except per Boe amounts): Successor Predecessor Year EndedDecember 31, 2018 April 29, 2017through December31, 2017 January 1, 2017through April 28,2017Operating Revenues: Crude oil sales(1)$228,075 $94,956 $51,593Natural gas sales(2) 21,022 13,605 8,584Natural gas liquids sales 25,627 14,012 7,867Product revenue$274,724 $122,573 $68,044 Sales Volumes: Crude oil (MBbls) 3,840.8 2,012.7 1,068.5Natural gas (MMcf) 8,591.2 5,938.0 3,336.1Natural gas liquids (MBbls) 1,141.2 762.4 449.0Crude oil equivalent (MBoe)(3) 6,413.8 3,764.8 2,073.5 Average Sales Prices (before derivatives): Crude oil (per Bbl)$59.38 $47.18 $48.29Natural gas (per Mcf)$2.45 $2.29 $2.57Natural gas liquids (per Bbl)$22.46 $18.38 $17.52Crude oil equivalent (per Boe)(3)$42.83 $32.56 $32.82 Average Sales Prices (after derivatives)(4): Crude oil (per Bbl)$54.77 $46.44 $48.29Natural gas (per Mcf)$2.39 $2.29 $2.57Natural gas liquids (per Bbl)$22.46 $18.38 $17.52Crude oil equivalent (per Boe)(3)$40.00 $32.17 $32.82_____________________________(1)Crude oil sales excludes $0.6 million, $0.2 million, and $0.1 million of oil transportation revenues from third parties, which do not have associated salesvolumes, for the Current Successor Period, 2017 Successor Period, and the 2017 Predecessor Period, respectively.(2)Natural gas sales excludes $1.3 million, $0.8 million, and $0.4 million of gas gathering revenues from third parties, which do not have associated salesvolumes, for the Current Successor Period, 2017 Successor Period, and the 2017 Predecessor Period, respectively.(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.(4)The derivatives economically hedge the price we receive for crude oil. For the Current Successor Period, the derivative cash settlement loss for oil andnatural gas was $17.7 million and $0.5 million, respectively, and the derivative cash settlement loss for oil was $1.5 million for the 2017 SuccessorPeriod. Please refer to Part II, Item 8, Note 13 - Derivatives for additional disclosures.Operating revenues increased by 44% to $274.7 million for the year ended December 31, 2018 compared to $190.6 million for the year endedDecember 31, 2017 largely due to a 31% increase in oil equivalent pricing and a 10% increase in sales volumes. The increased volumes are a direct result ofthe Company increasing the pace and efficiency of its Wattenberg development program during 2018. During the period from January 1, 2018 throughDecember 31, 2018, we turned to sales 34.4 net operated wells in the Rocky Mountain region. In addition to the overall increase of operational activity, therewas an increase of $9.7 million related to the adoption of ASC 606, which caused certain revenues to be presented on a gross basis compared to a historicalnet presentation. Please refer to Part II, Item 8, Note 2 - Revenue Recognition for additional disclosures.60Table of ContentsThe following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts): Successor Predecessor Year EndedDecember 31, 2018 April 29, 2017 throughDecember 31, 2017 January 1, 2017through April 28,2017Operating Expenses: Lease operating expense$34,825 $25,862 $13,128Gas plant and midstream operating expense 10,788 8,341 3,541Gathering, transportation, and processing 9,732 — —Severance and ad valorem taxes 18,999 9,590 5,671Exploration 291 3,745 3,699Depreciation, depletion and amortization 41,883 21,312 28,065Abandonment and impairment of unproved properties 5,271 — —Unused commitments 21 — 993General and administrative expense 42,453 42,676 15,092Operating expenses$164,263 $111,526 $70,189 Selected Costs ($ per Boe): Lease operating expense$5.43 $6.87 $6.33Gas plant and midstream operating expense 1.68 2.22 1.71Gathering, transportation, and processing 1.52 — —Severance and ad valorem taxes 2.96 2.55 2.73Exploration 0.05 0.99 1.78Depreciation, depletion and amortization 6.53 5.66 13.54Abandonment and impairment of unproved properties 0.82 — —Unused commitments — — 0.48General and administrative expense 6.62 11.34 7.28Operating expenses$25.61 $29.63 $33.85 Operating expenses, excluding impairments and abandonments and unusedcommitments$24.79 $29.63 $33.37 Lease operating expense. Our lease operating expense decreased $4.2 million or 11%, to $34.8 million for the year ended December 31, 2018 fromthe combined 2017 Successor and Predecessor Periods of $39.0 million, and decreased on an equivalent basis to $5.43 per Boe from $6.68 per Boe. Thedecrease is primarily due to the sale of our Mid-Continent assets on August 6, 2018. The Company has also taken measures to decrease its lease operatingexpense, in conjunction with an increase in production, which caused the per Boe metric to further decrease. During 2018, the Company experienceddecreases in its well servicing and maintenance costs of $3.2 million and $0.7 million, respectively.Gas plant and midstream operating expense. Our gas plant and midstream operating expense decreased $1.1 million to $10.8 million for the yearended December 31, 2018 from $11.9 million for the combined 2017 Successor and Predecessor Periods, and decreased on an equivalent basis to $1.68 perBoe from $2.04 per Boe. The decrease is primarily due to the sale of our Mid-Continent assets on August 6, 2018.Gathering, transportation, and processing. As noted in the operating revenues section above, the increase in gathering, transportation, andprocessing expense during the year ended December 31, 2018 to $9.7 million is related to the Company's adoption of ASC 606 during 2018, which causedcertain revenues to be shown gross, with the related expenses recorded in this line item. Please refer to Part II, Item 8, Note 2 - Revenue Recognition foradditional disclosures.61Table of ContentsSeverance and ad valorem taxes. Our severance and ad valorem taxes increased by 24% from $15.3 million for the combined 2017 Successor andPredecessor Periods to $19.0 million for the year ended December 31, 2018. Severance and ad valorem taxes primarily correlate to revenue. Revenuesincreased by 44% for the year ended December 31, 2018 when compared to the same period in 2017. The Company received a net ad valorem tax settlementof $5.1 million during the fourth quarter of 2018, which reduced this line item. Please refer to Part II, Item 8, Note 8 - Commitments and Contingencies foradditional discussion on the settlement.Exploration. Our exploration expense decreased $7.1 million to $0.3 million for the year ended December 31, 2018 from $7.4 million for thecombined 2017 Successor and Predecessor Periods. During the year ended December 31, 2018, we incurred $0.3 million in delay rentals. During thecombined 2017 Successor and Predecessor Periods, we paid $3.8 million in delay rentals and incurred $2.9 million on abandoned well projects and $0.7million in geological and geophysical expenses.Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense per Boe was $6.53, $5.66, and $13.54 for theyear ended December 31, 2018, 2017 Successor Period, and 2017 Predecessor Period, respectively. Together, the year ended December 31, 2018 and the 2017Successor Period (collectively, the “Successor Periods”) reflect the $310.6 million fair value downward adjustment to the depletable asset base uponadoption of fresh-start accounting. The increase in depreciation, depletion, and amortization during the Current Successor Period when compared to the 2017Successor Period primarily correlates to an increase in capital expenditures.Abandonment and impairment of unproved properties. During the year ended December 31, 2018, abandonment and impairment of unprovedproperties of $5.3 million was due to the standard annual amortization of our emergence leases that were not held by production at the time of our emergence.There were no abandonment and impairment of unproved properties during the 2017 Successor and Predecessor Periods. Please refer to Part II, Item 8, Note 1- Summary of Significant Accounting Policies for additional discussion on our impairment policy and practices.Unused commitments. There were immaterial amounts of unused commitments during the year ended December 31, 2018. No amounts of unusedcommitments were incurred during the 2017 Successor Period. During the 2017 Predecessor Period, we incurred $1.0 million in unused commitment fees on awater supply contract in the Wattenberg Field.General and administrative expense. Our general and administrative expense per Boe was $6.62, $11.34, and $7.28 for the year ended December 31,2018, 2017 Successor Period, and 2017 Predecessor Period, respectively. The 2017 Successor Period reflects a one-time cash and non-cash $9.6 million, or$2.55 per Boe, severance charge primarily related to the Company's former Chief Executive Officer's separation from the Company. The remaining decreasein expense for the year ended December 31, 2018 when compared to the combined 2017 Successor and Predecessor Periods was due to decreases inconsultant restructuring fees of $5.4 million and wages and benefits of $2.7 million, partially offset by increases in employee bonuses of $1.6 million andprofessional services of $0.8 million.Derivative gain (loss). Our derivative gain for the year ended December 31, 2018 was $30.3 million as compared to a loss of $15.4 million for the2017 Successor Period. We had no derivative contracts during the 2017 Predecessor Period. During the year ended December 31, 2018, we entered intoseveral oil and gas costless collars, puts, and swap contracts. Our derivative gain is primarily due to fair market value adjustments caused by market pricesbeing lower than our contracted hedge prices. Please refer to Part II, Item 8, Note 13 - Derivatives for additional discussion.Interest expense. Our interest expense for the year ended December 31, 2018, the 2017 Successor Period, and the 2017 Predecessor Period was $2.6million, $0.8 million, and $5.7 million, respectively. During the year ended December 31, 2018, the Company incurred $1.4 million in interest expenseassociated with its Current and Prior Credit Facilities, commitment fees of $0.9 million, and miscellaneous fees of $0.3 million related to its Current and PriorCredit Facilities. The Company incurred $0.7 million in commitment fees on the available borrowing base under the Prior Credit Facility during the 2017Successor Period. Interest expense on the Company's Senior Notes was $1.0 million for the 2017 Predecessor Period, with the remaining interest expenserelating to the predecessor credit facility. The Company had no outstanding debt during the 2017 Successor Period. Average debt outstanding for the yearended December 31, 2018 and the 2017 Predecessor Period was $26.8 million and $991.7 million, respectively.62Table of ContentsYear Ended December 31, 2017 Compared to Year Ended December 31, 2016The table below presents revenues, sales volumes, and average sales prices for the periods indicated (in thousands, except per Boe amounts): Successor Predecessor April 29, 2017through December31, 2017 January 1, 2017through April 28,2017 Year EndedDecember 31, 2016Operating Revenues: Crude oil sales(1)$94,956 $51,593 $152,205Natural gas sales(2) 13,605 8,584 21,470Natural gas liquids sales 14,012 7,867 19,660Product revenue$122,573 $68,044 $193,335 Sales Volumes: Crude oil (MBbls) 2,012.7 1,068.5 4,309.9Natural gas (MMcf) 5,938.0 3,336.1 12,231.3Natural gas liquids (MBbls) 762.4 449.0 1,587.0Crude oil equivalent (MBoe)(3) 3,764.8 2,073.5 7,935.5 Average Sales Prices (before derivatives): Crude oil (per Bbl)$47.18 $48.29 $35.31Natural gas (per Mcf)$2.29 $2.57 $1.76Natural gas liquids (per Bbl)$18.38 $17.52 $12.39Crude oil equivalent (per Boe)(3)$32.56 $32.82 $24.36 Average Sales Prices (after derivatives)(4): Crude oil (per Bbl)$46.44 $48.29 $39.57Natural gas (per Mcf)$2.29 $2.57 $1.76Natural gas liquids (per Bbl)$18.38 $17.52 $12.39Crude oil equivalent (per Boe)(3)$32.17 $32.82 $26.67________________________________(1)Crude oil sales excludes $0.2 million, $0.1 million, and $0.5 million of oil transportation revenues from third parties, which do not have associated salesvolumes, for the 2017 Successor Period, 2017 Predecessor Period, and the 2016 Predecessor Period, respectively.(2)Natural gas sales excludes $0.8 million, $0.4 million, and $1.5 million of gas gathering revenues from third parties, which do not have associated salesvolumes, for the 2017 Successor Period, 2017 Predecessor Period, and the 2016 Predecessor Period, respectively.(3)Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.(4)The derivatives economically hedge the price we receive for crude oil. For the 2017 Successor Period, the derivative cash settlement loss was $1.5million and the derivative cash settlement gain was $18.3 million for the 2016 Predecessor Period. Please refer to Part II, Item 8, Note 13 - Derivatives foradditional disclosures.Operating revenues decreased by 1% to $190.6 million for the year ended December 31, 2017 compared to $193.3 million for the yearended December 31, 2016, largely due to a 26% decrease in sales volumes offset by a 34% increase in oil equivalent pricing. The decreased volumes were adirect result of the Company suspending drilling and completion activities through the majority of 2016 and the first half of 2017. During the periodfrom December 31, 2016 through December 31, 2017, we turned to sales 10.0 net operated wells in the Rocky Mountain region and no wells in the Mid-Continent region. 63Table of ContentsThe following table summarizes our operating expenses for the periods indicated (in thousands, except per Boe amounts): Successor Predecessor April 29, 2017through December31, 2017 January 1, 2017through April 28,2017 Year EndedDecember 31, 2016Operating Expenses: Lease operating expense$25,862 $13,128 $43,671Gas plant and midstream operating expense 8,341 3,541 12,826Severance and ad valorem taxes 9,590 5,671 15,304Exploration 3,745 3,699 946Depreciation, depletion and amortization 21,312 28,065 111,215Impairment of oil and gas properties — — 10,000Abandonment and impairment of unproved properties — — 24,692Unused commitments — 993 7,686Contract settlement expense — — 21,000General and administrative expense 42,676 15,092 77,065Operating expenses$111,526 $70,189 $324,405 Selected Costs ($ per Boe): Lease operating expense$6.87 $6.33 $5.50Gas plant and midstream operating expense 2.22 1.71 1.62Severance and ad valorem taxes 2.55 2.73 1.93Exploration 0.99 1.78 0.12Depreciation, depletion and amortization 5.66 13.54 14.01Impairment of oil and gas properties — — 1.26Abandonment and impairment of unproved properties — — 3.11Unused commitments — 0.48 0.97Contract settlement expense — — 2.65General and administrative expense 11.34 7.28 9.71Operating expenses$29.63 $33.85 $40.88 Operating expenses, excluding impairments and abandonments, unusedcommitments and contract settlement expense$29.63 $33.37 32.89Lease operating expense. Our lease operating expense decreased $4.7 million or 11%, to $39.0 million for the 2017 Successor and 2017 PredecessorPeriods from $43.7 million for the year ended December 31, 2016, but increased on an equivalent basis from $5.50 per Boe to $6.68 per Boe due to reducedproduction. The Company eliminated significant amounts of compression and labor costs resulting in a decrease in total compression costs of $4.1 millionfor the 2017 Successor and Predecessor Period when compared to the same period in 2016.Gas plant and midstream operating expense. Our gas plant and midstream operating expense decreased $0.9 million to $11.9 million for the 2017Successor and 2017 Predecessor Period from $12.8 million for the 2016 Predecessor Period, but increased on an equivalent basis from $1.62 per Boeto $2.04 per Boe due to reduced production. Gas plant and midstream operating expense on an aggregate basis was commensurate between the comparableperiods. Severance and ad valorem taxes. Our severance and ad valorem taxes remained constant between the 2017 Successor and 2017 Period and the 2016Predecessor Period. Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 1% for the 2017 Successor and 2017 PredecessorPeriod when compared to the same period in 2016.64Table of ContentsExploration. Our exploration expense increased $6.5 million to $7.4 million for the 2017 Successor and 2017 Predecessor Period from $0.9million for the comparable period in 2016. During the 2017 Successor and 2017 Predecessor Period we paid $3.8 million in delay rentals and incurred $2.9million on abandoned well projects and $0.7 million in geological and geophysical expenses. During the 2016 Predecessor Period, we incurred $0.9 millionon abandoned well projects. Depreciation, depletion, and amortization. Our depreciation, depletion, and amortization expense per Boe was $5.66, $13.54, and $14.01 for the2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively. The 2017 Successor Period reflects the $310.6 million fair valuedownward adjustment to the depletable asset base upon adoption of fresh-start accounting.Impairment of oil and gas properties. There were no impairment of oil and gas properties during the 2017 Successor and 2017 Predecessor Periods.During the 2016 Predecessor Period, we incurred a $10.0 million impairment charge on our Mid-Continent assets based on the most current bid for the assetsreceived during the first quarter of 2016, when they were held for sale. Please refer to Note 1 - Summary of Significant Accounting Policies in Part II, Item 8 ofthis Annual Report on Form 10-K for additional discussion on our impairment policy and practice.Abandonment and impairment of unproved properties. There were no abandonment and impairment of unproved properties during the 2017Successor and 2017 Predecessor Periods. During the 2016 Predecessor Period, we incurred an abandonment and impairment of unproved properties chargeof $24.7 million due to non-core leases expiring within the Wattenberg Field. Unused commitments. There were no unused commitments during the 2017 Successor Period. During the 2017 Predecessor Period, we incurred $1.0million in unused commitment fees on a water supply contract in the Wattenberg Field. During the 2016 Predecessor Period, we incurred unused commitmentfees of $7.7 million, made up of $4.3 million water commitment deficiency payments and $3.4 million purchase and transportation deficiency payments.Please refer to Note 8 - Commitments and Contingencies in Part II, Item 8 of this Annual Report on Form 10-K for additional discussion.Contract settlement expense. There were no contract settlement expenses during the 2017 Successor and 2017 Predecessor Periods. During the 2016Predecessor Period, we incurred a $21.0 million loss to settle our crude oil purchase agreement with Silo Energy, LLC as part of our bankruptcy process.Please see Note 8 - Commitments and Contingencies in Part II, Item 8 of this Annual Report on Form 10-K for additional discussion. General and administrative expense. Our general and administrative expense per Boe was $11.34, $7.28 and $9.71 for the 2017 Successor Period,2017 Predecessor Period, and 2016 Predecessor Period, respectively. The 2017 Successor Period reflects a one-time cash and non-cash $9.6 million or $2.55per Boe severance charge primarily related to the Company's former Chief Executive Officer's separation from the Company. The 2016 Predecessor Periodincludes $13.3 million, or $1.68 per Boe, more in advisor fees than the comparable period in 2017. Excluding those two items, the per Boe metrics werecommensurate between the periods presented.Derivative gain (loss). Our derivative loss for the 2017 Successor Period was $15.4 million. We had no derivative contracts during the 2017Predecessor Period. During the 2017 Successor Period, we entered into several oil and gas costless collar and swap contracts. Our derivative loss was mainlydue to fair market value adjustments caused by market prices being higher than our contracted hedge prices. Our derivative loss for the 2016 PredecessorPeriod was $11.2 million. Due to the Company being in default on the predecessor credit facility, all of these derivative contracts in the 2016 PredecessorPeriod were terminated during the fourth quarter of 2016. Please see 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 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period was $0.8 million, $5.7million, and $62.1 million, respectively. Upon filing its petition for Chapter 11, the Company ceased accruing interest expense on its Senior Notes. TheCompany incurred $0.7 million in commitment fees on the available borrowing base under the successor credit facility during the 2017 Successor Period.Interest expense on the Senior Notes was $1.0 million and $52.3 million for the 2017 Predecessor Period and 2016 Predecessor Period, respectively, with theremaining interest expense relating to the predecessor credit facility. The Company had no outstanding debt during the 2017 Successor Period. Average debtoutstanding for the 2017 Predecessor Period and 2016 Predecessor Period was $991.7 million and $1.0 billion, respectively.65Table of ContentsLiquidity and Capital ResourcesThe Company's anticipated sources of liquidity include cash from operating activities, borrowings under the credit facility, proceeds from sales ofassets, and potential proceeds from equity and/or debt capital markets. Our cash flows from operating activities are subject to significant volatility due tochanges in commodity prices, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control,including global and regional product supply and demand, weather, product distribution, refining and processing capacity, regulatory constraints, and othersupply chain dynamics, among other factors. To mitigate some of the pricing risk, we have approximately 54% and 59% of our average 2019 guidedproduction hedged as of December 31, 2018 and as of the filing date of this report, respectively.As of December 31, 2018, our liquidity was $312.9 million, consisting of cash on hand of $12.9 million and $300.0 million of available borrowingcapacity on our Current Credit Facility. As of the date of filing, we had $65.0 million outstanding on our credit facility.The following table summarizes our cash flows and other financial measures for the periods indicated (in thousands). Successor Predecessor Year EndedDecember 31,2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April 28,2017 Year EndedDecember 31,2016 Net cash (used in) provided by operating activities$116,598 $27,574 $(19,884) $14,563Net cash used in investing activities(164,376) (82,641) (6,022) (67,460)Net cash (used in) provided by financing activities47,998 (2,398) 15,406 112,062Cash and cash equivalents, and restricted cash13,002 12,782 70,247 80,747Acquisition of oil and gas properties2,892 5,383 445 98Exploration and development of oil and gas properties264,231 76,384 5,123 52,344 Cash flows (used in) provided by operating activitiesThe Current Successor and 2017 Successor Periods include cash receipts and disbursements attributable to our normal operating cycle. The 2017and 2016 Predecessor Period contained reorganization costs along with our normal operating receipts and disbursements. See Results of Operations above formore 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. The Company spent $267.1 million,$81.8 million, $5.6 million, and $52.4 million for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 PredecessorPeriod, respectively. The fluctuation in cash flows in investing activities is a direct result of the Company's current strategic emphasis on growing operationalcapability as well as its entrance and emergence from bankruptcy.Cash flows (used in) provided by financing activitiesNet cash provided by financing activities for the Current Successor Period primarily consisted of net draws of $50.0 million on our Current CreditFacility. Net cash used by financing activities for the 2017 Successor Period consisted of employee tax withholdings in exchange for the return of commonstock (in conjunction with the vesting of equity awards). Net cash provided by financing activities for the 2017 Predecessor Period consisted of proceedsfrom the rights offering of $207.5 million net of the $191.7 million repayment to the predecessor credit facility. Net cash provided by financing activities forthe year ended December 31, 2016 consisted primarily of net proceeds from the predecessor credit facility of $112.7 million.Credit facilityCurrent Credit FacilityOn December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as theadministrative agent, and a syndicate of financial institutions as lenders (the “Current Credit66Table of ContentsFacility”). The Current Credit Facility has an aggregate original commitment amount of $750.0 million and matures on December 7, 2023. The initial borrowing base in respect of the Current Credit Facility is $350.0 million. The first borrowing base redetermination will occur on May 1,2019 with subsequent semi-annual redeterminations thereafter. Borrowings under the Current Credit Facility will bear interest at a per annum rate equal to, at the option of the Company, either (i) a LondonInterBank Offered Rate (“LIBOR”), subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Current Credit Facility (the“Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank,N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interestpublished by the Federal Reserve Bank of New York as the overnight bank funding rate and (d) a one month LIBOR, subject to a 0% LIBOR floor plus amargin of 0.75% to 1.75%, based on the utilization of the Current Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at theEurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, andinterest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. The Current Credit Facility is guaranteed by all wholly owned domestic subsidiaries of the Company (each, a “Guarantor” and, together with theCompany, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customaryexceptions.The Current Credit Facility contains customary representations and affirmative covenants. The Current Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, includerestrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers orconsolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations orsubsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries,(xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, and (xix) sales or discounts ofreceivables. The Credit Parties are subject to certain financial covenants under the Current Credit Facility, including, without limitation, tested on the last day ofeach fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to adjusted EBITDAX of 4.00 to 1.00 and(ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. As of December 31, 2018, the Company had $50.0 million outstanding under the Current Credit Facility and had the ability to borrow up to theborrowing base of $350.0 million. For more information regarding our debt, please refer to Part II, Item 8, Note 7 - Long-term Debt.As of December 31, 2018, and through the filing date of this report, the Company is in compliance with all credit facility covenants.Prior Credit FacilityOn April 7, 2017, the Company's Plan was confirmed by the Bankruptcy Court, and the Plan became effective on April 28, 2017. Upon emergencefrom bankruptcy, we (i) executed a credit agreement (the “Prior Credit Facility”) with an initial borrowing base of $191.7 million and maturity date of March31, 2021 and (ii) issued new common stock as part of the $200.0 million rights offering and the $7.5 million transaction with the ad hoc equity committee inthe bankruptcy proceeding. Please refer to Note 15 - Chapter 11 Proceedings and Emergence for additional details.67Table of ContentsContractual Obligations We have the following contractual obligations and commitments as of December 31, 2018: Less than More than Total 1 Year 1 - 3 Years 3 - 5 Years 5 Years (in thousands)Contractual Obligation Current Credit Facility(1) 50,000 — — 50,000 —Interest and fees on Current Credit Facility(1) 17,107 3,469 6,938 6,700 —Delivery commitments(2) 136,253 19,580 56,740 59,933 —Office lease(3) 4,242 1,256 2,752 234 —Asset retirement obligations(4) 118,783 — 17,369 6,343 95,071Total $326,385 $24,305 $83,799 $123,210 $95,071___________________(1)No scheduled payments exist for the Current Credit Facility, and prepayments can be made without penalty, so long as payment is made on the last dayof the interest period. The interest is calculated using the stated rate within the Current Credit Facility for the current outstanding balance, and thecommitment fees are based on the fess on the available borrowing base over the periods presented.(2)The Company has one oil purchase agreement and one operating lease. The calculation on the delivery commitments is based on the minimum grossvolume commitment schedule (as defined in the NGL Crude Logistics, LLC agreement) and applicable differential fees. Please refer to Note 8 -Commitments and Contingencies for additional discussion on this agreement and for a description of our operating lease.(3)The Company has subleased a portion of its office lease. The contractual amounts disclosed are presented gross, excluding total sublease income of $1.4million.(4)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, 2018 and 2017. Because these costs typically extend many years into the future, management preparesestimates and makes judgments that are subject to future revisions based upon numerous factors. Please refer to Part II, Item 8, Note 11 - Asset RetirementObligation, 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. Please refer to Part II, Item 8, Note 1 - Summary of Significant Accounting Policiesto our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management.Method 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 whether68Table of Contentsproductive or nonproductive. All capitalized well costs and other associated costs and leasehold costs of proved properties are amortized on 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 abandonment or impairment of unproved properties in thestatements of operations and comprehensive income (loss) in our consolidated financial statements. Lease acquisition costs are reclassified to provedproperties and depleted on a unit-of-production basis once proved reserves have been assigned.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 MeasureIn the current and prior year, our third-party petroleum consultant prepared our estimates of oil and natural gas reserves and associated future netrevenues. During 2016, our internal corporate reservoir engineering group prepared, and our third-party petroleum engineering consultant audited ourestimates of oil and natural gas reserves and associated future net revenues. While the SEC has adopted rules which allow us to disclose proved, probable, andpossible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC’s revised rules define proved reserves as thequantities 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 timeat which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic orprobabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certainthat it will commence the project within a reasonable time. Our internal corporate reservoir engineering group and our third party petroleum engineeringconsultant must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates areupdated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is asubjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate isa function of the quality 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, 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 amounts or timing offuture reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment ofassets that may be material.69Table of ContentsRevenue RecognitionSales of oil, natural gas, and natural gas liquids are recognized when performance obligations are satisfied at the point control of the product istransferred to the customer. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among otherfactors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result,the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. Please refer to Footnote 2- Revenue Recognition for more information.The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas, and NGLs whendelivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. Atthe end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Companyfactors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. Payment isgenerally received within 30 to 90 days after the date of production. The Company has interests with other producers in certain properties, in which case theCompany uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as of December 31, 2018 and 2017.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 and at least annually. We estimate the expected undiscounted future cash flows of our oil and natural gas propertiesand compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount isrecoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gasproperties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent salesprices 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, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and currentmarket conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when orif future impairment charges for proved 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 abandonment and impairment expense for any decline in value. Leases that were not held by production uponemergence from bankruptcy are being amortized over the remainder of those leases.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 Wattenberg Field 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.70Table of ContentsAsset 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 accompanying statements of operations.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 ofsettlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact thefair value of the existing ARO liability, a corresponding adjustment is made to the related asset.DerivativesWe 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 accompanying statements of operations.Stock-based compensationRestricted Stock Units. We recognize compensation expense for all restricted stock units granted 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. Stock-based compensation expense recorded for restricted stock units is included in general and administrative expenses on our accompanyingstatements of operations.Stock Options. We recognize compensation expense for all stock option awards granted to employees. Stock-based compensation expense ismeasured at the grant date based on the fair value of the award and is recognized as an expense on a straight-line basis over the requisite service period, whichis generally the vesting period. The fair value of stock option grants is based on a Black-Scholes Model. Stock-based compensation expense recorded forstock option awards is included in general and administrative expenses on our accompanying statements of operations.Performance Stock Units. We recognize compensation expense for all performance stock unit awards granted to employees. The number of shares ofthe Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. The PSUs vest in their entirety atthe end of the three-year performance period. The total number of PSUs granted is evenly split between two performance criteria. The first criterion is basedon a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group ofpeer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A)(i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 tradingdays preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning ofthe performance period. The second criterion is based on the Company's average annual return on capital employed (“ROCE”) for each year during the three-year performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period.The fair value of the PSUs is measured at the grant date with a stochastic process method using a Brownian Motion simulation. A stochastic processis a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that byiterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company could notpredict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, theCompany created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences71Table of Contentsregarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature,the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion ofthe PSUs tied to the TSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S.Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers.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, 2018.Recent accounting pronouncementsPlease refer to Part II, Item 8, Note 1 - Summary of Significant Accounting Policies for additional details.Effects of Inflation and Pricing Inflation in the United States increased to 2.2% in 2018 from 1.8% in 2017, which was a decrease from 2.0% in 2016. These changes did not have amaterial impact on our results of operations for the periods ended December 31, 2018, 2017, and 2016. Although the impact of inflation has been relativelyinsignificant in recent years, it is still a factor in the United States economy, and we tend to experience inflationary pressure on the cost of oilfield servicesand equipment as increasing oil and gas prices increase drilling activity in our areas of operations. Material changes in prices also impact the current revenuestream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of oil and gas properties, ARO, and values ofproperties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrowmoney, and retain personnel.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 and72Table of Contentsresults of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and naturalgas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and developmentactivities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations, and capitalresources. If oil and natural gas SEC prices declined by 10%, our proved reserve volumes would decrease by 0.3% and our PV-10 value as of December 31,2018 would decrease by approximately 23% or $223.1 million. If oil and natural gas SEC prices increased by 10%, our proved reserve volumes wouldincrease by 0.4% and our PV-10 value as of December 31, 2018 would increase by approximately 24% or $229.8 million.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.To the extent that we engage in derivative contracts, we may be prevented from realizing the benefits of favorable price changes in the physicalmarket. However, we are similarly insulated against decreases in such prices.Presently, all of our derivative arrangements are concentrated with four counterparties, all of which are lenders under our Current Credit Facility. Ifthese counterparties 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, 2018, a hypothetical upward or downward shift of 10% per Bbl or MMBtu in theNYMEX forward curve as of December 31, 2018 would change our derivative gain by $(15.3) million and $16.1 million, respectively.We have entered into various types of derivative instruments, including commodity price swaps, cashless collars, and puts to mitigate a portion ofour exposure to fluctuations in commodity prices.Interest RatesAt December 31, 2018 and on the filing date of this report we had $50.0 million and $65.0 million outstanding under our Current Credit Facility,respectively. Borrowings under our Current Credit Facility bear interest at a fluctuating rate that is tied to an adjusted Base Rate or LIBOR, at our option. Anyincreases in these interest rates can have an adverse impact on our results of operations and cash flow. As of December 31, 2018 and through the filing date ofthis report, the Company was in compliance with all financial and non-financial covenants.Counterparty and Customer Credit RiskIn connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Four lenders under ourCurrent Credit Facility are currently counterparties on our derivative instruments currently in place and have investment grade credit ratings.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.73Table of ContentsMarketability of Our ProductionThe marketability of our production depends in part upon the availability, proximity, and capacity of third-party refineries, access to regionaltrucking, pipeline and rail infrastructure, natural gas gathering systems, and processing facilities. We deliver crude oil and natural gas produced throughtrucking services, pipelines, and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the priceoffered for our production or result in the shut-in of producing wells or the delay or discontinuance 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,weather, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production isinterrupted at the same time, it could adversely affect our cash flow.Currently, there are no pipeline systems that service wells in our French Lake area of the Wattenberg Field. If neither we nor a third-party constructsthe required pipeline system, we may not be able to fully test or develop our resources in French Lake.74Table of ContentsItem 8. Financial Statements and Supplementary DataReport of Independent Registered Accounting Firm Board of Directors and StockholdersBonanza Creek Energy, Inc.Opinion on the financial statementsWe have audited the accompanying consolidated balance sheets of Bonanza Creek Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”)as of December 31, 2018 and 2017 (Successor), and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity,and cash flows for the year ended December 31, 2018 and for the period from April 29, 2017 through December 31, 2017 (Successor) and the period fromJanuary 1, 2017 through April 28, 2017 (Predecessor), and the related notes (collectively referred to as the “financial statements”). In our opinion, thefinancial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017 (Successor), and theresults of its operations and its cash flows for the year ended December 31, 2018 and for the period from April 29, 2017 through December 31, 2017(Successor) and the period from January 1, 2017 through April 28, 2017 (Predecessor), in conformity with accounting principles generally accepted in theUnited States of America.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’sinternal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued bythe Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 27, 2019 expressed an unqualifiedopinion.Change in accounting principlesAs discussed in Note 1 to the consolidated statements, the Company has changed its method of accounting for revenue from contracts with customers due tothe adoption of the new revenue standard using the modified retrospective approach. Our opinion is not modified with respect to this matter.Basis of presentationAs discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the District of Delaware entered an order confirmingthe plan for reorganization on April 7, 2017, and the Company emerged from bankruptcy on April 28, 2017. Accordingly, the accompanying consolidatedfinancial statements have been prepared in conformity with FASB Accounting Standards Codification 852, Reorganizations, for the Successor as a new entitywith assets, liabilities and a capital structure having carrying amounts not comparable with prior periods, as described in Note 1.Basis for opinionThese financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financialstatements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Companyin accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing proceduresto assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also includedevaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financialstatements. We believe that our audits provide a reasonable basis for our opinion./s/ GRANT THORNTON LLPWe have served as the Company’s auditor since 2017.Oklahoma City, OklahomaFebruary 27, 201975Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and StockholdersBonanza Creek Energy, Inc.We have audited the accompanying consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows of Bonanza CreekEnergy, Inc. and subsidiaries for the year ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements 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 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 auditprovides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of Bonanza Creek Energy, Inc. andsubsidiaries’ operations and their cash flows for the year ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to thefinancial statements, the Company suffered a significant deterioration in liquidity during 2016, and filed for bankruptcy under Chapter 11 of the BankruptcyCode on January 4, 2017. This raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to thesematters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.Hein & Associates LLPDenver, ColoradoMarch 15, 2017 76Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands, except per share amounts) Successor As of December 31, 2018 2017ASSETS Current assets: Cash and cash equivalents$12,916 $12,711Accounts receivable: Oil and gas sales31,799 28,549Joint interest and other47,577 3,831Prepaid expenses and other4,633 6,555Inventory of oilfield equipment3,478 1,019Derivative asset34,408 488Total current assets134,811 53,153Property and equipment (successful efforts method): Proved properties719,198 555,341Less: accumulated depreciation, depletion and amortization(52,842) (17,032)Total proved properties, net666,356 538,309Unproved properties154,352 183,843Wells in progress93,617 47,224Other property and equipment, net of accumulated depreciation of $2,546 in 2018 and $2,224 in 20173,649 4,706Total property and equipment, net917,974 774,082Long-term derivative asset3,864 6Other noncurrent assets4,885 3,130Total assets$1,061,534 $830,371LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable and accrued expenses (note 6)$79,390 $62,129Oil and gas revenue distribution payable19,903 15,667Derivative liability183 11,423Total current liabilities99,476 89,219Long-term liabilities: Credit facility (note 7)50,000 —Ad valorem taxes18,740 11,584Long-term derivative liability— 2,972Asset retirement obligations for oil and gas properties29,405 38,262Total liabilities197,621 142,037 Commitments and contingencies (note 8) Stockholders’ equity: Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of December 31,2018 and 2017— —Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,543,940 and 20,453,549issued and outstanding as of December 31, 2018 and 2017, respectively4,286 4,286Additional paid-in capital696,461 689,068Retained earnings (deficit)163,166 (5,020)Total stockholders’ equity863,913 688,334Total liabilities and stockholders’ equity$1,061,534 $830,371The accompanying notes are an integral part of these consolidated financial statements.77Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)(in thousands, except per share amounts) Successor Predecessor For the YearEnded December31, 2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April28, 2017 For the YearEnded December31, 2016 Operating net revenues: Oil and gas sales $276,657 $123,535 $68,589 $195,295Operating expenses: Lease operating expense 34,825 25,862 13,128 43,671Gas plant and midstream operating expense 10,788 8,341 3,541 12,826Gathering, transportation, and processing 9,732 — — —Severance and ad valorem taxes 18,999 9,590 5,671 15,304Exploration 291 3,745 3,699 946Depreciation, depletion, and amortization 41,883 21,312 28,065 111,215Impairment of oil and gas properties — — — 10,000Abandonment and impairment of unproved properties 5,271 — — 24,692Unused commitments 21 — 993 7,686Contract settlement expense — — — 21,000General and administrative expense (including $7,156, $11,630, $2,116, and$8,892, respectively, of stock-based compensation) 42,453 42,676 15,092 77,065Total operating expenses 164,263 111,526 70,189 324,405Income (loss) from operations 112,394 12,009 (1,600) (129,110)Other income (expense): Derivative gain (loss) 30,271 (15,365) — (11,234)Interest expense (2,603) (773) (5,656) (62,058)Gain on sale of properties 27,324 — — —Reorganization items, net (note 16) — — 8,808 —Gain on termination fee — — — 6,000Other income (loss) 800 (1,267) 1,108 (2,548)Total other income (expense) 55,792 (17,405) 4,260 (69,840)Income (loss) from operations before taxes 168,186 (5,396) 2,660 (198,950)Current income tax benefit (expense) (note 10) — 376 — —Deferred income tax benefit (note 10) — — — —Net income (loss) $168,186 $(5,020) $2,660 $(198,950)Comprehensive income (loss) $168,186 $(5,020) $2,660 $(198,950)Basic net income (loss) per common share: $8.20 $(0.25) $0.05 $(4.04)Diluted net income (loss) per common share: $8.16 $(0.25) $0.05 $(4.04)Basic weighted-average common shares outstanding 20,507 20,427 49,559 49,268Diluted weighted-average common shares outstanding 20,603 20,427 50,971 49,268The accompanying notes are an integral part of these consolidated financial statements.78Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY Additional Accumulated Common Stock Paid-In Earnings Shares Amount Capital (Deficit) Total (in thousands, except share data)Balances, January 1, 2016 (Predecessor) 49,754,408 $49 $806,386 $(597,028) $209,407Restricted common stock issued 154,656 2 — — 2Restricted common stock forfeited (120,477) (1) — — (1)Restricted stock used for tax withholdings (127,904) (1) (288) — (289)Stock-based compensation — — 8,892 — 8,892Net loss — — — (198,950) (198,950)Balances, December 31, 2016 (Predecessor) 49,660,683 $49 $814,990 $(795,978) $19,061Restricted common stock issued 767,848 1 — — 1Restricted common stock forfeited (5,134) — — — —Restricted stock used for tax withholdings (318,180) (1) (427) — (428)Fair value of equity issued to existing commonstockholders — — (23,410) — (23,410)Stock-based compensation — — 2,116 — 2,116Net income — — — 2,660 2,660Balances, April 28, 2017 (Predecessor) 50,105,217 $49 $793,269 $(793,318) $—Cancellation of Predecessor equity (50,105,217) (49) (793,269) 793,318 —Balances, April 28, 2017 (Predecessor) — $— $— $— $—Issuance of Successor equity 20,356,071 4,285 679,836 — 684,121 Balances, April 28, 2017 (Successor) 20,356,071 $4,285 $679,836 $— $684,121Restricted common stock issued 173,200 2 — — 2Restricted stock used for tax withholdings (75,722) (1) (2,398) — (2,399)Stock-based compensation — — 11,630 — 11,630Net loss — — — (5,020) (5,020)Balances, December 31, 2017 (Successor) 20,453,549 $4,286 $689,068 $(5,020) $688,334Restricted common stock issued 84,345 — — — —Restricted stock used for tax withholdings (25,991) — (863) — (863)Exercise of stock options 32,037 — 1,100 — 1,100Stock-based compensation — — 7,156 — 7,156Net income — — — 168,186 168,186Balances, December 31, 2018 (Successor) 20,543,940 $4,286 $696,461 $163,166 $863,913The accompanying notes are an integral part of these consolidated financial statements.79Table of ContentsBONANZA CREEK ENERGY, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Successor Predecessor Year EndedDecember 31,2018 April 29, 2017throughDecember 31,2017 January 1,2017 throughApril 28, 2017 Year EndedDecember 31,2016 Cash flows from operating activities: Net income (loss)$168,186 $(5,020) $2,660 $(198,950)Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion and amortization41,883 21,312 28,065 111,215Non-cash reorganization items— — (44,160) —Impairment of oil and gas properties— — — 10,000Abandonment and impairment of unproved properties5,271 — — 24,692Well abandonment costs and dry hole expense— 75 2,931 872Stock-based compensation7,156 11,630 2,116 8,892Amortization of deferred financing costs and debt premium30 — 374 3,180Derivative (gain) loss(30,271) 15,365 — 11,234Derivative cash settlements(18,160) (1,464) — 18,333Gain on sale of oil and gas properties(27,324) — — —Inventory write-offs248 1,758 — 4,390Other(3,559) 11 18 (323)Changes in current assets and liabilities: Accounts receivable(46,988) (4,477) (6,640) 35,282Prepaid expenses and other assets2,214 (1,979) 963 (1,838)Accounts payable and accrued liabilities19,953 (8,470) (5,880) (11,616)Settlement of asset retirement obligations(2,041) (1,167) (331) (800)Net cash provided by (used in) operating activities116,598 27,574 (19,884) 14,563Cash flows from investing activities: Acquisition of oil and gas properties(2,892) (5,383) (445) (98)Exploration and development of oil and gas properties(264,231) (76,384) (5,123) (52,344)Proceeds from sale of oil and gas properties103,134 — — —Payments of contractual obligation— — — (12,000)Operating bonds— — — (2,672)Additions to property and equipment - non oil and gas(387) (874) (454) (346)Net cash used in investing activities(164,376) (82,641) (6,022) (67,460)Cash flows from financing activities: Proceeds from Current Credit Facility50,000 — — —Proceeds from Prior Credit Facility90,000 — — —Payments to Prior Credit Facility(90,000) — — —Proceeds from predecessor credit facility— — — 209,000Payments to predecessor credit facility— — (191,667) (96,333)Proceeds from sale of common stock— — 207,500 —Proceeds from exercise of stock options1,100 — — —Payment of employee tax withholdings in exchange for the return of common stock(863) (2,398) (427) (289)Deferred financing costs(2,239) — — (316)Net cash provided by (used in) financing activities47,998 (2,398) 15,406 112,062Net change in cash, cash equivalents, and restricted cash220 (57,465) (10,500) 59,165Cash and cash equivalents, and restricted cash: Beginning of period12,782 70,247 80,747 21,582End of period$13,002 $12,782 $70,247 $80,747Supplemental cash flow disclosure: 80Table of ContentsCash paid for interest$2,582 $523 $3,509 $58,900Cash paid for reorganization items$— $— $52,968 $—Changes in working capital related to exploration, development and acquisition of oil and gasproperties$11,769 $16,057 $3,360 $(30,044)The accompanying notes are an integral part of these consolidated financial statements.81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. (“BCEI” or, together with its consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing,extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field inColorado.Basis of PresentationAs of December 31, 2018, the balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek EnergyOperating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactionshave been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after thebalance sheet date of December 31, 2018, through the filing date of this report.On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which owns all of the outstanding equityinterest in Bonanza Creek Energy Upstream LLC and Bonanza Creek Energy Midstream, LLC. These subsidiaries comprised the Company's Mid-Continentregion and assets. Please refer to Note 4 - Divestitures for additional discussion.As of December 31, 2017, the balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek EnergyOperating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, HolmesEastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated.On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the“Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the“Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint PrepackagedPlan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking toadminister all of the Debtors' Chapter 11 Cases jointly under the caption “In re Bonanza Creek Energy, Inc., et al” (Case No. 17-10015). The Debtors receivedbankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). Although the Companyis no longer a debtor-in-possession, the Company was a debtor-in-possession during a portion of the year ended December 31, 2017. As such, certain aspectsof the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financialcondition and results of operations for the period presented.Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a resultof the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statementsafter April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financialstatements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April28, 2017 and dates prior thereto. Please refer to Note 16 - Fresh-Start Accounting for additional discussion.Subsequent to January 4, 2017 and through the date of emergence, all expenses, gains, and losses directly associated with the reorganization arereported as reorganization items, net in the accompanying consolidated statements of operations and comprehensive income (loss) (“statements ofoperations”).References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequentto April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or priorto April 28, 2017. Throughout these financial statements, the Company refers to the 2017 annual period which is comprised of both Successor andPredecessor periods. References to “Current Successor Period” relate to the year ended December 31, 2018. References to “2017 Successor Period” relate tothe period of April 29, 2017 through December 31, 2017. References to the “2017 Predecessor Period” and “2016 Predecessor Period” relate to the periods ofJanuary 1, 2017 through April 28, 2017 and January 1, 2016 through December 31, 2016, respectively.82Table of Contents 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.Going Concern PresumptionOur consolidated financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization ofassets, and the satisfaction of liabilities and other commitments in the normal course of business.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.These receivables are generally unsecured. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probablethat a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, theCompany usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables aretypically collected within one to two months, and the Company 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 net realizable value, 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. The computation of DD&A takes into consideration restoration, dismantlement, andabandonment costs and anticipated proceeds from salvaging equipment.The 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.As of December 31, 2018, the Company's gathering assets comprised $120.4 million, $0.9 million, and $0.1 million of proved properties, wells inprogress, and unproved properties, respectively, on the accompanying consolidated balance sheets.83Table of ContentsLease acquisition costs are reclassified to proved properties and depleted on a unit-of-production basis once proved reserves have been assigned.The Company assesses its unproved properties periodically for impairment on a property-by-property basis, which requires significant judgment. Leases thatwere not held by production upon emergence from bankruptcy are being amortized off over the remainder of those leases. Leases acquired post-emergence areassessed for impairment applying the following factors:•the remaining amount of unexpired term under leases;•the Company's ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that maybe closer to expiration;•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases;•its evaluation of the continuing successful results from the application of completion technology by the Company or by other operators in 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 3 - 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 (“balance sheets”). For additional discussion, please refer to Note 11 - Asset Retirement Obligations.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.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.Assets 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. Please refer to Footnote 4 - Divestitures for moreinformation. 84Table of ContentsRevenue RecognitionSales of oil, natural gas, and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of theproduct is transferred to the customer. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, amongother factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As aresult, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. Please refer toFootnote 2 - Revenue Recognition for more information.The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas, and NGLs whendelivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. Atthe end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Companyfactors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. Payment isgenerally received within 30 to 90 days after the date of production. The Company has interests with other producers in certain properties, in which case theCompany uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as of December 31, 2018 and 2017.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 2017, 2016, and 2015are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions during any period presented.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 theyears ended December 31, 2018, 2017, and 2016, NGL Crude Logistics accounted for 66%, 44%, and 0% of sales, respectively; Lion Oil Trading &Transportation, Inc. accounted for 8%, 18%, and 18% of sales, respectively; and Duke Energy Field Services accounted for 8%, 16%, and 14% of sales,respectively. For the year ended December 31, 2016, Silo Energy, LLC accounted for 50% of 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 were placed with major financial institutions and take the form of swaps, collars, or puts. The oil contracts are indexed to NYMEXWTI prices, and natural gas contracts are indexed to NYMEX HH and CIG prices, which have a high degree of historical correlation with actual pricesreceived by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fairvalue. For additional discussion, please refer to Note 13 - Derivatives.Earnings Per ShareEarnings per basic and diluted share within the Successor Company are calculated under the treasury stock method. Basic net income (loss) percommon share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding forthe respective period. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common sharesoutstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested restricted stockunits (“RSUs”), in-the-money outstanding stock options, unvested performance stock units (“PSUs”), and exercisable warrants, which are measured using thetreasury stock method. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and areconsequently excluded from the calculation of diluted earnings per share.85Table of ContentsEarnings per basic and diluted share within the Predecessor Company were calculated under the two-class method. Pursuant to the two-class method,the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method,earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstandingduring the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security accordingto undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive atthe earnings allocated to common stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated toshare in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on thebasis of the weighted-average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstandingduring the period using the more dilutive of the treasury method or two-class method. 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, credit facilities, andderivative instruments. Cash and cash equivalents, trade receivables, trade payables, and accrued liabilities are carried at cost and approximate fair value dueto the short-term nature of these instruments. Our credit facilities have variable interest rates, so they approximate fair value. Derivative instruments arerecorded at fair value.Recently Issued and Adopted Accounting StandardsIn May 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-09, Revenue from Contracts with Customers (Topic606) Accounting Standards Codification (“ASC”) 606 (“ASC 606”). Several additional related updates were issued since that point. In summary, revenuerecognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the Companyexpects to be entitled in exchange for those goods or services. The guidance also requires enhanced financial statement disclosures over revenue recognitionand provisions regarding future revenues and expenses under a gross-versus-net presentation.The standard was required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modifiedretrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The standard is effective for annual reportingperiods beginning after December 15, 2017, and interim periods within those annual periods. We adopted the new standard on January 1, 2018, and itsadoption did not have a significant impact on our financial statements. Please refer to Note 2 - Revenue Recognition for additional discussion.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. We adopted the newstandard on January 1, 2018, and its adoption did not have a material impact on our financial statements and disclosures.Effective January 1, 2017, the Company adopted FASB Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting. Theobjective of this update was to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accountingfor share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on thestatement of cash flows. This update is effective for the annual periods beginning after December 15, 2016, and interim periods within those annual periods.As of January 1, 2017, and thereafter, the Company did not have excess tax benefits associated with its stock compensation, and therefore, there was no taximpact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes have alreadybeen classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. This standard allowed companies toelect to account for forfeitures as they occurred or estimate the number of awards that will vest. The Company elected to account for forfeitures as they occur,resulting in a minimal impact upon adoption of this standard.In August 2016, the FASB issued Update No. 2016-15 - Classification of Certain Cash Receipts and Cash Payments, which clarifies thepresentation of specific cash receipts and cash payments within the statement of cash flows. This86Table of Contentsauthoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Earlyadoption is permitted. We adopted the new standard on January 1, 2018, and its adoption did not have a material impact on our consolidated statements ofcash flows (“statements of cash flows”) and related disclosures.In November 2016, the FASB issued Update No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This update clarifies how entitiesshould present restricted cash and restricted cash equivalents in the statement of cash flows by including them with cash and cash equivalents whenreconciling the total beginning and ending amounts for the periods shown on the statements of cash flows. This guidance is to be applied using aretrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoptionis permitted. We adopted the new standard on January 1, 2018, and the prior period has been adjusted to conform to the current period presentation, whichresulted in an increase in cash used in investing activities of $0.1 million for the 2017 Successor and Predecessor Periods, respectively, and $0.2 million forthe year ended December 31, 2016.The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that sums to the totalof such amounts shown in the accompanying statements of cash flows (in thousands): Successor Predecessor As of December 31, As of 2018 2017 April 28, 2017 December 31, 2016Cash and cash equivalents$12,916 $12,711 $70,183 $80,565Restricted cash included in other noncurrent assets86 71 64 182Total cash, cash equivalents and restricted cash as shown in thestatements of cash flows$13,002 $12,782 $70,247 $80,747Restricted cash consists of funds for road maintenance and repairs.In January 2017, the FASB issued Update No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. This updateclarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for asacquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interimperiods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted this new standard on January 1, 2018 andwill apply it to any future acquisitions or disposals of assets or business.In February 2017, the FASB issued Update No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. This update is meant to clarifyexisting guidance and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modifiedretrospective method as outlined in the guidance and is effective at the same time as Update 2014-09, Revenue from Contracts with Customers (Topic 606).We adopted this new standard on January 1, 2018, and its adoption did not have a material impact on our financial statements and disclosures.In May 2017, the FASB issued Update No. 2017-09 Compensation – Stock Compensation (Topic 718). The purpose of this update is to provideclarity as to which modifications of awards require modification accounting under Topic 718. Previously issued guidance frequently resulted in varyinginterpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award isthe same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award;and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting isutilized, award disclosure requirements under Topic 718 remain unchanged. This guidance was effective for annual or any interim periods beginning afterDecember 15, 2017. We adopted this new standard on January 1, 2018. There was no material impact due to the adoption of this guidance.In February 2016, the FASB issued Update No. 2016-02 - Leases (Topic 842) to increase transparency and comparability among organizations byrecognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in thebalance sheet will be classified as either finance or operating, with such classification affecting the presentation within the statements of cash flows. Thestandard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. The Company adopted thisguidance on January 1, 2019, using the modified retrospective approach.87Table of ContentsAs part of the assessment process, the Company utilized external consultants to evaluate agreements under this guidance as well as assess thecompleteness of the lease population. The types of agreements evaluated under this guidance included the Company’s office leases, corporate asset rentals,drilling rig agreements, well-completion agreements, midstream infrastructure agreements, generator and compressor rentals, various other field equipmentrentals, and other arrangements that included potential lease obligations under this guidance. The Company has completed the process of reviewing anddetermining the contracts and agreements to which the new guidance applies, and has implemented policies, internal controls, and processes that will benecessary to support the Company’s compliance with the additional accounting and disclosure requirements under this guidance. The lease administrationsystem that will support the Company’s compliance with this guidance after adoption is operational and currently being populated with the necessary leasedata and relevant assumptions.Policy elections made by the Company as allowed under this guidance include (a) not recognizing leases with terms that are less than twelve monthson the balance sheet, (b) combining lease and non-lease components as a single lease, (c) and applying practical expedients, which allow the Company toavoid reassessing contracts that commenced prior to adoption and were correctly classified under ASC 840. Adoption of this guidance will result in right-of-use assets and right-of-use liabilities on the balance sheets; however, the Company is not in a position to provide an estimate of the full quantitative impactsat this time. In January 2018, the FASB issued Update 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842, whichpermits an entity to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity's adoption of Update2016-02 and not previously accounted for as leases. An entity that elects this practical expedient should evaluate new or modified land easements under thisguidance beginning at the date Update 2016-02 is adopted. The Company plans to elect this practical expedient option at the same time it adopts Update2016-02.In July 2018, the FASB issued Update No. 2018-11, Leases (Topic 842): Targeted Improvements, which provides for an additional transition methodthat allows an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance ofretained earnings (deficit) in the period of adoption. The Company plans to elect this transition method, which will eliminate the need for adjusting priorperiod comparable financial statements prepared under current lease accounting guidance. The Company will adopt this guidance at the same time it adoptsUpdate 2016-02.In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair ValueMeasurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periodsbeginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures.In August 2018, the Securities and Exchange Commission, (“SEC”) issued a final rule, Disclosure Update and Simplification, that updates andsimplifies SEC disclosure requirements. The primary changes include removing the requirement to disclose outside of the consolidated financial statementshistorical and pro forma ratios of earnings to fixed charges and historical low and high trading prices of the Company's common stock and adding arequirement to provide within the interim financial statements an analysis of changes in stockholders' equity for the current and comparative quarterly andyear-to-date periods. Other changes included requirements related to segment, geographic area and dividend disclosures. The final rule was effectiveNovember 5, 2018. The Company adopted the standard for this annual report ending December 31, 2018, and it did not have a material impact on theCompany's disclosures. There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements anddisclosures that have been issued but not yet adopted by the Company as of December 31, 2018, and through the filing date of this report.NOTE 2 - REVENUE RECOGNITIONOn January 1, 2018, the Company adopted ASC 606, using the modified retrospective approach for all applicable contracts at the date of initialadoption. Results for reporting periods beginning January 1, 2018 are presented in accordance with ASC 606, while prior period amounts are reported inaccordance with ASC 605 - Revenue Recognition. The impact of adoption is as follows (in thousands):88Table of Contents Year Ended December 31, 2018 As Unadjusted(1) ASC 606Adjustments As ReportedOperating Revenues: Oil sales$228,661 $— $228,661 Natural gas sales 18,076 4,293 22,369 NGLs sales 20,188 5,439 25,627Oil and gas sales$266,925 $9,732 $276,657 Operating expenses: Gathering, transportation and processing$— $9,732 $9,732 Net income$168,186 $— $168,186____________________(1) This column excludes the impact of ASC 606 and is consistent with the presentation prior to January 1, 2018.Revenue from Contracts with CustomersSales of oil, natural gas, and NGLs are recognized when performance obligations are satisfied at the point control of the product is transferred to thecustomer. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a welldelivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil,natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.Performance ObligationsOil SalesUnder our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-uponindex price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead, tank outlet, leaseautomatic custody transfer meter, or other contractually agreed-upon delivery point, at the net contracted price received.Natural Gas and NGLs SalesUnder our natural gas processing contracts, we deliver natural gas to an agreed-upon delivery point. The delivery points are specified within eachcontract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers andprocesses the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where we maintain controlthrough the outlet of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing fees presentedas an expense in our consolidated statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of themidstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from themidstream processing entity and, as a result, we recognize revenue on a net basis.Working Interest PartnersThe Company and its working interest partners have entered into joint operating agreements, which govern the marketing and selling of the workinginterest partners' share of oil, natural gas, and NGLs. When selling oil, natural gas, and NGLs on behalf of working interest owners, the Company is acting asan agent and thus reports the revenue on a net basis.Transaction PriceAs noted above, the transaction price is generally tied to a market index, net of adjustments or price differentials, with the variable considerationbeing the estimation process and related accruals; however, any identified differences between our revenue estimates and actual revenue received historicallyhave not been significant.89Table of ContentsAs further described in Note 8 - Commitments and Contingencies, one contract with NGL Crude Logistics, LLP (“NGL”, known as the “NGLagreement”) has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On anon-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL agreement based on approved productionplans to determine if liquidated damages to NGL are probable. As of December 31, 2018, the Company believes that the volumes delivered to NGL will be inexcess of the MVCs required then and during the upcoming approved production plan. As a result of this analysis, to date, no variable consideration relatedto potential liquidated damages has been considered in the transaction price for the NGL agreement.Transaction Price Allocated to Remaining Performance ObligationsUnder our sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, andthe transaction price for remaining performance obligations is determined in accordance with the preceding section during the period in which theperformance obligation is satisfied. For our product sales that have a contract term of one year or less, we applied the practical expedient under the guidance,which states that a Company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation ispart of a contract that has an original expected duration of one year or less.Contract BalancesUnder our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment isunconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under this guidance. At December 31, 2018 andDecember 31, 2017, our receivables from contracts with customers were $31.8 million and $28.5 million, respectively.Prior-Period Performance ObligationsWe record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGLs sales maynot be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to thepurchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received forproduct sales in the month in which payment is received from the purchaser. We have existing internal controls for our revenue estimation process and relatedaccruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period fromJanuary 1, 2018 through December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reportingperiods was not material.NOTE 3 - IMPAIRMENTSDuring 2018, the Company incurred its standard annual amortization of $5.3 million on its emergence leases that were not held by production at thetime of our emergence as disclosed in the abandonment and impairment of unproved properties line item in the accompanying statements of operations.There were no impairments for the year ended December 31, 2017.During the first quarter of 2016, the Company impaired its oil and gas properties in the Mid-Continent region by $10.0 million, based upon the mostrecent bid for the assets received while the assets were held for sale. The Company also recorded unproved properties impairments of $24.7 million for non-core leases expiring within the Wattenberg Field. For additional discussion, please refer to Note 12 - Fair Value Measurements.NOTE 4 - DIVESTITURESDuring the first quarter of 2018, the Company established a plan to sell all of the Company's assets within its Mid-Continent region and North ParkBasin in order to focus on and partially fund the development of our core assets in the Wattenberg Field in Colorado, at which point they were deemed heldfor sale.The Company sold its North Park Basin assets on March 9, 2018 for minimal net proceeds and full release of all current and future obligationsresulting in a minimal net loss. As of December 31, 2017, the assets within the Company's North Park Basin represented $5.4 million, net of accumulateddepreciation, depletion, and amortization; and a corresponding asset retirement obligation liability of approximately $5.4 million.On August 6, 2018, the Company entered into an agreement to simultaneously close and divest of all of its assets within its Mid-Continent region.Net proceeds from the sale amounted to $102.9 million, subject to customary post-closing adjustments, resulting in a gain of approximately $27.3 million,included in the gain on sale of properties line item in the accompanying statements of operations. The original purchase price of $117.0 million was subjectto customary purchase-price90Table of Contentsadjustments, comprised of operational cash activity related to the Mid-Continent assets, for the time period between the effective date of February 1, 2018and the closing date of August 6, 2018. The divestiture did not represent a strategic shift and is not expected to have a significant effect on the Company'soperations or financial results; therefore, the disposal did not meet the criteria of discontinued operations.NOTE 5 - OTHER NONCURRENT ASSETSOther noncurrent assets contain the following (in thousands): Successor As of December 31, 2018 2017Operating bonds $2,713 $2,683Deferred financing costs 1,710 —AMT credit refund(1) 376 376Restricted cash 86 71Other noncurrent assets $4,885 $3,130______________________________________(1) Represents the alternative minimum tax credit refund due to the Company upon application of the newly enacted comprehensive tax legislation that tookeffect on December 22, 2017.NOTE 6 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES Accounts payable and accrued expenses contain the following (in thousands): Successor As of December 31, 2018 2017Drilling and completion costs$33,602 $21,833Accounts payable trade11,532 6,256Accrued general and administrative cost12,728 10,025Lease operating expense2,183 5,005Accrued interest241 250Accrued oil and gas hedging— 808Production and ad valorem taxes and other19,104 17,952Total accounts payable and accrued expenses$79,390 $62,129NOTE 7 - LONG-TERM DEBTSuccessor DebtCurrent Credit Facility On December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as theadministrative agent, and a syndicate of financial institutions, as lenders (the “Current Credit Facility”). The Current Credit Facility has an aggregate originalcommitment amount of $750.0 million and matures on December 7, 2023. The initial borrowing base is $350.0 million, and there are no scheduled borrowingbase redeterminations until May 1, 2019, with subsequent semi-annual redeterminations thereafter. Borrowings under the Current Credit Facility will bear interest at a per annum rate equal to, at the option of the Company, either (i) a LondonInterBank Offered Rate (“LIBOR”), subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Current Credit Facility (the“Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank,N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interestpublished by the Federal Reserve Bank of New York as the overnight bank funding rate and (d) a LIBOR offered rate91Table of Contentsfor a one month interest period, subject to a 0% LIBOR floor plus a margin of 0.75% to 1.75%, based on the utilization of the Current Credit Facility (the“Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selectedby the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterlyin arrears. The Current Credit Facility is guaranteed by all wholly owned domestic subsidiaries of the Company (each, a “Guarantor” and, together with theCompany, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customaryexceptions.The Current Credit Facility contains customary representations and affirmative covenants. The Current Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, includerestrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers orconsolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations orsubsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries,(xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, and (xix) sales or discounts ofreceivables (xx) dividend payments. The Credit Parties are subject to certain financial covenants under the Current Credit Facility, including, without limitation, tested on the last day ofeach fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to adjusted EBITDAX of 4.00 to 1.00 and(ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company had $50.0 million outstanding on the Current Credit Facility as of December 31, 2018 and had no amounts outstanding under the creditfacility in effect as of December 31, 2017.In connection with the Current Credit Facility, the Company capitalized $2.2 million in deferred financing costs, of which, $1.7 million and $0.5million of the total amounts capitalized are presented within other noncurrent assets and prepaid expenses and other line items, respectively, in theaccompanying balance sheets as of December 31, 2018.Prior Credit FacilityOn the Effective Date, the Company entered into a new revolving credit facility, as the borrower, with KeyBank National Association, as theadministrative agent, and certain lenders party thereto (the “Prior Credit Facility”). The new borrowing base of $191.7 million was redeterminedsemiannually, as early as April and October of each year. The original maturity date of this Prior Credit Facility was March 31, 2021.The Prior Credit Facility restricted, among other items, certain dividend payments, additional indebtedness, purchase of margin stock, asset sales,loans, investments, and mergers. The Prior Credit Facility also contains certain financial covenants, which require the maintenance of certain financial andleverage ratios, as defined by the Prior Credit Facility. The Prior Credit Facility stated that beginning with the fiscal quarter ending September 30, 2017, andeach following fiscal quarter through the maturity of the Prior Credit Facility, the Company's leverage ratio of indebtedness to EBITDAX was not to exceed3.50 to 1.00. Beginning also with the fiscal quarter ending September 30, 2017, and each following fiscal quarter, the Company was required to maintain aminimum current ratio of 1.00 to 1.00 and a minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense of2.50 to 1.00 as of the end of the respective fiscal quarter. The Prior Credit Facility also required the Company maintain a minimum asset coverage ratio of1.35 to 1.00 as of the fiscal quarters ending September 30, 2017 and December 31, 2017. The minimum asset coverage ratio was only applicable until the firstredetermination in April of 2018. As of December 31, 2017, and through the filing date of this report, the Company is in compliance with all of the PriorCredit Facility covenants.Our obligations under the Prior Credit Facility were secured by first priority liens on all of our property and assets (whether real, personal, or mixed,tangible or intangible), including our proved reserves and our oil and gas properties (which term was defined to include fee mineral interests, term mineralinterests, leases, subleases, farm-outs, royalties, overriding royalties, net profit interests, carried interests, production payments, back in interests, andreversionary interests). The Prior Credit Facility was guaranteed by the Company and all of its direct and indirect subsidiaries. 92Table of ContentsThe Prior Credit Facility provided for interest rates plus an applicable margin to be determined based on LIBOR or a base rate, at the Company’selection. LIBOR borrowings bore interest at LIBOR, plus a margin of 3.00% to 4.00% depending on the utilization level, and the base rate borrowings boreinterest at the Reference Rate, as defined in the Prior Credit Facility, plus a margin of 2.00% to 3.00% depending on the utilization level.This Prior Credit Facility was dissolved and settled in full as of December 7, 2018.Predecessor DebtPredecessor Credit Facility The predecessor credit facility, dated March 29, 2011, as amended, with a syndication of banks, provided for a total credit facility size of $1.0billion. The predecessor credit facility provided for interest rates plus an applicable margin to be determined based on LIBOR or a base rate, at theCompany’s election. LIBOR borrowings bore interest at LIBOR plus 1.50% to 2.50% depending on the utilization level, and the base rate borrowings boreinterest at the “Bank Prime Rate,” as defined in the predecessor credit facility, plus 0.50% to 1.50%. The borrowing base on the predecessor credit facility was$150.0 million on October 31, 2016. As of December 31, 2016, the Company had $191.7 million outstanding under the credit facility and had a borrowingbase deficiency of $41.7 million.Predecessor Senior Unsecured NotesThe $500.0 million aggregate principal amount of 6.75% Senior Notes that, prior to the Company's Chapter 11 filing, matured on April 15, 2021 andthe $300.0 million aggregate principal amount of 5.75% Senior Notes that matured on February 1, 2023 were unsecured senior obligations.On the Effective Date, by operation of the Plan, all outstanding obligations under the Senior Notes were canceled and 9,481,610 shares of theCompany's new common stock were issued. Please refer to Note 15 - Chapter 11 Proceedings and Emergence for additional discussion.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 authoritative accounting 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.Following negotiations with the Colorado Department of Public Health and Environment (“CDPHE”), over self-reported air quality noncompliance,on October 3, 2017, the Company agreed to a Compliance Order on Consent (the “COC”) with the CDPHE. As part of the COC, the Company was required topay a $0.2 million penalty. Additionally, as further required by the COC, the Company will perform certain mitigation projects and adopt certain proceduresand processes addressing the monitoring, reporting, and control of air emissions with respect to the Company's storage tank facilities in the Wattenberg Field.The COC further set forth compliance requirements and criteria for continued operations and contains provisions regarding, record-keeping, modifications tothe COC, circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownershipinterests covered by the COC. In order to be in compliance, the Company incurred $1.2 million and $0.7 million in 2018 and 2017, respectively, andcurrently anticipates spending $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance andCDPHE approval.93Table of ContentsIn September 2018, the Company reached a settlement in a case in which it was one of several plaintiffs seeking reimbursement of ad valorem taxesthat were assessed by a special metropolitan district in Colorado. Pursuant to that settlement, the Company received a gross reimbursement of ad valoremtaxes paid in the amount of $7.4 million. The Company estimates that $2.3 million of the reimbursement is due to the Company’s associated interest ownersas shown in the accounts payable and accrued expenses line item in the accompanying balance sheets. The remaining net settlement amount of $5.1 millionis presented as a reimbursement in the accompanying statements of operations within the severance and ad valorem taxes line item. This net settlementamount will be further reduced to reflect the reimbursement to the State of Colorado of a certain amount of severance tax credits received in connection withad valorem taxes historically paid by the Company.In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), alleging failure to obtain requiredpermits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the DenverMetropolitan and North Front Range of Colorado, among other things. The NOI letter appears to challenge long-established federal and state regulations andpolicies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Actand state counterpart statutes. Because the allegations made in the NOI letter are based on novel and unprecedented interpretations of complex federal andstate air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit or will lead to actual suitby WEG against the Company, but the Company will vigorously defend against such allegations if sued, and will coordinate as much as possible with stateand federal permitting authorities to maintain the validity of its current and future air permits for such facilities.CommitmentsUpon emergence from bankruptcy, the new purchase agreement to deliver fixed determinable quantities of crude oil with NGL Crude Logistics, LLCbecame effective and the original purchase agreement with NGL was canceled. The terms of the new NGL agreement consists of defined volume commitmentsover an initial seven-year term. Under the terms of the new NGL agreement, the Company will be required to make periodic deficiency payments for anyshortfalls in delivering minimum volume commitments, which are set in six-month periods beginning in January 2018. There were no minimum volumecommitments for the year ending December 31, 2017. During 2018, the average minimum volume commitment was approximately 10,100 barrels per day andincreases by approximately 41% from 2018 to 2019 and approximately 3% each year for the remainder of the contract, to a maximum of approximately16,000 barrels per day. The aggregate financial commitment fee over the seven-year term, based on the minimum volume commitment schedule (as defined inthe agreement) and the applicable differential fee, is $136.3 million as of December 31, 2018. Upon notifying NGL at least twelve months prior to theexpiration date of the new NGL agreement, the Company may elect to extend the term of the new NGL agreement for up to three additional years.The Company rejected its Denver office lease, which was confirmed in the Plan. On April 29, 2017, the Company entered into a new office leaseagreement to rent office facilities. The lease is non-cancelable and expires in February 2022. Rent expense was $0.9 million for the year ended December 31,2018, 2017 Successor Period, and 2017 Predecessor Period and $2.8 million for the year ended December 31, 2016.The annual minimum commitment payments on the new NGL agreement and the new office lease for the next five years as of December 31, 2018 arepresented below (in thousands): NGL Commitments (1)Office Lease Commitments(2)Total2019 $19,5801,25620,8362020 27,9491,35129,3002021 28,7911,40130,1922022 29,48523429,7192023 30,448—30,4482024 and thereafter ———Total $136,2534,242140,495 ____________________(1) The above calculation is based on the minimum volume commitment schedule (as defined in the new NGL agreement) and applicable differential fees.(2) The Company has subleased a portion of its office lease. The contractual amounts disclosed are presented gross, excluding total sublease income of $1.4million.94Table of ContentsNOTE 9 - STOCK-BASED COMPENSATION2017 Long Term Incentive PlanUpon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergenceBoard, which allows for the issuance of restricted stock units, performance stock units, and stock options. On the Effective Date, the Companyreserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan. See below for further discussion of awards grantedunder the 2017 LTIP.Inducement AwardsDuring the year ended December 31, 2018, the Company granted inducement awards in the form of RSUs separate and distinct from the 2017 LTIP.The total number of inducement awards granted to employees during the year ended December 31, 2018 was 170,613 representing a total fair value of $4.6million.Restricted Stock UnitsThe 2017 LTIP, established by the pre-emergence Board, allows for the issuance of RSUs to members of the Board of Directors and employees of theCompany at the discretion of the Board of Directors. Each RSU represents one share of the Company's new common stock to be released from restriction uponcompletion of the vesting period. The awards typically vest in one-third increments over three years. The RSUs are valued at the grant date share price and arerecognized as general and administrative expense over the vesting period of the award. During June 2017, the Company granted 63,894 RSUs to non-executive members of the Board of Directors, with a fair value of $2.3 million. Thisgrant is intended to cover a three-year period, and the RSUs will vest in equal installments on each of the first three anniversaries. The vested shares will bereleased upon the earlier of the third anniversary of the grant date, a change of control, or the director's separation from the Company.Total expense recorded for RSUs, inclusive of the Board of Director grants, for the Current and 2017 Successor Periods was $5.2 million and $7.9million, respectively. The fair value of the RSUs granted from the 2017 LTIP during the Current and 2017 Successor Periods was $6.2 million and $13.4million, respectively.As of December 31, 2018, unrecognized compensation cost related to all RSUs was $10.2 million and will be amortized through 2023.A summary of the status and activity of non-vested restricted stock units is presented below: Restricted Stock Units Weighted-AverageGrant-DateFair Value Non-vested at beginning of 2017 Successor Period— $—Granted452,996 $34.62Vested(173,200) $34.19Forfeited(18,631) $34.36Non-vested as of December 31, 2017261,165 $34.93Granted387,720 $27.80Vested(84,345) $30.63Forfeited(83,705) $29.78Non-vested as of December 31, 2018480,835 $30.83Cash 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 Current and 2017 Successor Periods.95Table of ContentsPerformance Stock UnitsThe 2017 LTIP, established by the pre-emergence Board, allows for the issuance of PSUs to employees at the sole discretion of the Board ofDirectors. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded.The PSUs vest in their entirety at the end of the three-year performance period. The total number of PSUs granted is evenly split between two performancecriterion. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance periodcompared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies isdetermined by dividing (A)(i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weightedaverage share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price forthe 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's average annual return on capitalemployed (“ROCE”) for each year during the three-year performance period. Compensation expense associated with PSUs is recognized as general andadministrative expense over the performance period.The fair value of the PSUs was measured at the grant date with a stochastic process method using a Brownian Motion simulation. A stochasticprocess is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means thatby iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company could notpredict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, theCompany created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likelypath the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method,specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR.Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rateswith maturities consistent with the performance period, 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 TSR portion of the PSUs: For the Year Ended December 31, 2018Expected term of award (in years)3Risk-free interest rate2.76%Expected daily volatility2.6%During the Current Successor Period, the Company recognized compensation expense for the PSUs of $0.6 million. The fair value of the PSUsgranted during the Current Successor Period was $1.8 million. As of December 31, 2018, unrecognized compensation cost was $1.2 million and will beamortized through 2020.A summary of the status and activity of performance stock units is presented below: Performance Stock Units Weighted-AverageGrant-DateFair Value Non-vested as of December 31, 2017— $—Granted(1)59,641 $29.92Forfeited(5,952) $29.92Non-vested as of December 31, 201853,689 $29.92______________________________(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 times the number of units awarded, depending onthe level of satisfaction of the performance condition.96Table of ContentsStock OptionsThe 2017 LTIP, established by the pre-emergence Board, allows for the issuance of stock options to the Company's employees at the sole discretionof the Board of Directors. Options expire ten years from the grant date unless otherwise determined by the Board of Directors. Compensation expense on thestock options are recognized as general and administrative expense over the vesting period of the award.There were no stock options granted during the Current Successor Period. Total expense recorded for stock options for the Current and 2017Successor Periods was $1.4 million and $3.7 million, respectively. The fair value of the stock options granted during the 2017 Successor Period was $6.8million. As of December 31, 2018, unrecognized compensation cost was $0.8 million and will be amortized through 2020.Stock options were valued using a Black-Scholes Model using the following assumptions: For the Year EndedDecember 31, 2017Expected volatility52.1%Expected dividends—%Expected term (years)6.0Risk-free interest rate1.96%Expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expectedlife assumption on the grant date. The risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining termequal to the expected term of the awards. The Company’s expected life of stock option awards is derived from the midpoint of the average vesting time andcontractual term of the awards.A summary of the status and activity of non-vested stock options is presented below: Stock Options Weighted-AverageExercise Price Weighted-AverageRemaining ContractualTerm (in years) Aggregate Intrinsic Value(in thousands)Outstanding at beginning of Current Successor Period— $— — $—Granted389,102 34.36 — $—Exercised— — — $—Forfeited(191,831) 34.36 9.3 $—Outstanding as of December 31, 2017197,271 $34.36 9.3 $—Granted— — — $—Exercised(32,037) 34.36 — $—Forfeited(32,425) 34.36 — $—Outstanding as of December 31, 2018132,809 $34.36 6.7 $—Options outstanding and exercisable as of December 31, 201861,880 $34.36 4.8 $—Predecessor Long Term Incentive PlanThe Company’s Predecessor Long Term Incentive Plan (the “Predecessor Plan”) had different forms of equity issuances allowed under it, includingrestricted stock, performance stock units, and long term incentive plan units (“predecessor awards”), as further described in this section. Upon emergence frombankruptcy, the Company's predecessor awards were canceled.Restricted Stock under the Predecessor Long Term Incentive Plan The Company granted shares of restricted stock to directors, eligible employees, and officers under its Predecessor Plan. Each share of restrictedstock represented one share of the Company’s common stock to be released from restriction upon completion of the vesting period. The awards typicallyvested in one-third increments over three years. Each share of restricted stock was entitled to a non-forfeitable dividend, if the Company were to declare one,and has the same voting rights97Table of Contentsas a share of the Company’s common stock. Shares of restricted stock were valued at the closing price of the Company’s common stock on the grant date andwere recognized as general and administrative expense over the vesting period of the award. The Company granted no shares of restricted stock under the Predecessor Plan during the 2017 or 2016 Predecessor Periods. The Company granted568,832 shares of restricted stock under the Predecessor Plan to certain employees during 2015. The fair value of the restricted stock granted in 2015 was$13.8 million. The Company recognized compensation expense of $1.2 million and $6.1 million for the 2017 and 2016 Predecessor Periods, respectively.There were no shares of restricted stock granted to non-employee directors under the Predecessor Plan during the 2017 Predecessor Period. Duringthe year ended December 31, 2016, the Company issued 113,044 shares of restricted common stock under the Predecessor Plan to its non-employee directors.The Company recognized compensation expense of $0.04 million and $0.7 million for the 2017 and 2016 Predecessor Periods, respectively. These awardsvested approximately one year after issuance.A summary of the status and activity of non-vested restricted stock is presented below: Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 RestrictedStock Weighted-AverageGrant-DateFair Value RestrictedStock Weighted-AverageGrant-DateFair Value Non-vested at beginning of year368,887 $19.45 731,818 $29.47Granted— $— 113,044 $0.98Vested(111,996) $32.22 (355,498) $31.68Forfeited(5,134) $29.55 (120,477) $27.34 Canceled(251,757) $13.08 — $—Non-vested at end of period— $— 368,887 $19.45The Company recorded no excess tax benefits for the 2017 and 2016 Predecessor Periods.Performance Stock Units under the Predecessor Long Term Incentive PlanThe Company granted PSUs to certain officers under its Predecessor Plan. The number of shares of the Company’s common stock that may be issuedto settle PSUs ranged from zero to two times the number of PSUs awarded. PSUs were determined at the end of each annual measurement period over thecourse of the three-year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equalto 200% of the target number of PSUs may be earned during the performance cycle), although no stock was actually awarded to the participant until the endof the entire three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The performancecriteria for the PSUs is based on a comparison of the Company’s TSR for the measurement period compared with the TSRs of a group of peer companies forthe same measurement period. Compensation expense associated with PSUs was recognized as general and administrative expense over the measurementperiod. The TSR for the Company and each of the peer companies was determined by dividing (A)(i) the average share price for the last 30 trading days of theapplicable measuring period, minus (ii) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuringperiod, by (B) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period. The number of earnedshares of the Company's common stock was calculated based on which quartile its TSR percentage ranks as of the end of the annual measurement periodrelative to the other companies in the comparator group. 98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 could not predict withcertainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Companycreated multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path thestock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specificallythe Monte Carlo Model, was 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 Company granted no PSUs under the Predecessor Plan during the 2017 and 2016 Predecessor Periods. The Company recognized compensationexpense for the Predecessor Company of $0.5 million and $1.8 million for the 2017 and 2016 Predecessor Periods, respectively, relating to the 2015 PSUs. A summary of the status and activity of PSUs is presented in the following table: Predecessor January 1, 2017 through April 28,2017 For the Year Ended December 31,2016 PSUWeighted-AverageGrant-DateFair Value PSU Weighted-AverageGrant-DateFair ValueNon-vested at beginning of year(1)21,538 $33.31 114,833 $35.27Granted(1)— $— — $—Vested(1)— $— (59,725) $36.61Forfeited(1)— $— (33,570) $35.55Canceled(1)(21,538) $33.31 — $—Non-vested at end of period(1)— $— 21,538 $33.31___________________________(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 times the number of PSUs awarded, dependingon the level of satisfaction of the performance condition.During the 2017 Predecessor Period the third tranche of the 2015 awards had a zero-times multiplier, in accordance with the terms of the respectivePSU awards. During the year ended December 31, 2016, the third tranche of the 2014 awards and the second tranche of the 2015 awards had a zero-timesmultiplier, in accordance with the terms of the respective PSU awards.Predecessor Long Term Incentive Plan UnitsThe Company granted no Predecessor LTIP units (“units”) during the 2017 Predecessor Period. During the year end December 31, 2016, theCompany granted 2,958,558 units for a total fair value $2.9 million, that settled in shares of the Company's common stock upon vesting. The units wouldvest in one-third increments over three years. The units contained a share price cap of $26 that incrementally decreases the number of shares of the Company'scommon stock that will be released upon vesting if the Company's common stock were to exceed the share price cap.Total expense recorded for the units for the Predecessor Company for the 2017 and 2016 Predecessor Periods was $0.4 million and $0.9 million,respectively.99Table of ContentsA summary of the status and activity of non-vested units for the 2017 and 2016 Predecessor Periods is presented below. Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 LTIP Units Weighted-AverageGrant-DateFair Value LTIP Units Weighted-AverageGrant-DateFair Value Non-vested at beginning of year2,443,402 $0.99 — $—Granted— $— 2,958,558 $0.99Vested(767,848) $0.98 — $—Forfeited(126,616) $0.98 (515,156) $0.98Canceled(1,548,938) $0.99 — $—Non-vested at end of period— $— 2,443,402 $0.99401(k) PlanThe Company has a defined contribution retirement plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of1974. The 401(k) Plan allows eligible employees to contribute up to the contribution limits established under the IRC. The Company matches eachemployee’s contribution up to six percent of the employee’s base salary. The Company’s matching contributions to the 401(k) Plan were $1.1 million, $0.6million, $0.6 million, and $2.0 million for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and the year ended December 31,2016, 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 basis of assets and liabilities and amounts reported in theCompany’s balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets andliabilities determines the periodic provision for deferred taxes.The provision for income taxes consists of the following (in thousands): Successor Predecessor Year EndedDecember 31,2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April 28,2017 Year EndedDecember 31,2016 Current tax benefit Federal $— $376 $— $—State — — — —Deferred tax benefit — — — —Total income tax benefit $— $376 $— $—100Table of ContentsTemporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred taxliability result from the following components (in thousands): Successor As of December 31, 2018 2017Deferred tax liabilities: Oil and gas properties $52,006 $—Derivative liability 8,527 —Total deferred tax liabilities 60,533 —Deferred tax assets: Federal and state tax net operating loss carryforward 137,567 117,115Oil and gas properties — 1,319Derivative liability — 3,457Reclamation costs 7,251 9,516Stock compensation 1,635 1,419Accrued compensation 1,308 1,285Inventory 1,577 1,529Settlement liabilities — —AMT credit — —State bonus depreciation addback — 1,089Other long-term assets 271 231Total deferred tax assets 149,609 136,960Less: Valuation allowance 89,076 136,960Total deferred tax assets after valuation allowance — —Total non-current net deferred tax liability $— $—The Company has $577.6 million and $470.3 million of net operating loss carryovers for federal income tax purposes as of December 31, 2018 and2017, respectively. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $470.3 million will begin to expire in 2036. Federal netoperating loss carryforwards incurred after December 31, 2017 of $107.3 million have no expiration and can only be used to offset 80% of taxable incomewhen utilized.101Table of ContentsFederal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21%to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences, as follows (in thousands): Successor Predecessor Year EndedDecember 31,2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April 28,2017 Year EndedDecember 31,2016 Federal statutory tax (expense) benefit by applying the statutory rate $35,319 $1,889 $(931) $69,633Decrease (increase) in tax resulting from: State tax expense net of federal benefit 6,556 172 (85) 6,358Prior year true-up (458) — (7,572) —Stock compensation 854 — (1,773) —Permanent differences 61 (715) (35,273) —Rate change (421) (73,956) — —NOL Adjustment 5,973 — — —Other — (642) — (317)Valuation allowance (47,884) 73,628 45,634 (75,674)Total income tax benefit $— $376 $— $—During the year ended December 31, 2018, the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets.There was no deferred income tax benefit or expense in the accompanying statements of operations. The valuation allowance decreased to $89.1 million in2018 due to improvement of operational results. Net operating losses are inherently subject to changes in ownership. The net operating loss adjustment wasderived from the write-off of the Company's Mid-continent tax attributes upon the sale of those assets.During the year ended December 31, 2017, the decrease in tax rate was primarily due to the enactment of the Tax Cuts and Jobs Act (“Tax Act”).There was $0.4 million of current income tax benefits in the accompanying statements of operations due to the AMT payments being refunded as prescribedin the Tax Act. The valuation allowance decreased to $137.0 million in 2017 due to decreased tax rate as mandated by the Tax Act.During the year ended December 31, 2016, the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets.There was no deferred income tax benefit or expense in the accompanying statements of operations. The valuation allowance increased to $256.2 million in2016 due to continued deterioration of our operational results.The Company had no unrecognized tax benefits as of December 31, 2018, 2017, and 2016. 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.102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% for the Predecessor Company and ranges from 5% to 7% for the Successor Company.Upon the Company's emergence from bankruptcy, as discussed in Note 15 - Chapter 11 Proceedings and Emergence and Note 16 - Fresh-StartAccounting, the Company applied fresh-start accounting. This included adjusting the asset retirement obligations based on the estimated fair values at April28, 2017. A roll-forward of the Company’s asset retirement obligation is as follows (in thousands):Balance as of January 1, 2017 (Predecessor)$30,833Liabilities settled (218)Accretion expense 1,045Ending balance as of April 28, 2017 (Predecessor)$31,660 Fair value fresh-start adjustment$(2,599) Beginning balance as of April 29, 2017 (Successor)$29,061Additional liabilities incurred 130Accretion expense 1,370Liabilities settled (780)Revisions to estimate 8,481Ending balance as of December 31, 2017 (Successor)$38,262Additional liabilities incurred 373Accretion expense 1,831Liabilities settled (1,627)Revisions to estimate 1,490Sold properties (10,924)Ending balance as of December 31, 2018 (Successor) 29,405Revisions 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. Revisions to estimates for the year ended December 31, 2018 were primarily aresult of an increase in the credit-adjusted risk-free rate applied at year-end and an increase in the inflation rate on wells that had an asset retirementobligation as of the beginning of the year, offset by a slight decrease in abandonment costs. Revisions to estimates for the 2017 Successor Period were a resultof a decrease in the credit-adjusted risk-free rate applied at year-end, decreased estimated economic well lives, and an increase in abandonment costs.NOTE 12 - FAIR VALUE MEASUREMENTS The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measureassets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price thatwould be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statementestablishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs byrequiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset orliability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’sassumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances.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 103Table of ContentsLevel 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 unobservableFinancial 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.The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31,2018 and 2017 and their classification within the fair value hierarchy: Successor As of December 31, 2018 Level 1 Level 2 Level 3 (in thousands)Derivative assets(1)$— $38,272 $—Derivative liabilities(1)$— $183 $—Asset retirement obligations(2)$— $— $1,490 Successor As of December 31, 2017 Level 1 Level 2 Level 3 (in thousands)Derivative assets(1)$— $494 $—Derivative liabilities(1)$— $14,395 $—Asset retirement obligations(2)$— $— $8,481_______________________________(1)This represents a financial asset or liability that is measured at fair value on a recurring basis.(2)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.DerivativesFair 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 were validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and weredesignated as Level 2 within the valuation hierarchy.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. Proved104Table of Contentsproperties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid pricesreceived from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. Therewere no oil and gas property impairments during the years ended December 31, 2018 and 2017. For the year ended December 31, 2016, the Companyimpaired its oil and gas properties in the Mid-Continent region by $10.0 million, reflecting the difference between their $110.0 million carrying value andtheir $100.0 million fair value. For additional discussion on impairments, please refer to Note 3 - 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. During 2018, the Company incurred its standard annualamortization of $5.3 million on its emergence leases that were not held by production as disclosed in the abandonment and impairment of unprovedproperties line item in the accompanying statements of operations. There were no unproved oil and gas property impairments during the year endedDecember 31, 2017. During the year ended December 31, 2016, the Company impaired non-core acreage in the Wattenberg Field due to lease expirations,which had a carrying value of $187.4 million, to its fair value of $162.7 million, and recognized an impairment of unproved properties of $24.7 million.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 $1.5 million and $8.5 million of asset retirement obligations recorded at fair value as of December 31, 2018and 2017, respectively. Long-term Debt Upon emergence from bankruptcy, the Company's Senior Notes were canceled and the predecessor credit facility was paid in full. The Company'scredit facility approximates fair value as the applicable interest rates are floating. The Company had $50.0 million outstanding under the credit facility as ofDecember 31, 2018. There were no long-term debt amounts outstanding as of December 31, 2017.NOTE 13 - DERIVATIVESThe 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,collar, and put arrangements for oil and gas, and none of the derivative instruments qualify as having hedging relationships.In 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.A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceilingprice, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Companyreceives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment orreceipt occurs. A basis swap arrangement guarantees a price differential from a specified delivery point. The Company receives the difference between the pricedifferential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential andthe stated terms, if the stated terms are greater than the price differential.105Table of ContentsA put option provides the Company the right, but not the obligation, to sell a specified underlying security at a designated price within a specifiedtime frame.As of December 31, 2018, the Company had entered into the following commodity derivative contracts: Crude Oil (NYMEX WTI) Natural Gas (NYMEX Henry Hub) Natural Gas (CIG Basis) Natural Gas (CIG) Bbls/day Weighted Avg. Price perBbl MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu1Q19 Cashless Collar 4,000 $50.88/$63.83 7,600 $2.75/$3.22 — — — —Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 10,000 $2.17Put 500 $55.00 — — — — — —2Q19 Cashless Collar 5,330 $54.42/$67.57 2,505 $2.75/$3.22 — — — —Swap 3,500 $57.84 — — — — 16,703 $2.11Put 500 $55.00 — — — — — —3Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — —Swap 5,000 $59.92 — — — — 20,000 $2.10Put 500 $55.00 — — — — — —4Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — —Swap 5,000 $59.92 — — — — 20,000 $2.10Put 500 $55.00 — — — — — —1Q20 Swap 3,000 $63.48 — — — — — —As of the filing date of this report, the Company had entered into the following commodity derivative contracts: Crude Oil (NYMEX WTI) Natural Gas (NYMEX Henry Hub) Natural Gas (CIG Basis) Natural Gas (CIG) Bbls/day Weighted Avg. Price perBbl MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu MMBtu/day Weighted Avg. Price perMMBtu1Q19 Cashless Collar 4,656 $51.46/$65.40 7,600 $2.75/$3.22 — — — —Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 11,639 $2.20Put 172 $55.00 — — — — — —2Q19 Cashless Collar 6,330 $54.51/$68.74 2,505 $2.75/$3.22 — — — —Swap 3,500 $57.84 — — — — 19,203 $2.15Put — — — — — — — —3Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — —Swap 5,000 $59.92 — — — — 22,500 $2.13Put — — — — — — — —4Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — —Swap 5,000 $59.92 — — — — 22,500 $2.13Put — — — — — — — —1Q20 Swap 3,000 $63.48 — — — — 2,500 $2.40Collar 2,000 $55.00/$62.00 — — — — — —Derivative Assets and Liabilities Fair Value 106Table of ContentsThe Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets andliabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as ofDecember 31, 2018 and 2017 (in thousands): Successor As of December 31, 2018 2017 Balance Sheet Location Fair Value Fair ValueDerivative Assets: Commodity contractsCurrent assets $34,408 $488Commodity contractsNoncurrent assets 3,864 6Derivative Liabilities: Commodity contractsCurrent liabilities (183) (11,423)Commodity contractsLong-term liabilities — (2,972)Total derivative assets (liabilities), net $38,089 $(13,901)The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations (inthousands): Successor Predecessor Year EndedDecember 31,2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April 28,2017 Year EndedDecember 31, 2016Derivative cash settlement gain (loss): Oil contracts $(17,700) $(1,486) $— $18,333Gas contracts (460) 22 — —Total derivative cash settlement gain (loss)(1) $(18,160) $(1,464) $— $18,333 Change in fair value gain (loss) 48,431 (13,901) $— $(29,567) Total derivative gain (loss)(1) $30,271 $(15,365) $— $(11,234)___________________________(1)Total derivative gain (loss) and the derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) lossand derivative cash settlements line items on the accompanying statements of cash flows within the net cash provided by operating activities. NOTE 14 - EARNINGS PER SHARE The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentiallydilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming thatdate was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of theCompany's common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares relatedto PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of theperformance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company'scommon stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that wouldbe exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutiveshares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period.Please refer to Note 9 - Stock-Based Compensation for additional discussion.The RSUs, PSUs, stock options, and warrants of the Company are all non-participating securities, and therefore, the Company uses the treasury stockmethod to calculate earnings per share as shown in the following table (in thousands, except107Table of Contentsper share amounts): Successor Year Ended December31, 2018 April 29, 2017 throughDecember 31, 2017Net income (loss)$168,186 $(5,020) Basic net income (loss) per common share$8.20 $(0.25) Diluted net income (loss) per common share$8.16 $(0.25) Weighted-average shares outstanding - basic20,507 20,427Add: dilutive effect of contingent stock awards96 —Weighted-average shares outstanding - diluted20,603 20,427There were 170,755 shares which were anti-dilutive for the year ended December 31, 2018. The Company's warrants exercise price were in excess ofthe Company's stock price, therefore, they were excluded from the earnings per share calculation.The Company was in a net loss position for the 2017 Successor Period, which made the 375,123 potentially dilutive shares anti-dilutive.The Predecessor Company issued shares of restricted stock, which entitled the holders to receive non-forfeitable dividends if and when thePredecessor Company was to declare a dividend before vesting, thus making the awards participating securities. The awards are included in the calculation ofearnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and unvestedparticipating shareholders and losses to common shareholders only.The Predecessor Company issued units, which represented the right to receive, upon vesting, shares of the Predecessor Company's common stock ona one-to-one basis up to a share price of $26. In the event the price of the Company's common stock were to exceed $26, the number of shares distributedwould be adjusted downward so that the shares distributed would represent a value equivalent to $26 per share. The Predecessor Company issued PSUs, which represented the right to receive, upon settlement of the PSUs, a number of shares of the PredecessorCompany’s common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares relatedto PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of themeasurement period applicable to such PSUs. Please refer to Note 9 - Stock-Based Compensation for additional discussion.108Table of ContentsThe following table sets forth the calculation of income (loss) per basic and diluted shares from net income (loss) for the Predecessor Periods endedApril 28, 2017 and December 31, 2016: Predecessor January 1, 2017 throughApril 28, 2017 Year Ended December31, 2016 (in thousands, except per share amounts)Net income (loss) $2,660 $(198,950)Less: undistributed income to unvested restricted stock 120 —Undistributed income (loss) to common shareholders 2,540 (198,950)Basic net income (loss) per common share $0.05 $(4.04)Diluted net income (loss) per common share $0.05 $(4.04) Weighted-average shares outstanding - basic 49,559 49,268Add: dilutive effect of contingent PSUs 1,412 —Weighted-average shares outstanding - diluted 50,971 49,268The 2017 Predecessor Period had 258,126 anti-dilutive shares. The Company was in a net loss position for the 2016 Predecessor Period, which madethe 519,362 potentially dilutive shares, anti-dilutive. The participating shareholders are not contractually obligated to share in losses, and therefore, theentire net loss is allocated to the outstanding common shareholders.NOTE 15 - CHAPTER 11 PROCEEDINGS AND EMERGENCEOn December 23, 2016, Bonanza Creek Energy, Inc. and its subsidiaries entered into a Restructuring Support Agreement with (i) holders ofapproximately 51% in aggregate principal amount of the Company's 5.75% Senior Notes due 2023 (“5.75% Senior Notes”) and 6.75% Senior Notes due2021 (“6.75% Senior Notes”), collectively (the “Senior Notes”) and (ii) NGL Energy Partners, LP and NGL Crude Logistics, LLC (collectively “NGL”).On January 4, 2017, the Company filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code. The Debtors receivedbankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017.During the bankruptcy proceedings, the Company conducted normal business activities and was authorized to pay and did pay pre-petitionliabilities.In addition, subject to specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrativeactions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, wedid not record interest expense on the Company’s Senior Notes from January 6, 2017, the agreed-upon date, through April 28, 2017. For that period,contractual interest on the Senior Notes totaled $16.0 million.Reorganization On the Effective Date, the Senior Notes and existing common shares of the Company (“existing common shares”) were canceled, and the reorganizedCompany issued: (i) new common stock; (ii) three year warrants (“warrants”); and (iii) rights (the “subscription rights”) to acquire the new common sharesoffered in connection with the rights offering (the “rights offering”).•the Senior Notes aggregate principal amount of $800.0 million, plus $14.9 million of accrued and unpaid pre-petition interest and $51.2 million ofprepayment premiums was settled for 46.6% or 9,481,610 shares of the Company's new common stock;•the Company issued 803,083 or 3.9% of the new common stock to holders of our existing common stock, of which 1.75% was for the ad hoc equitycommittee settlement in exchange for $7.5 million, on terms equivalent to the rights offering;109Table of Contents•the Company issued 10,071,378 shares of new common stock in exchange for $200.0 million relating to the rights offering;•the Company issued 1,650,510 of warrants entitling their holders upon exercise thereof, on a pro rata basis, to 7.5% of the total outstanding newcommon shares at a per share price of $71.23 per warrant; and•the Company reserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan (“LTIP”).Pursuant to the terms of the approved Plan the following transactions were completed on the Effective Date;•the Company paid Silo Energy, LLC (“Silo”) the contract settlement amount of $7.2 million in full;•with respect to the predecessor credit facility, dated March 29, 2011 (the “predecessor credit facility”), principal, accrued interest, and fees of $193.7million were paid in full;•the Company paid $1.6 million for the 2016 Short Term Incentive Plan (“2016 STIP”) to various employees;•the Company funded an escrow account in the amount of $17.2 million for professional service fees attributable to its advisers;•the Company paid $13.8 million for professional services attributable to advisers of third parties involved in the bankruptcy proceedings;•the Company emerged with cash on hand of $70.2 million for operations; and•the Company amended its articles of incorporation and bylaws for the authorization of the new common stock.As confirmed in the Plan, the Company terminated its purchase agreement with Silo on February 1, 2017, and entered into a settlement agreementthat allowed Silo to: (i) retain the $5.0 million adequate assurance deposit maintained, (ii) retain the Company's $8.7 million crude oil revenue receivabledue to the Company for December 2016 production, and (iii) receive additional cash payment of $7.2 million, which was paid on the Effective Date. The$21.0 million settlement is shown in the contract settlement expense line item in the accompanying statements of operations as of December 31, 2016.Board of DirectorsUpon emergence from bankruptcy the Company's Board of Directors was made up of seven individuals, two of which were existing board members,Richard J. Carty and Jeffrey E. Wojahn, and five new board members consisting of Paul Keglevic, Brian Steck, Thomas B. Tyree, Jr., Jack E. Vaughn, andScott D. Vogel were appointed.Executive DepartureOn June 11, 2017, Richard J. Carty resigned as a member of the Board of Directors and left his role as President and Chief Executive Officer of theCompany. In connection with the departure of Mr. Carty, the Board of Directors appointed R. Seth Bullock, a managing director of Alvarez & Marsal, LLC,interim Chief Executive Officer.Effective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greageralso joined the Company's Board of Directors.NOTE 16 - FRESH-START ACCOUNTINGUpon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh-start accounting, pursuant to FASB ASC 852,Reorganizations, and applied the provisions thereof to its financial statements. The Company qualified for fresh-start accounting because: (i) the holders ofexisting voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company; and (ii) the reorganization valueof the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh-startaccounting as of April 28, 2017, when it emerged from bankruptcy protection. Adopting fresh-start accounting results in a new reporting entity for financialreporting purposes with no beginning retained earnings or deficit as of the fresh-start reporting date. The cancellation of all existing shares outstanding onthe Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852.Reorganization Value110Table of ContentsUnder fresh-start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximatethe amount a willing buyer would pay for the assets immediately after restructuring. Under application of fresh-start accounting, the Company allocated thereorganization value to its individual assets based on their estimated fair values.The Company's reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of anentity’s long-term debt, other interest bearing liabilities, and shareholders’ equity, less total cash and cash equivalents. In support of the Plan, the enterprisevalue of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $570.0 million to $680.0 million. Based on theestimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to beapproximately $643.0 million. This valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserveinformation prepared by the Company's internal reserve engineers, internal development plans and schedules, other internal financial information andprojections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics.The Company's principal assets are its oil and gas properties. The Company determined the fair value of its oil and gas properties based on thediscounted cash flows expected to be generated from these assets segregated into geographic regions. The computations were based on market conditions andreserves in place as of the Effective Date. Discounted cash flow models were generated using the estimated future revenues and development and operatingcosts for all developed wells and undeveloped locations comprising our proved reserves. The proved locations were limited to wells expected to be drilled inthe Company's five year plan. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five yearforward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. The prices werefurther adjusted for typical differentials realized by the Company for the location and product quality. Wattenberg Field oil differential estimates were basedon the new NGL purchase agreement that was confirmed as part of the Plan. Development costs were based on recent bids received by the Company and theoperating costs were based on actual costs, and both were adjusted by the same inflation rate used for revenues. The discounted cash flow models alsoincluded estimates not typically included in proved reserves, such as an industry standard general and administrative expense and income tax expense. Dueto the limited drilling plans that we had in place, proved undeveloped locations were risked within industry standards.The risk-adjusted after-tax cash flows were discounted at a rate of 11.0%. This rate was determined from a weighted-average cost of capitalcomputation, which utilized a blended expected cost of debt and expected returns on equity for similar industry participants.From this analysis the Company concluded the fair value of its proved, probable, and possible reserves was $397.3 million, $146.8 million, and$31.7 million, respectively, as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and determined that the fair value of itsprobable and possible reserves appropriately capture the fair value of its undeveloped leasehold acreage.The Company performed an analysis of its Rocky Mountain Infrastructure, LLC (“RMI”) assets using a replacement cost method which estimatedthe assets' replacement cost (for new assets), less any depreciation, physical deterioration, or obsolescence, resulting in a fair value of $103.1 million.The Company follows the lower of cost or net realizable value when valuing inventory of oilfield equipment. The valuation of the inventory ofoilfield equipment as of the Effective Date did not yield a material difference from the Company's carrying value immediately prior to emergence frombankruptcy; as such, there was no valuation adjustment recorded.The valuation of the Company's other property and equipment as of the Effective Date did not yield a material difference from the PredecessorCompany's net book value; as such there was no valuation adjustment recorded.Our liabilities on the Effective Date include working capital liabilities and asset retirement obligations. Our working capital liabilities are ordinarycourse obligations, and their carrying amounts approximate their fair values. The asset retirement obligation was reset using a revised credit-adjusted risk-freerate and known attributes as of the Effective Date, resulting in a $29.1 million obligation.In conjunction with the Company's emergence from bankruptcy, the Company issued 1,650,510 warrants to existing equity holders. The fair valueof $4.1 million was estimated using a Black-Scholes pricing model. The model used the following assumptions; an expected volatility of 40%, a risk-freeinterest rate of 1.44%, a stock price of $34.36, a strike price of $71.23, and an expiration date of 3 years.111Table of ContentsThe following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (inthousands, except per share amounts):Enterprise Value$642,999Plus: Cash and cash equivalents70,183Less: Interest bearing liabilities(29,061)Less: Fair value of warrants(4,081)Fair value of Successor common stock$680,040 Shares outstanding at April 28, 201720,356 Per share value$33.41The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands):Enterprise Value$642,999Plus: Cash and cash equivalents70,183Plus: Working capital liabilities63,871Plus: Other long-term liabilities17,919Reorganization value of Successor assets$794,972Successor Condensed Consolidated Balance SheetThe adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactionscontemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as estimated fair value adjustments as a result of the adoption offresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine estimated fair valuesor other amounts of assets and liabilities, as well as significant assumptions. Predecessor Company ReorganizationAdjustments Fresh-Start Adjustments Successor Company (in thousands, except share amounts)ASSETS Current Assets: Cash and cash equivalents$96,286 $(26,103)(1)$— $70,183Accounts receivable: Oil and gas sales24,876 — — 24,876Joint interest and other3,028 — — 3,028Prepaid expenses and other4,952 — — 4,952Inventory of oilfield equipment4,218 — — 4,218Total current assets133,360 (26,103) — 107,257Property and equipment (successful effortsmethod): Proved properties2,531,834 — (2,031,373)(6)500,461Less: accumulated depreciation, depletionand amortization(1,720,736) — 1,720,736(6)—Total proved properties, net811,098 — (310,637) 500,461Unproved properties163,781 — 14,679(6)178,460Wells in progress18,002 — (18,002)(7)—Other property and equipment, net6,056 — — 6,056Total property and equipment, net998,937 — (313,960) 684,977112Table of ContentsOther noncurrent assets2,738 — — 2,738Total assets$1,135,035 $(26,103) $(313,960) $794,972 LIABILITIES AND STOCKHOLDERS'SEQUITY Current liabilities: Accounts payable and accrued expenses$72,635 $(33,701)(2)$— $38,934Oil and gas revenue distribution payable24,937 — — 24,937Predecessor credit facility - current portion191,667 (191,667)(3)— —Total current liabilities289,239 (225,368) — 63,871Long-term liabilities: Ad valorem taxes17,919 — — 17,919Asset retirement obligations for oil and gasproperties31,660 — (2,599)(8)29,061Liabilities subject to compromise873,292 (873,292)(4)— —Total liabilities$1,212,110 $(1,098,660) $(2,599) $110,851Stockholders' equity: Predecessor preferred stock— — — —Predecessor common stock49 — (49)(9)—Additional paid in capital816,679 — (816,679)(9)—Successor common stock— 204(5)— 204Successor warrants— 4,081(5)— 4,081Additional paid-in capital— 679,836(5)— 679,836Retained deficit(893,803) 388,436(4)505,367(10)—Total stockholders' equity(77,075) 1,072,557 (311,361) 684,121Total liabilities and stockholders' equity$1,135,035 $(26,103) $(313,960) $794,972Reorganization Adjustments(1) The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands):Sources: Proceeds from rights offering$200,000Proceeds from ad hoc equity committee7,500Total sources$207,500Uses and transfers: Payment on predecessor credit facility (principal, interest and fees)$(193,729)Payment and funding of escrow account related to professional fees(17,193)Payment of professional fees and other(13,831)Payment of Silo contract settlement and other(7,228)Payment of remaining 2016 STIP(1,622)Total uses and transfers$(233,603) Total net sources, uses and transfers$(26,103)(2) The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (inthousands):113Table of ContentsAccounts payable and accrued expenses: Accrued 2016 STIP payment$(1,574)Escrow account funding(17,193)Professional fees and other(13,831)Accrued unpaid interest on predecessor credit facility(1,103)Total accounts payable and accrued expenses settled$(33,701)(3) Represents the payment in full of the predecessor credit facility on the Effective Date.(4) On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled asfollows in accordance with the Plan (in thousands):Senior Notes$800,000Accrued interest on Senior Notes (pre-petition)14,879Make-whole payment on Senior Notes51,185Silo contract settlement accrual7,228Total liabilities subject to compromise of the predecessor873,292 Rights offering200,000Fair value of equity issued to creditors, excluding equity issued to existing equity holders(653,212)Payment of Silo contract settlement(7,228)Gain on settlement of liabilities subject to compromise412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP(1,007) Total reorganization items at emergence$411,845 Issuance of warrants to existing shareholders$(4,081)Proceeds from ad hoc equity committee7,500Issuance of shares to existing shareholders(26,828)Total reorganization adjustments to retained deficit$388,436(5) Represents the fair value of 20,356,071 shares of new common stock and 1,650,510 warrants issued upon emergence from bankruptcy on the EffectiveDate.Fresh-Start Adjustments(6) Fair value adjustments to proved and unproved oil and natural gas properties. A combination of the market and income approach were utilized to performvaluations. Included in this line items were adjustments to the fully-owned subsidiary, Rocky Mountain Infrastructure, LLC. Lastly, the accumulateddepreciation was reset to zero in accordance with fresh-start accounting.(7) Represents the reset of wells in progress with fair valuation of the associated reserves in proved property.(8) Upon application of fresh-start accounting and due to the Company’s emergence with no debt, the Company revalued its asset retirement obligationsbased upon comparable companies’ credit-adjusted risk-free rates in accordance with ASC 410 - Asset Retirement and Environmental Obligations.(9) Cancellation of Predecessor Company’s common stock and additional paid-in capital.(10) Adjustment to reset retained deficit to zero.Reorganization Items, NetReorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan, and areclassified as Reorganization items, net in our statement of operations. The following table summarizes reorganization items recorded in the CurrentPredecessor Period (in thousands):114Table of ContentsGain on settlement of liabilities subject to compromise$412,852Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP(1,007)Fresh-start valuation adjustments(311,361)Legal and professional fees and expenses(34,335)Write-off of debt issuance and premium costs(6,156)Make-whole payment on Senior Notes(51,185)Total reorganization items, net$8,808NOTE 17 - DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)The Company’s oil and natural gas activities are located entirely within the United States. Costs incurred in oil and natural gas producing activitiesare as follows (in thousands): Successor Predecessor Year EndedDecember 31,2018 April 29, 2017throughDecember 31,2017 January 1, 2017through April 28,2017 Year EndedDecember 31,2016Acquisition(1) $2,861 $5,383 $445 $97Development(2)(3) 304,197 106,449 10,780 31,209Exploration 294 3,671 769 74Total(4) $307,352 $115,503 $11,994 $31,380_________________________(1)Acquisition costs for unproved properties for the year ended December 31, 2018, 2017 Successor Period, 2017 Predecessor Period, and 2016 PredecessorPeriod were $2.5 million, $5.4 million, $0.4 million, and $0.1 million, respectively. There was $0.4 million in acquisition costs for proved properties forthe year ended December 31, 2018 and no acquisition costs for proved properties for the 2017 Successor Period, 2017 Predecessor Period, and 2016Predecessor Period.(2)Development costs include workover costs of $5.6 million, $4.3 million, $1.8 million, and $6.0 million charged to lease operating expense for theCurrent Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively.(3)Includes amounts relating to asset retirement obligations of $(9.0) million, $8.3 million, $3.1 million, and $2.4 million for the Current Successor Period,2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively.Suspended Well CostsThe Company did not incur any exploratory well costs during the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and2016 Predecessor Period.ReservesThe proved reserve estimates at December 31, 2018 and 2017 were prepared by NSAI, our third party independent reserve engineers. The provedreserve estimate at December 31, 2016 was internally generated with an audit performed 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.115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, 2018, 2017, and 2016 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl)Balance-December 31, 2015 57.393 144.227 19.918Extensions, discoveries and infills(1) 6.133 15.128 2.142Production (4.310) (11.907) (1.491)Sales of minerals in place (0.100) (0.343) (0.035)Revisions to previous estimates(3) (9.020) (9.060) (2.987)Balance-December 31, 2016 50.096 138.045 17.547Extensions, discoveries and infills(1) 8.470 22.212 3.376Production (3.081) (9.010) (1.136)Revisions to previous estimates(3) (2.557) 6.422 3.028Balance-December 31, 2017 52.928 157.669 22.815Extensions, discoveries and infills(1) 18.390 31.471 5.197Production (3.841) (8.567) (1.140)Sales of minerals in place (6.236) (20.534) (1.499)Removed from capital program(2) (1.442) (3.246) (0.544)Revisions to previous estimates(3) 4.555 8.219 0.101Balance-December 31, 2018 64.354 165.012 24.930 Proved developed reserves: December 31, 2016 26.313 85.972 9.951December 31, 2017 25.785 92.718 12.702December 31, 2018 23.725 79.630 11.703Proved undeveloped reserves: December 31, 2016 23.783 52.073 7.596December 31, 2017 27.143 64.951 10.113December 31, 2018 40.629 85.382 13.227________________________(1)At December 31, 2018, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 28,832 MBoe.At December 31, 2017, horizontal development in the Wattenberg Field resulted in additions in extensions and discoveries of 15,548 MBoe.At December 31, 2016, horizontal development in the Wattenberg Field resulted in additions of 1,632 MBoe, and infill down-spacing within theWattenberg Field resulted in 9,164 MBoe to the additions, extensions, and infills category.(2)As of December 31, 2018, proved undeveloped reserves were reduced by 2,527 MBoe due to the removal of proved undeveloped locations from our five-year drilling program.(3)As of December 31, 2018, the Company revised its proved reserves upward by 6,026 MBoe. The commodity prices at December 31, 2018 increased to$65.56 per Bbl WTI and $3.10 per MMBtu HH from $51.34 per Bbl WTI and $2.98 per MMBtu HH at December 31, 2017, resulting in positive revisionsof 2,333 MBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments of 1,536 MBoe. There were net positive engineeringrevisions of 2,163 MBoe.116Table of ContentsAs of December 31, 2017, the Company revised its proved reserves upward by 1,542 MBoe. The commodity prices at December 31, 2017 increased to$51.34 per Bbl WTI and $2.98 per MMBtu HH from $42.75 per Bbl WTI and $2.48 per MMBtu HH at December 31, 2016, resulting in positive revisionsof 5,405 MBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments (net of price increases) of 1,672 MBoe, of which1,370 MBoe relate to operations in the Wattenberg Field. The Company also had positive other engineering revisions of 2,042 MBoe, offset by PUDdemotions of 7,577 MBoe.As of December 31, 2016, the Company revised its proved reserves downward by 13,517 MBoe. The commodity prices at December 31, 2016 decreasedto $42.75 per Bbl WTI and $2.48 per MMBtu HH from $50.28 per Bbl WTI and $2.59 per MMBtu HH at December 31, 2015. The negative effects ofcommodity price reductions on reserves were offset by lower cost estimates to drill and complete future development locations in the Wattenberg Fieldalong with lower operating cost estimates across the Company's operations, to reflect a positive reserves adjustment (net of price reductions) of 4,652MBoe. Also, all future proved undeveloped locations in the Mid-Continent region were demoted to non-proved reserves resulting in a negative revisionof 7,761 MBoe. In the Wattenberg Field, certain proved undeveloped locations totaling 8,611 MBoe were demoted due to their not being centric tocurrent infrastructure. The Company also had negative other engineering revisions of 1,797 MBoe in 2016.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.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, 2018 2017 2016(in thousands) Future cash flows $4,742,180 $3,307,868 $2,424,415Future production costs (1,585,032) (1,490,091) (1,365,765)Future development costs (925,640) (622,344) (468,804)Future income tax expense — — —Future net cash flows 2,231,508 1,195,433 589,84610% annual discount for estimated timing of cash flows (1,276,528) (596,935) (312,891)Standardized measure of discounted future net cash flows $954,980 $598,498 $276,955Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end.117Table of ContentsThe 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, 2018 2017 2016(in thousands) Beginning of period $598,498 $276,955 $327,816Sale of oil and gas produced, net of production costs (204,566) (125,992) (123,494)Net changes in prices and production costs 365,952 282,112 (126,536)Extensions, discoveries and improved recoveries 153,691 103,937 22,800Development costs incurred 127,788 24,121 19,701Changes in estimated development cost (52,260) 2,122 281,062Purchases of minerals in place — — —Sales of minerals in place (115,742) — 16Revisions of previous quantity estimates 12,341 14,119 (182,938)Net change in income taxes — —Accretion of discount 59,850 27,696 32,782Changes in production rates and other 9,428 (6,572) 25,746End of period $954,980 $598,498 $276,955The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2018, 2017,and 2016 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, 2018 2017 2016Oil (per Bbl) $59.29 $46.76 $38.42Gas (per Mcf) $2.28 $2.45 $2.07Natural gas liquids (per Bbl) $22.06 $19.57 $12.12118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, 2018 and 2017 (in thousands, except pershare data): Successor Three Months Ended2018 March 31 June 30 September 30 December 31Oil and gas sales $64,193 $71,872 $74,380 $66,213Operating profit(1) $35,042 $40,014 $43,959 $41,416Net Income $13,870 $4,859 $43,363 $106,094Basic net income per common share $0.68 $0.24 $2.11 $5.16Diluted net income per common share $0.68 $0.24 $2.10 $5.15 Predecessor Successor Three MonthsEnded March 31,2017 April 1, 2017through April28, 2017 April 29, 2017through June 30,2017 Three MonthsEnded September30, 2017 Three MonthsEnded December31, 20172017 Oil and gas sales $52,559 $16,030 $28,114 $45,232 $50,189Operating profit(1) 14,398 3,786 12,955 22,540 22,935Net income (loss) (94,276) 96,936 (3,580) 4,328 (5,768)Basic net income (loss) per common share $(1.91) $1.88 $(0.18) $0.21 $(0.28)Diluted net income (loss) per common share $(1.91) $1.85 $(0.18) $0.21 $(0.28)________________________(1)Oil and gas sales less lease operating expense, gas plant and midstream operating expense, gathering, transportation, and processing, severance and advalorem taxes, depreciation, and depletion and amortization.Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.As disclosed in our Current Report on Form 8-K, filed on April 19, 2017, we engaged Grant Thornton LLP (“Grant Thornton”) on April 13, 2017 asthe Company’s new independent registered public accounting firm to audit the Company’s financial statements for the fiscal year ending December 31, 2017,and dismissed Hein & Associates LLP (“Hein”) as the Company’s independent registered accounting firm. The decision to change the Company’sindependent registered accounting firm from Hein to Grant Thornton was approved by the Audit Committee of the Board of Directors of the Company.During the fiscal years ended December 31, 2016 and December 31, 2015, and through April 13, 2017, there were no disagreements with Hein onany matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, that if not resolved to the satisfaction ofHein, would have caused Hein to make reference thereto in its reports on the Company’s financial statements for such years.During the fiscal years ended December 31, 2016 and 2015, and the subsequent interim period through April 13, 2017, there were no “reportableevents” (as that term is defined in Item 304(a)(1)(v) of Regulation S-K). 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, 2018. 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 internal119Table of Contentsaudit function, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as ofDecember 31, 2018, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures wereeffective 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 process designed under the supervision of the Company’s ChiefExecutive Officer and Principal Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation ofconsolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Because of itsinherent limitations, internal control over financial reporting may not detect or prevent misstatements. Also, projections of any evaluation of theeffectiveness 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 processes may deteriorate.As of December 31, 2018, 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, 2018, based on those criteria. Management included in its assessment of internal control over financial reporting allconsolidated entities.Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements included in this AnnualReport on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2018, which isincluded 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, 2018 that materially affected, or are reasonably likely to materially affect, our internal controlover financial reporting.120Table of ContentsReport of Independent Registered Accounting FirmBoard of Directors and StockholdersBonanza Creek Energy, Inc.Opinion on internal control over financial reportingWe have audited the internal control over financial reporting of Bonanza Creek Energy, Inc. (a Delaware Company) and subsidiaries (the “Company”) as ofDecember 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations ofthe Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting asof December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidatedfinancial statements of the Company as of and for the year ended December 31, 2018 and our report dated February 27, 2019 expressed an unqualifiedopinion on those financial statements.Basis for opinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Ourresponsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operatingeffectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. Webelieve that our audit provides a reasonable basis for our opinion.Definition and limitations of internal control over financial reportingA 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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 27, 2019121Table of ContentsItem 9B. Other Information.None.122Table of ContentsPART IIIItem 10. Directors, Executive Officers, and Corporate Governance.The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after the end of the fiscal yearended December 31, 2018.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 will be incorporated by reference in a future filing with the SEC within 120 days after the end of the fiscal yearended December 31, 2018.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after the end of the fiscal yearended December 31, 2018.Item 13. Certain Relationships and Related Transaction and Director Independence.The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after the end of the fiscal yearended December 31, 2018.Item 14. Principal Accounting Fees and Services.The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after the end of the fiscal yearended December 31, 2018.123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.124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/ Eric T. Greager Eric T. Greager,President and Chief Executive Officer(principal executive officer) February 27, 2019KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Eric T. Greager, Brant DeMuth,Cyrus D. Marter IV, and Sandi K. Garbiso and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act withor 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 or allamendments 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.125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 27, 2019By:/s/ Eric T. Greager Eric T. Greager,President and Chief Executive Officer(principal executive officer)Date:February 27, 2019By:/s/ Brant DeMuth Brant DeMuth,Executive Vice President and Chief Financial Officer (principalfinancial officer)Date:February 27, 2019By:/s/ Sandi K. Garbiso Sandi K. Garbiso,Vice President and Chief Accounting Officer (principal accounting officer)Date:February 27, 2019By:/s/ Jack E. Vaughn Jack E. Vaughn,Chairman of the BoardDate:February 27, 2019By:/s/ Paul Keglevic Paul Keglevic,DirectorDate:February 27, 2019By:/s/ Brian Steck Brian Steck,DirectorDate:February 27, 2019By:/s/ Thomas B. Tyree, Jr. Thomas B. Tyree, Jr.,DirectorDate:February 27, 2019By:/s/ Scott D. Vogel Scott D. Vogel,DirectorDate:February 27, 2019By:/s/ Jeffrey E. Wojahn Jeffrey E. Wojahn,Director126Table of ContentsINDEX TO EXHIBITSExhibitNumberDescription2.1Order Confirming Debtors’ Third Amended Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code onApril 7, 2017 (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 7,2017)2.2Debtors’ Third Amended Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (incorporated byreference to Exhibit 2.2 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 7, 2017)2.3Agreement and Plan of Merger, dated as of November 14, 2017, by and among Bonanza Creek Energy, Inc., SandRidge Energy, Inc.and Brook Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-Kfiled on November 15, 2017)3.1Third Amended and Restated Certificate of Incorporation of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.1 toBonanza Creek Energy, Inc.’s Registration Statement on Form 8-A filed on April 28, 2017)3.2Fourth Amended and Restated Bylaws of Bonanza Creek Energy, Inc. (incorporated by reference to Exhibit 3.2 to Bonanza CreekEnergy, Inc.’s Registration Statement on Form 8-A filed on April 28, 2017).10.1Restructuring Support Agreement, dated as of December 23, 2016 (incorporated by reference to Exhibit 10.1 to Bonanza CreekEnergy, Inc.’s Current Report on Form 8-K filed on December 23, 2016)10.2Backstop Commitment Agreement, dated as of December 23, 2016 (incorporated by reference to Exhibit 10.2 to Bonanza CreekEnergy, Inc.’s Current Report on Form 8-K filed on December 23, 2016)10.3Stipulation dated February 1, 2017 among the Debtors, the Ad Hoc Noteholder Group and Silo (incorporated by reference to Exhibit10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on February 3, 2017)10.4Restructuring Support and Lock-Up Agreement, dated as of February 16, 2017, among the Debtors and the RBL Lenders(incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on March 16, 2017)10.5Amended and Restated Credit Agreement dated as of April 28, 2017, among Bonanza Creek Energy, Inc., as borrower, the lendersparty thereto and KeyBank National Association, as administrative agent and as issuing lender (incorporated by reference to Exhibit10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.6Warrant Agreement dated as of April 28, 2017, among Bonanza Creek Energy, Inc. and Broadridge Investor CommunicationSolutions, Inc. as warrant agent (incorporated by reference to Exhibit 10.2 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.7Termination Agreement, dated as of December 28, 2017, by and among Bonanza Creek Creek Energy, Inc., SandRidge Energy, Inc.and Brook Merger Sub, Inc. (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K filed on December 28,2017)10.8*Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Bonanza Creek Energy,Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.9*Form of Restricted Stock Unit Agreement under the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan (incorporated byreference to Exhibit 10.4 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.10*Form of Non-Qualified Stock Option Agreement under the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan (incorporatedby reference to Exhibit 10.5 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.11*Bonanza Creek Energy, Inc. Third Amended and Restated Executive Change in Control and Severance Plan (incorporated byreference to Exhibit 10.6 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.12*Bonanza Creek Energy, Inc. Fourth Amended and Restated Executive Change in Control and Severance Plan (incorporated byreference to Exhibit 10.2 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 12, 2017)10.13*Form of Indemnification Agreement between Bonanza Creek Energy, Inc. and the directors and executive officers of Bonanza CreekEnergy, Inc (incorporated by reference to Exhibit 10.7 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28,2017)10.14*Separation and General Release Agreement dated as of June 11, 2017, by and between Bonanza Creek Energy, Inc. and Richard J.Carty (incorporated by reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on June 12, 2017)127Table of Contents10.15*Form of Separation and General Release Agreement, by and between Bonanza Creek Energy, Inc. and Wade E. Jaques (incorporatedby reference to Exhibit 10.1 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on August 4, 2017)10.16*Employment Letter Agreement dated November 6, 2017 between Bonanza Creek Energy, Inc. and Sandra Garbiso (incorporated byreference to Exhibit 10.2 of the Quarterly Report on Form 10 Q filed on November 9, 2017)10.17*Form of Employment Letter Agreement (incorporated by reference to Exhibit 10.2 of the Current Report on Form 8‑K filed onMarch 29, 2013)10.18*Amendment No. 1 and Consent, dated as of December 22, 2017, to Amended and Restated Credit Agreement dated as of April 28,2017 among Bonanza Creek Energy, Inc., as borrower, the lender parties thereto and KeyBank National Association, as administrativeagent and as issuing lender.10.19*Amendment No. 2, dated as of February 2, 2018, to Amended and Restated Credit Agreement dated as of April 28, 2017 amongBonanza Creek Energy, Inc., as borrower, the lender parties thereto and KeyBank National Association, as administrative agent and asissuing lender10.20*Amendment No. 3, dated as of May 31, 2018, to Amended and Restated Credit Agreement dated as of April 28, 2017 among BonanzaCreek Energy, Inc., as borrower, the lender parties thereto and KeyBank National Association, as administrative agent and as issuinglender10.21*Form of Restricted Stock Unit Agreement under the Bonanza Creek Energy, Inc. 2017 Long Term Incentive Plan (incorporated byreference to Exhibit 10.4 to Bonanza Creek Energy, Inc.’s Current Report on Form 8-K filed on April 28, 2017)10.22*Credit Agreement, dated as of December 7, 2018, among Bonanza Creek Energy, In.c as borrower, the lenders party thereto andJPMorgan Chase Bank, N.A., as administrative agent and an issuing bank (incorporated by reference to Exhibit 10.1 to BonanzaCreek Energy, Inc.'s Current Report on From 8-K filed on December 10, 2018)21.1†List of subsidiaries23.1†Consent of Grant Thornton LLP23.2†Consent of Hein & Associates LLP23.3†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, 2018101†The following material from the Bonanza Creek Energy, Inc. Annual Report on Form 10‑K for the year ended December 31, 2017 (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 herewith128Exhibit 21.1Subsidiaries of Bonanza Creek Energy, Inc., a Delaware corporationBonanza Creek Energy Operating Company, 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 have issued our reports dated February 27, 2019 with respect to the consolidated financial statements and internal control over financial reportingincluded in the Annual Report of Bonanza Creek Energy, Inc. on Form 10-K for the year ended December 31, 2018. We consent to the incorporation byreference of said reports in the Registration Statements of Bonanza Creek Energy, Inc. on Forms S-8 (File No. 333-229431 and File No. 333-217545)./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 27, 2019Exhibit 23.2CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in the Registration Statement on Form S-8 (File Nos. 333-217545 and 333-229431) of Bonanza Creek Energy,Inc. of our report dated March 15, 2017, relating to our audit of the consolidated financial statements of Bonanza Creek Energy, Inc., appearing in the AnnualReport on Form 10-K of Bonanza Creek Energy, Inc. for the year ended December 31, 2018.Our report dated March 15, 2017, contains an explanatory paragraph that states that the Company suffered a significant deterioration in liquidity during2016, and filed for bankruptcy under Chapter 11 of the Bankruptcy Code on January 4, 2017, which raises substantial doubt about the Company’s ability tocontinue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty./s/ Hein & Associates LLPDenver, ColoradoFebruary 27, 2019Exhibit 23.3CONSENT 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, 2018. We further consent to the incorporation by reference thereof into Bonanza Creek Energy, Inc.'sRegistration Statements on Form S-8 (Registration Nos. 333-217545 and 333-229431). NETHERLAND, SEWELL & ASSOCIATES, INC. By:/s/ C.H. (Scott) Rees III C.H. (Scott) Rees III, P.E. Chairman and Chief Executive OfficerDallas, Texas February 27, 2019 Exhibit 31.1CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a‑ 14(a)I, Eric T. Greager, certify that:1.I have reviewed this Annual Report on Form 10‑K for the year ended December 31, 2018 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 27, 2019 /s/ Eric T. Greager Eric T. Greager President and Chief Executive Officer(principal executive officer)Exhibit 31.2CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a‑ 14(a)I, Brant DeMuth, certify that:1.I have reviewed this Annual Report on Form 10-K for the year ended December 31, 2018 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 27, 2019 /s/ Brant DeMuth Brant DeMuth Executive Vice President and Chief Financial Officer (principal financialofficer)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, 2018 as filedwith the Securities and Exchange Commission on the date hereof (the “Report”), I, Eric T. Greager, 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 27, 2019 /s/ Eric T. Greager Eric T. Greager President and Chief Executive Officer(principal executive officer)Exhibit 32.2Certification of the Principle 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, 2018 as filedwith the Securities and Exchange Commission on the date hereof (the “Report”), I, Brant DeMuth, Executive Vice President and Chief Financial Officer,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 27, 2019 /s/ Brant DeMuth Brant DeMuth Executive Vice President and Chief Financial Officer (principal financialofficer)January 18, 2019 Mr. Jeffrey E. Wojahn Reserves Committee of Bonanza Creek Energy, Inc. c/o Bonanza Creek Energy, Inc. 410 Seventeenth Street, Suite 1400 Denver, Colorado 80202 Dear Mr. Wojahn: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2018, to the interest of Bonanza Creek Energy, Inc. and its wholly-owned direct and indirect subsidiaries (collectively, BCEI) in certain oil and gas properties located in Wattenberg Field, Colorado. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by BCEI. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following 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. We estimate the net reserves and future net revenue to BCEI interest in theseproperties, as of December 31, 2018, to be: Net Reserves Future Net Revenue(1) (M$) Oil NGL Gas Present Worth Category (MBBL) (MBBL) (MMCF) Total at 10% Proved Developed Producing 23,724.6 11,702.6 79,630.0 1,091,227.9 604,698.3 Proved Developed Non-Producing 0.0 0.0 0.0 -16.8 -15.4 Proved Undeveloped 40,629.1 13,226.7 85,381.6 1,140,297.1 350,297.1 Total Proved 64,353.7 24,929.3 165,011.6 2,231,508.1 954,980.1 Totals may not add because of rounding. (1) Future net revenue is after deducting estimated abandonment costs. 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 and pressure bases. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. No study was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreagebeyond those tracts for which undeveloped reserves have been estimated. Gross revenue is BCEI's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for BCEI's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2018. For oil and NGL volumes, the average West Texas Intermediate spot price of $65.56 per barrel is adjusted for quality, transportation fees, and market differentials. Transportation fees are inclusive of reductions to oil purchase contracts that were negotiated in the context of BCEI's recent restructuring. No adjustments have been made to estimates of future revenue to account for any potential shortfall or deficiency in fulfilling these contracts. For gas volumes, the average Henry Hub spot price of $3.100 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $59.29 per barrel of oil, $22.06 per barrel of NGL, and $2.282 per MCF of gas. Operating costs used in this report arebased on operating expense records of BCEI. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and BCEI's estimate of the portion of its headquarters general 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 and are not escalated for inflation. Capital costs used in this report were provided by BCEI and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are BCEI's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation. For the purposes of this report, we did notperform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the BCEI interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on BCEI receiving its net revenue interest share of estimated future gross production. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and 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. Estimates of 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, our estimates arebased on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by BCEI, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. The data used in our estimates were obtained from BCEI,other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Benjamin W. Johnson, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2007 and has over 2 years of prior industry experience. John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees III By: C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/Benjamin W. Johnson /s/ John G. Hattner By: By: Benjamin W. Johnson, P.E. 124738 John G. Hattner, P.G. 559 Vice President Senior Vice President Date Signed: January 18, 2019 Date Signed: January 18, 2019 BWJ: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 is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in 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 digital document. DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. (2) 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 may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used tosupport proved reserves, an "analogous reservoir" 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. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gasreserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Supplemental definitions from the 2018 Petroleum Resources Management System: Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access thesereserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent 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. Definitions - Page 1 of 6 DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. (iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is 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 oil and gas producing activities as defined in paragraph(a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory- type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs. (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records. (iii) Dry hole contributions and bottom holecontributions. (iv) Costs of drilling and equipping exploratory wells. (v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is 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 another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir. (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oiland gas") in their natural states and original locations; (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1) Lifting the oil and gas to the surface; and (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and Definitions - Page 2 of 6 DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, 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. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in thestate in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas; (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production; (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or (D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits ofcommercial production from the reservoir by a defined project. (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for anassociated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are 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. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Definitions - Page 3 of 6 DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipmentand facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become 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 and related equipment and facilities. (B) Repairs and maintenance. (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. (E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating 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 cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil andgas reserves are those 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 contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced 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 contain economically producible oil or gas on the basis of available geoscience and engineering data. (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 well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonablecertainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) 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, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and Definitions - Page 4 of 6 DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (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 be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. 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 of geoscience (geological, geophysical, and geochemical), engineering, and economic data are madeto estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal 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 and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally lowreservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year: a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities ofthose reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves. d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows. Definitions - Page 5 of 6 DEFINITIONS OF OIL AND GAS RESERVES Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves. f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed,to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projects — such asconstructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:  The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);  The company's historical record at completing development of comparable long-term projects;  The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;  The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significantsteps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and  The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. (32) Unproved properties. Properties with no proved reserves. Definitions - Page 6 of 6 

Continue reading text version or see original annual report in PDF format above