10-K 1 bcei2017123110-k.htm 10-K Document

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________
Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-35371
Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)
 
 
Delaware
(State or other jurisdiction of
incorporation 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 Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate 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 x
Indicate 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 preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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’s knowledge, 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. x
Indicate 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 growth company. 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 ¨
Accelerated filer x
Non-accelerated filer ¨
(Do not check if a
smaller reporting company)
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 financial accounting 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 x
Indicate 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 to the 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, 2017, based upon the closing price of $31.71 of the registrant’s common stock as reported on the New York Stock Exchange, was approximately $647,792,840. Excludes approximately 1,030 shares of the registrant’s common stock held 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 March 9, 2018: 20,453,619
Documents 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, 2017, as incorporated by reference into Part III of this report for the year ended December 31, 2017.
 

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BONANZA CREEK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2017

TABLE OF CONTENTS
 
    
    
PAGE
 


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Information Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 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 to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements include statements related to, among other things:
the Company’s business strategies and intent to maximize liquidity;
reserves estimates;
estimated sales volumes;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
ability to modify future capital expenditures;
the Wattenberg Field being a premier oil and resource play in the United States;
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;
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 acreage;
our ability to replace oil and natural gas reserves;

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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 and other 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 of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially 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 acreage positions;
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 and changes 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;

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access to adequate gathering systems and pipeline take-away capacity
our ability to provide adequate infrastructure for the products of our drilling program;
our ability to secure transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;
costs and other risks associated with curing title for mineral rights within our properties;
continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and
other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, 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 these statements 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 can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
GLOSSARY OF OIL AND NATURAL GAS TERMS
We 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 and accurate 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 may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support 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.
“Asset Sale.” Any direct or indirect sale, lease (including by means of production payments and reserve sales and a sale and lease-back transaction), 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 a ratio of six Mcf to one Bbl of oil.
“British thermal unit” or “BTU.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
“Basin.” A large natural depression on the earth’s surface in which sediments generally deposited via water accumulate.
“Central production facility.” Production facility for treating, gathering, storing and delivering oil, natural gas and water production from nearby wells.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment to allow for the production of crude oil 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, is in the liquid phase at surface pressure and temperature.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development costs.” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the 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; (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; and (iv) provide improved recovery systems.
“Development well.” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
“Differential.” The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead priced received.
“Deterministic method.” The method of estimating reserves or resources using a single value for each parameter (from the geoscience, engineering or economic 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, or is 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 of oil 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 a project.
“ERISA.” Employee Retirement Income Security Act of 1974.
“Estimated ultimate recovery (EUR).” Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of 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 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.
“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 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

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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.
“Finding and development costs.” Calculated by dividing the amount of total capital expenditures for oil and natural gas activities, by the amount of 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.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
‘‘Hydraulic fracturing.” The process of injecting water, proppant and chemicals under pressure into the formation to fracture the surrounding rock and 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 in 100 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 the working 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 of the fractional working interest owned in gross wells expressed as whole numbers and fractions of whole numbers.
“NGL.” Natural gas liquid.
“NYMEX.” The New York Mercantile Exchange.
“Oil and gas producing activities.” Defined as (i) the search for crude oil, including condensate and natural gas liquids, or natural gas in their natural states and original locations; (ii) the acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil 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 and gathering, treating and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (iv) extraction of saleable

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hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coal beds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
“PDNP.” Proved developed non-producing reserves.
“PDP.” Proved developed producing reserves.
“Percentage-of-proceeds.” A processing contract where the processor receives a percentage of the sold outlet stream, dry gas, NGLs or a combination, 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 areas with 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 stratum will 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 a governmental spacing unit for one or more productive formations. (Pooling is also known as unitization or communitization.). Ownership interests are calculated 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 applicable operating costs of support equipment and 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; 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, 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 costs of oil and gas produced along with production (lifting) costs identified 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 naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
“Proved developed reserves.” Proved reserves that can be expected to be recovered 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.
“Proved reserves.” 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.

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(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 reasonable certainty.
(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 potions of the reservoir only if geoscience, engineering, or performance data and 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, 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
(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.
“Proved undeveloped reserves” or “PUD.” Proved reserves 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. 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. 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 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 other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, 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 and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices (after adjustment for differentials in location and quality) for each of the preceding twelve months. Please refer to the footnote 2 of the Proved Reserves table in Item 1 of this Annual Report on Form 10-K for additional discussion.
“Reasonable certainty.” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent 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 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.

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"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 an attempt to establish or increase existing production.
“Reserves.” Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, 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.
“Reserve replacement percentage.” The sum of sales of reserves, reserve extensions and discoveries, reserve acquisitions, and reserve revisions of previous 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 is confined 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 is dependent upon new technologies such as horizontal drilling and multi-stage fracture stimulation to access large rock volumes in order to produce economic quantities of oil or natural gas.
“Royalty interest.” An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGLs produced and sold unencumbered 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 and third 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 for the following specific purposes: gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection 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 a productive reservoir along with the appropriate well density for the designated spacing unit size. Typical spacing for conventional wells is 40 acres for oil wells 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 well for 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 one mile, 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 of economic 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 on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Also referred to as “undeveloped oil and gas reserves.”
“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 working interest 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.

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“WTI.” West Texas Intermediate index.



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PART I
Item 1. Business
When we use the terms “Bonanza Creek,” the “Company,” “we,” “us,” or “our” we are referring to Bonanza Creek Energy, Inc. and its consolidated subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Natural Gas Terms above. Throughout this document we make statements that may be classified as “forward-looking” Please refer to the Information Regarding Forward-Looking Statements section above for an explanation of these types of statements.
Overview
Bonanza Creek is a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Bonanza Creek Energy, Inc. was incorporated in Delaware on December 2, 2010 and went public in December 2011.
Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado. We also own and operate oil-producing assets in the Dorcheat Macedonia Field and the McKamie Patton Field in southern Arkansas and the North Park Basin in Colorado. We operate approximately 92% of all our productive wells allowing us to control the pace, costs and completion techniques used in the development of our asset base. The Wattenberg Field has a low cost structure, strong production efficiencies, established reserves and prospective drilling opportunities, which allows for predictable production and reserve growth.
Bankruptcy Proceedings under Chapter 11
On January 4, 2017, the Company and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions under Chapter 11 in the Bankruptcy Court. The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). For additional information about our bankruptcy proceedings and emergence, see Note 2 - Chapter 11 Proceedings and Emergence.
Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date, which differed materially from the recorded values of those same assets and liabilities in the Predecessor Company. As a result, our balance sheets and statement of operations subsequent to the Effective Date are not comparable to our balance sheets and statements of operations prior to the Effective Date. For additional information about our application of fresh-start accounting, see Note 3 - Fresh-Start Accounting.  
References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017. References to “Current Successor Period” relates to the period of April 29, 2017 through December 31, 2017. References to “Current Predecessor Period” relate to the period of January 1, 2017 through April 28, 2017. References to “Prior Predecessor Period” relate to the period of January 1, 2016 through December 31, 2016.
Our Business Strategies
In 2017, the Company recapitalized its balance sheet, such that it is now well positioned to pursue its development strategy. This strategy consists of utilizing enhanced completion designs to increase the productivity of wells across our acreage position and securing our leasehold position in French Lake, which we expect to delineate in 2018. In order to focus on and partially fund the development of its core assets, the Company elected, subsequent to year-end, to actively pursue the divestment of its Mid-Continent region and North Park Basin assets. The Company successfully sold its North Park Basin on March 9, 2018 for $0.1 million and full release of all current and future obligations.
We also took steps to improve our access to gas processing in the DJ Basin, which will result in improved costs, greater reliability, and greater optionality than available to many other operators in the basin while enhancing the value of our Rocky Mountain Infrastructure, LLC (“RMI”) system. This flexibility helps ensure product flow from both existing and new wells. We will continue to look for ways to improve our access to gas gathering and processing services.
During 2017, we implemented a series of cost reductions that are anticipated to be fully realized by the beginning of 2019 and result in annualized G&A and LOE reductions of approximately $20.0 million. The cost reductions were focused
primarily around labor, compression contracts, water services, and well servicing. Further efficiency improvements will continue to be a focus for the Company, with our per-unit costs benefiting from production growth in 2018 and beyond.
In 2018, the Company plans to accelerate development in the DJ Basin while testing enhanced completion designs on large, efficient multi-well pads throughout the Company’s acreage position. Enhanced completion designs will vary to ensure that thorough knowledge can be applied to future drilling programs. Fluid volumes and types, proppant volumes and types, stage spacing, well spacing, and flowback technique are the primary variables that will be tested throughout the 2018 program. The Company will continue to monitor industry trends, public data, and information from non-operated wells to further delineate optimum completion techniques. The program contemplates running one rig in the first half of 2018 with a second rig added at mid-year to coincide with its access to additional gas processing capacity. The 2018 program is expected to grow Wattenberg annual production by approximately 20% in 2018 and greater than 50% in 2019, assuming a continuous two rig program.
Capital investment with the 2018 program is expected to be approximately $280.0 million to $320.0 million, which will support drilling 90 gross wells and turning online 55 gross wells.
In order to help achieve the Company's strategies, we are actively seeking to secure permanent leadership.
The following tables summarize our estimated proved reserves, PV-10 reserve value, sales volumes, and projected capital spend as of December 31, 2017:
 
    
 
    
 
    
Natural
    
 
 
 
Crude
 
Natural
 
Gas
 
Total
 
 
Oil
 
Gas
 
Liquids
 
Proved
Estimated Proved Reserves
 
(MBbls)
 
(MMcf)
 
(MBbls)
 
(MBoe)
Developed
 
 
 
 
 
 
 
 
    Rocky Mountain
 
19,419

 
71,212

 
11,107

 
42,396

    Mid-Continent
 
6,366

 
21,506

 
1,595

 
11,544

 
 
25,785

 
92,718

 
12,702

 
53,940

Undeveloped
 
 
 
 
 
 
 
 
    Rocky Mountain
 
27,143

 
64,951

 
10,113

 
48,082

    Mid-Continent
 

 

 

 

 
 
27,143

 
64,951

 
10,113

 
48,082

Total Proved
 
52,928

 
157,669

 
22,815

 
102,022

 
 
 
 
 
 
 
 
 
 
 
Sales Volumes for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
the Year Ended
 
 
 
 
Net Proved
 
 
Estimated Proved Reserves at
 
December 31,
 
 
 
 
Undeveloped
 
 
December 31, 2017(1)
 
2017
 
 
 
 
Drilling
 
 
 
 
 
 
 
 
 
 
 
Average Net
 
 
 
Projected
 
Locations
 
 
Total
 
 
 
 
 
 
 
 
Daily Sales
 
 
 
2018 Capital
 
as of
 
 
Proved
 
% of
 
% Proved
 
PV-10
 
Volumes
 
% of
 
Expenditures
 
December 31,
 
 
(MBoe)
   
Total
 
Developed
 
($ in MM)(2)
   
(Boe/d)
   
Total
 
($ in millions)
   
2017
Rocky Mountain
 
90,478

 
89
%
 
47
%
 
$
484.8

 
12,783

 
80
%
 
$
280-320

 
155.5

Mid-Continent(3)
 
11,544

 
11
%
 
100
%
 
 
113.7

 
3,213

 
20
%
 
 

 

Total
 
102,022

 
100
%
 
53
%
 
$
598.5

 
15,996

 
100
%
 
$
280-320

 
155.5

_____________________
(1)
Proved reserves and related future net revenue and PV-10 were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices for each of the preceding twelve months, which were $51.34 per Bbl WTI and $2.98 per MMBtu HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $4.58 per Bbl for crude oil and a decrease of $0.53 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 natural gas liquid reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices, after adjustment for differentials in location and quality, for each of the preceding twelve

11


months. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating the Company and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. PV-10 differs from Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) because it does not include the effect of future income taxes. Please refer to the Reconciliation of PV-10 to Standardized Measure presented in the “Reserves” subsection of Item 1 below.
(3)
Mid-Continent sales volumes were 3,213 Boe/d for 2017, which is comprised of 2,885 Boe/d of production net to our interest and 328 Boe/d sales volumes from our percentage-of-proceeds contracts.

Our Operations
Our operations are mainly focused in the Wattenberg Field in the Rocky Mountain region and in the Dorcheat Macedonia Field in the Mid-Continent region.
Rocky Mountain Region
The two areas in which we operate in the Rocky Mountain region are the Wattenberg Field in Weld County, Colorado and the North Park Basin in Jackson County, Colorado. As of December 31, 2017, our estimated proved reserves in the Rocky Mountain region were 90,478 MBoe, which represented 89% of our total estimated proved reserves and contributed 12,783 Boe/d, or 80%, of sales volumes during 2017.
Wattenberg Field - Weld County, Colorado. Our operations are located in the oil and liquids-weighted extension area of the Wattenberg Field targeting the Niobrara and Codell formations. As of December 31, 2017, our Wattenberg position consisted of approximately 95,000 gross (67,000 net) acres.
The Wattenberg Field is now primarily developed for the Niobrara and Codell formations using horizontal drilling and multi-stage fracture stimulation techniques. We believe the Niobrara B and C benches have been fully delineated on our legacy acreage, while the Codell formation has been delineated on our western legacy acreage. Our northern and southern acreage positions are in the early stages of delineation.
Our estimated proved reserves at December 31, 2017 in the Wattenberg Field were 90,236 MBoe. As of December 31, 2017, we had a total of 625 gross producing wells, of which 447 were horizontal wells, and our sales volumes during 2017 were 12,719 Boe/d. Our sales volumes for the fourth quarter of 2017 were 11,916 Boe/d. As of December 31, 2017, our working interest for all producing wells averaged approximately 80% and our net revenue interest was approximately 66%.
We drilled and participated in drilling 59.5 gross (31.8 net) standard reach lateral (“SRL”) equivalent wells in 2017 in the Wattenberg Field. As of December 31, 2017, we have an identified drilling inventory of approximately 205 gross (155.5 net) proved undeveloped (“PUD”) drilling locations (248 gross SRL equivalents) on our acreage.
During the year, in the Niobrara benches, we drilled eight gross extended reach lateral (“XRL”) operated wells and nine gross SRL operated wells, and we completed four gross XRL operated wells and five gross SRL operated wells. In addition, we drilled and completed one gross Codell SRL operated well. We also participated in the drilling and completion of 15 gross (5.0 net) XRL wells and one gross (0.1 net) medium reach lateral (“MRL”) well in the Niobrara formation. We also participated in the completion of six gross (0.01 net) SRL wells in the Niobrara formation. In addition, we participated in the drilling and completion of one gross (0.5 net) XRL well and the completion of one gross (0.002 net) SRL well in the Codell formation.
The Company entered into two third-party gas processor contracts recently, which reduced line pressures in the Company’s RMI system resulting in improved production from both new and existing wells, and will allow flexibility in moving gas to the most advantageous locations and provide additional production flow assurance.
The Company anticipates running one rig in the first half of 2018 with a second rig added at mid-year. The first rig is planned to drill large scale pads of up to eight wells throughout our legacy acreage position. At least two of the pads drilled in the first half of the year will be completed using slick-water completion designs to further test and validate the improved performance compared to historic gel completion designs. One of these pads is located in the western legacy acreage with the

12


second pad located in the eastern legacy acreage. Data gathered from these tests will help formulate completion designs in the back half of the year and beyond. The addition of the second rig will provide additional data to form completion techniques and development assumptions throughout the acreage position going forward. The Company will continue to remain agile and modify drilling and completion techniques as additional data from both operated and non-operated wells becomes available.
The 2018 program is expected to grow Wattenberg annual production by approximately 20% in 2018 and greater than 50% in 2019, assuming a continuous two rig program.
Capital investment with this program is expected to be approximately $280.0 million to $320.0 million, which will support drilling 90 gross wells and turning online 55 gross wells in 2018. Of the wells planned to be drilled, approximately 43 are XRL wells, seven are MRL wells, and 40 are SRL wells. The cost of an XRL, MRL, and SRL well is anticipated to be $5.4 million, $4.2 million, and $3.0 million, respectively.
North Park Basin - Jackson County, Colorado. We control approximately 20,000 gross (15,000 net) acres in the North Park Basin in Jackson County, Colorado, all prospective for the Niobrara oil shale. We operate the North and South McCallum Fields, which currently produce light oil, which is trucked to market.
In the North Park Basin, our estimated proved reserves as of December 31, 2017 were approximately 242 MBoe, consisting of 100% crude oil, and our sales volumes during 2017 were 64 Boe/d. Our sales volumes in the North Park Basin for the fourth quarter of 2017 were 57 Boe/d. There were no wells drilled during 2017 in the North Park Basin.
The Company successfully sold its North Park Basin on March 9, 2018 for $0.1 million and full release of all current and future obligations.
Mid-Continent Region
In southern Arkansas, we target the oil-rich Cotton Valley sands in the Dorcheat Macedonia and McKamie Patton Fields. As of December 31, 2017, our estimated proved reserves in the Mid-Continent region were 11,544 MBoe. We currently have 300 gross producing vertical wells. During 2017, no wells were drilled in the Mid-Continent region; however, the Company recompleted 25 wells in the Cotton Valley formation. We achieved a sales volume rate for 2017 of 3,213 Boe/d, of which 70% was from oil and NGLs, and a sales volume rate for the fourth quarter of 2017 of 2,778 Boe/d. None of our 2018 capital budget is assigned to the Mid-Continent region.
Dorcheat Macedonia. In the Dorcheat Macedonia Field, we average an approximate 87% working interest and an approximate 72% net revenue interest on all producing wells. The majority of our acreage is held by unitization or production. Our production during 2017 was approximately 2,660 Boe/d (2,988 Boe/d sales volumes). During the fourth quarter of 2017, our production was 2,251 Boe/d (2,595 Boe/d sales volumes). Our proved reserves in this field are approximately 10,419 MBoe. Due to the Company having no current plans to drill within the Mid-Continent region, no PUDs have been assigned to this region.
Other Mid-Continent. We own additional interests in the McKamie Patton Field in the Mid-Continent region near the Dorcheat Macedonia Field. As of December 31, 2017, our estimated proved reserves were approximately 1,125 MBoe, and sales volumes during 2017 were approximately 225 Boe/d. During the fourth quarter of 2017, our production was 183 Boe/d.
Gas Processing Facilities. Our Mid-Continent gas processing facilities are located in Lafayette and Columbia counties in Arkansas and are strategically located to serve our production in the region. Our McKamie Gas Plant has been idle since 2015, and our Dorcheat Macedonia Field Gas Plant has a current capacity of 12.5 MMcf/d with 28,000 gallons per day of associated NGL capacity. Our ownership of these facilities and related gathering pipeline provides us with the benefit of controlling processing and compression of our natural gas production.
Reserves
Estimated Proved Reserves
The summary data with respect to our estimated proved reserves presented below has been prepared in accordance with rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to companies involved in oil and natural gas producing activities. Our reserve estimates do not include probable or possible reserves. Our estimated proved reserves for the years ended December 31, 2017, 2016 and 2015 were determined using the preceding twelve month

13


unweighted arithmetic average of the first-day-of-the-month prices. For a definition of proved reserves under the SEC rules, please see the Glossary of Oil and Natural Gas Terms included in the beginning of this report.
Reserve estimates are inherently imprecise, and estimates for undeveloped properties are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, all of these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actual quantities 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, 2017, 2016 and 2015 for each of the regions and currently producing fields in which we operate. The proved reserve estimates as of December 31, 2017 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our third-party independent reserve engineers. The proved reserves as of December 31, 2016 and 2015 are based on reports prepared by our internal corporate reservoir engineering group, of which 100% were audited by NSAI. For more information regarding our independent reserve engineers, please see Independent Reserve Engineers below. The information in the following table is not intended to represent the current market value of our proved reserves nor does it give any effect to or reflect our commodity derivatives or current commodity prices.
 
 
At December 31,
 
Region/Field
 
2017
 
2016
 
2015
 
 
 
(MMBoe)
 
Rocky Mountain
    
90.5

    
78.0

    
80.1

 
    Wattenberg
 
90.3

 
77.8

 
79.8

 
    North Park
 
0.2

 
0.2

 
0.3

 
Mid-Continent
 
11.5

 
12.7

 
21.2

 
    Dorcheat Macedonia
 
10.4

 
11.6

 
20.1

 
    McKamie Patton
 
1.1

 
1.1

 
1.1

 
  Total
 
102.0

 
90.7

 
101.3

 
The following table sets forth more information regarding our estimated proved reserves at December 31, 2017, 2016 and 2015:

14


 
 
At December 31,
 
 
 
2017
 
2016
 
2015
 
Reserve Data(1):
    
    
    
    
    
    
 
  Estimated proved reserves:
 
 
 
 
 
 
 
    Oil (MMBbls)
 
52.9

 
50.1

 
57.4

 
    Natural gas (Bcf)
 
157.7

 
138.0

 
144.2

 
    Natural gas liquids (MMBbls)
 
22.8

 
17.5

 
19.9

 
      Total estimated proved reserves (MMBoe)(2)
 
102.0

 
90.7

 
101.3

 
      Percent oil and liquids
 
74
%
 
75
%
 
76
%
 
  Estimated proved developed reserves:
 
 
 
 
 
 
 
    Oil (MMBbls)
 
25.8

 
26.3

 
28.9

 
    Natural gas (Bcf)
 
92.7

 
86.0

 
77.5

 
    Natural gas liquids (MMBbls)
 
12.7

 
10.0

 
10.4

 
      Total estimated proved developed reserves (MMBoe)(2)
 
53.9

 
50.6

 
52.2

 
      Percent oil and liquids
 
71
%
 
72
%
 
75
%
 
  Estimated proved undeveloped reserves:
 
 
 
 
 
 
 
    Oil (MMBbls)
 
27.1

 
23.8

 
28.5

 
    Natural gas (Bcf)
 
65.0

 
52.0

 
66.7

 
    Natural gas liquids (MMBbls)
 
10.1

 
7.5

 
9.6

 
      Total estimated proved undeveloped reserves (MMBoe)(2)
 
48.1

 
40.1

 
49.2

 
      Percent oil and liquids
 
77
%
 
78
%
 
77
%
 
____________________
(1)
Proved reserves were calculated using the preceding twelve month unweighted arithmetic average of the first-day-of-the-month prices, which were $51.34 per Bbl WTI and $2.98 per MMBtu HH, $42.75 per Bbl WTI and $2.48 per MMBtu HH, and $50.28 per Bbl WTI and $2.59 per MMBtu HH for the years ended December 31, 2017, 2016 and 2015, 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 and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves on undrilled acreage are 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 productivity at greater distances.

Proved undeveloped locations in our December 31, 2017 reserve report are included in our development plan and are scheduled to be drilled within five years from their initial proved booking date. Upon emergence from bankruptcy, the Company undertook a process to review its five-year development schedule in light of improved commodity pricing and the significant improvement in the Company's liquidity and outstanding long-term debt and determined that all PUDs would in fact be drilled within the five-year alloted window. The Company’s management evaluated the proved undeveloped drilling plan using NYMEX strip prices, the liquidation model for general and administrative costs and the cash flows from potential asset sales, wells scheduled to be drilled and from existing properties. Upon emergence from bankruptcy, the Company made the election to reset the five-year rule on its existing PUDs. The reserve report factored in a one-rig program until the second half of 2022, when a second-rig is added, which allows all PUDs to be drilled within the allotted five-year window. Subsequent to year-end, the Company approved a second rig to be added at mid-year 2018. All of the PUDs at December 31, 2017 reside in the Wattenberg field. The reliable technologies used to establish our proved reserves are a combination of pressure performance, geologic mapping, offset productivity, electric logs, and production data.

Estimated proved reserves at December 31, 2017 were 102.0 MMBoe, a 13% increase from estimated proved reserves of 90.7 MMBoe at December 31, 2016. Approximately 89% of our December 31, 2017 proved reserves are attributed to the Rocky Mountain region, and 99.8% of the Rocky Mountain proved reserves are attributed to the Wattenberg Field. The net increase in our reserves of 11.3 MMBoe is the result of a 15.5 MMBoe increase from PUD and 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 2.1

15


MMBoe 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 from December 31, 2016 to December 31, 2017 consisted of pricing and LOE changes, reserve additions from capital and PUD developments, and engineering revisions. The positive pricing revision of 5,405 Mboe resulted from an increase in average commodity price from $42.75 per Bbl 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 is 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 is the result of completing 10 operated and 24 non-operated unproved horizontal locations in the Niobrara and Codell formations in the Wattenberg Field during 2017 and adding infill PUD locations that are on the 2018 rig schedule, offset by PUD locations that were removed due to a shift within our development strategy.
As of December 31, 2017, the current total proved undeveloped location count in our Wattenberg Field was 205 (248 SRL equivalents), compared to 210 (226 SRL equivalents) as of December 31, 2016. Our five-year plan includes the drilling of these proved undeveloped locations. The year-end 2017 reserves were based on a one-rig drilling program estimated to convert 19% of our year-end 2017 proved undeveloped reserves in the Wattenberg Field. Subsequent to year-end, the Company approved a second rig to be added at mid-year 2018. New drilling in 2018 will begin around existing central production facilities (“CPFs”) as they can be connected immediately upon completion. For the year ending December 31, 2017, approximately 50% of the proved undeveloped locations are spaced on 80 acres within a single bench and approximately 50% 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 acre offset between wells on the upper and lower bench.
Estimated proved reserves at December 31, 2016 were 90.7 MMBoe, a 10% decrease from estimated proved reserves of 101.3 MMBoe at December 31, 2015. The net decrease in our reserves of 10.6 MMBoe is the result of 2016 production of 7.8 MMBoe coupled with writing off 16.4 MMBoe of PUDs and 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 completing 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-operated unproved horizontal wells and one operated unproved vertical well in the Niobrara formation in the Wattenberg Field during 2016. In 2016 our five-year drilling plan was adjusted to focus on locations that were adjacent to existing production 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 reserve changes in the Wattenberg Field and 4,416 Mboe were related to negative reserve changes in the Dorcheat Macedonia Field. The overall positive engineering 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. The negative 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 per MMBtu 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 of the 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 lateral equivalents) and was 204 as of December 31, 2015.
Total Company positive engineering revisions as of December 31, 2015, were 37,174 Mboe, of which 30,086 Mboe (81%) related to reserve changes in the Wattenberg Field. This positive engineering revision was offset by a negative pricing revision of 21,417 Mboe in the Wattenberg Field. The majority of the positive revisions in the Wattenberg Field resulted from a combination of decreased drilling and completion costs, including $3.0 million per standard reach lateral well as of December 31, 2015 compared to $4.2 million at December 31, 2014, a 29% decrease, and an increase in productivity from horizontal proved developed producing wells, which increased the offsetting proved undeveloped reserves. The increase in PDP reserves was primarily attributed to the installation of infrastructure in the east side of our Wattenberg Field acreage, which removed the producing constraint that inhibited productivity over the prior two years of development in that area. Another significant contribution to the positive reserve revision in the Wattenberg Field results from a contract change as of January 1, 2015, which gave our Company ownership of the natural gas liquids from our gas production. This conversion from two-stream (wet gas and oil) to three-stream (dry gas, natural gas liquids and oil) added 8,560 Mboe to our proved reserves as of December 31, 2015. With the addition of 45 horizontal proved undeveloped locations in the Wattenberg Field to the proved reserves at

16


December 31, 2015, the total proved undeveloped location count as of December 31, 2015 was 204 (220 standard reach lateral equivalents) and was 226 as of December 31, 2014. A negative pricing revision of 28,810 Mboe for the Company resulted from a decrease in average commodity price from $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014 to $50.28 per Bbl WTI and $2.59 per MMBtu HH for the year ended December 31, 2015.
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized 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 flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Neither our PV-10 measure or the Standardized Measure purport to 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, 2017, 2016 and 2015:
 
 
December 31,
 
 
2017
 
2016
 
2015
 
 
(in millions)
PV-10
    
$
598.5

    
$
276.9

    
$
327.8

Present value of future income taxes discounted at 10%(1)
  
 

 
 

 
 

Standardized Measure
 
$
598.5

 
$
276.9

 
$
327.8

____________________________
(1) The tax basis of our oil and gas properties as of December 31, 2017, 2016, and 2015 provides more tax deduction than income generated from our oil and gas properties when the reserve estimates were prepared using $51.34 per Bbl WTI and $2.98 per MMBTU HH, $42.75 per Bbl WTI and $2.48 per MMBtu HH, and $50.28 per Bbl WTI and $2.59 per MMBtu HH, respectively.

Proved Undeveloped Reserves
 
 
Net Reserves, MBoe
 
 
At December 31,
 
 
2017
 
2016
 
2015
Beginning of year
    
40,057

 
49,184

 
43,246

Converted to proved developed
 
(2,196
)
 
(1,352
)
 
(6,994
)
Additions from capital program
 
11,717

 

 
2,308

Removed from capital program
 
(7,577
)
 
 
 
 
Acquisitions
 

 

 
1,541

Revisions
 
6,081

 
(7,775
)
 
9,083

End of year
 
48,082

 
40,057

 
49,184


At December 31, 2017, our proved undeveloped reserves were 48,082 MBoe, all of which are scheduled to be drilled within five years of their initial proved booking date. During 2017, the Company converted 6% of its proved undeveloped reserves (seven gross wells representing net reserves of 2,196 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 are on the 2018 rig schedule, offset by PUD locations that were removed due to a changes in our development strategy. The increase in revisions is primarily due to the forecasted 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 their initial proved booking date. During 2016, the Company converted 3% of its proved undeveloped

17


reserves (seven gross wells representing net reserves of 1,352 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 a result 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 of PUDs in the Mid-Continent region, as drilling is now focused entirely on the Wattenberg Field. Thirty-eight Wattenberg proved undeveloped locations that were not within areas with existing CPFs were demoted and were replaced with 42 infill proved undeveloped locations that are near existing CPFs which contributes to development well planning.
At December 31, 2015, our proved undeveloped reserves were 49,184 MBoe, all of which were scheduled to be drilled within five years of their initial proved booking date. During 2015, the Company converted 16% of its proved undeveloped reserves (52 gross wells representing net reserves of 6,994 MBoe) at a cost of $121.0 million. Executing our 2015 capital program resulted in the addition of 2,308 MBoe (17 gross wells) in proved undeveloped reserves in the Wattenberg Field. A small acquisition within the field limits of the Dorcheat Macedonia Field added 14 gross proved undeveloped locations and 1,541 MBoe to our reserves. The positive engineering revision of 9,083 MBoe reflected in the December 31, 2015 reserve estimates was primarily the result of adding 28 gross new proved undeveloped locations in the Wattenberg Field on 80-acre spacing, the majority directly offsetting economic proved producing wells drilled prior to 2015, and an increase in proved undeveloped reserves in the eastern portion of the Wattenberg Field resulting from increased productivity due to the procurement and installation of third party infrastructure, which eliminated a production constraint thereby allowing productivity to rise, proved developed reserves to increase, and associated proved undeveloped reserves to increase by an estimated 3.0 MMBoe.
Internal controls over reserves estimation process
Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with SEC definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The Company’s Reserves Committee reviews significant reserve changes on an annual basis and our third-party independent reserve engineers, NSAI, is engaged by and has direct access to the Reserves Committee. The reserves estimates for the year ended December 31, 2017 shown herein have been independently prepared by NSAI. These NSAI reserve estimates are reviewed by our in-house petroleum engineer who oversees and controls preparation of the reserve report data by working with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI for their evaluation process. The Company's technical person who was primarily responsible for overseeing the preparation of our reserve estimates was our Senior Reservoir Development Engineer who has over 17 years of experience in the oil and gas industry, including three years in her role at the Company. Her professional qualifications include a bachelor's degree in Petroleum Engineering from the University of Wyoming and a master's degree in Petroleum Engineering from the Colorado School of Mines.
For the years ended December 31, 2016 and 2015 the Company prepared the reserves estimates, which were 100% audited by NSAI. The responsibility for compliance in reserves estimation was delegated to our internal corporate reservoir engineering group managed by John E. Vorwerk. Mr. Vorwerk was our Corporate Reserves Manager until August 2017. Mr. Vorwerk attended the Colorado School of Mines and graduated in 1976 with a Bachelor of Science degree in Geological Engineering. He also received a Master of Science degree in Mineral Economics from the Colorado School of Mines in 1991. Mr. Vorwerk had been in the petroleum industry for 41 years, and had been a Registered Professional Engineer since 1981. He had been directly involved in evaluations and the estimation of reserves and resources, and has worked in the corporate reserves function for over 21 years. Mr. Vorwerk was employed at Bonanza from 2014 until 2018, and served as Corporate Reserves Manager. During this time our internal corporate reservoir engineering group was responsible for compliance in reserve estimation, and our internal corporate reservoir engineering gropu, collectively with Mr. Vorwerk, had over 85 years of industry experience.
Independent Reserve Engineers
The reserves estimates for the year ended December 31, 2017 shown herein have been independently prepared by NSAI. The reserve estimates for the years ended December 31, 2016 and 2015 were independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Benjamin W. Johnson and Mr. John Hattner.  Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from Texas Tech University in 2005 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry

18


experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Production, Revenues and Price History
Oil and gas prices have shown signs of rebounding during the latter part of 2017 and continuing into 2018. Oil prices are impacted by production levels, crude oil inventories, real or perceived geopolitical risks in oil producing regions, the relative strength of the U.S. dollar, weather and the global economy. With better pricing, we expect increased industry activity, which could moderate the magnitude of price increases throughout the year.
Sensitivity Analysis
If oil and natural gas SEC prices declined by 10%, our proved reserve volumes would decrease by 2% and our PV-10 value as of December 31, 2017 would decrease by approximately 28% or $169.0 million. The PV-10 value of our Rocky Mountain region, primarily our Wattenberg assets, would decrease by 31% or $148.3 million. If oil and natural gas SEC prices increased by 10%, our proved reserve volumes would increase by 1% and our PV-10 value as of December 31, 2017 would increase by approximately 27% or $161.7 million. The PV-10 value of our Rocky Mountain region, primarily our Wattenberg assets, would increase by 29% or $140.5 million.
The Company did not incur any impairments during 2017, and we do not anticipate triggering any impairments in 2018 when analyzing price changes only.
Production
The following table sets forth information regarding oil, natural gas, and natural gas liquids production, sales prices, and production costs for the periods indicated. For additional information on price calculations, please see information set forth in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

19


 
 
Successor
 
 
Predecessor
 
 
April 29, 2017 through December 31, 2017
 
 
January 1, 2017 through April 28, 2017
 
For the Year Ended December 31, 2016
 
For the Year Ended December 31, 2015
Oil:
    
 
 
 
 
 
 
 
 
    
    
 
    
Total Production (MBbls)
 
 
2,012.7

 
 
 
1,068.5

 
 
4,309.9

 
 
6,072.3

    Wattenberg Field
 
 
1,568.5

 
 
 
834.4

 
 
3,470.7

 
 
5,029.6

    Dorcheat Macedonia Field
 
 
379.9

 
 
 
193.2

 
 
750.0

 
 
923.2

Average sales price (per Bbl), including derivatives(3)
 
$
46.44

 
 
$
48.29

 
$
39.57

 
$
62.07

Average sales price (per Bbl), excluding derivatives(3)
 
$
47.18

 
 
$
48.29

 
$
35.32

 
$
40.95

Natural Gas:
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Production (MMcf)
 
 
5,767.5

 
 
 
3,242.5

 
 
11,906.3

 
 
14,110.9

    Wattenberg Field
 
 
4,588.1

 
 
 
2,564.9

 
 
9,574.8

 
 
11,020.8

    Dorcheat Macedonia Field
 
 
1,179.3

 
 
 
677.6

 
 
2,331.4

 
 
3,090.5

Average sales price (per Mcf), including derivatives(4)
 
$
2.29

 
 
$
2.57

 
$
1.76

 
$
1.95

Average sales price (per Mcf), excluding derivatives(4)
 
$
2.29

 
 
$
2.57

 
$
1.76

 
$
1.77

Natural Gas Liquids:
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Production (MBbls)
 
 
712.9

 
 
 
422.7

 
 
1,491.1

 
 
1,675.9

    Wattenberg Field
 
 
656.2

 
 
 
391.1

 
 
1,354.3

 
 
1,489.9

    Dorcheat Macedonia Field
 
 
56.8

 
 
 
31.6

 
 
136.8

 
 
186.0

Average sales price (per Bbl), including derivatives
 
$
18.38

 
 
$
17.52

 
$
12.39

 
$
9.49

Average sales price (per Bbl), excluding derivatives
 
$
18.38

 
 
$
17.52

 
$
12.39

 
$
9.49

Oil Equivalents:
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Production (MBoe)
 
 
3,686.9

 
 
 
2,031.6

 
 
7,785.4

 
 
10,100.0

    Wattenberg Field
 
 
2,989.4

 
 
 
1,653.0

 
 
6,420.8

 
 
8,356.3

    Dorcheat Macedonia Field
 
 
633.2

 
 
 
337.7

 
 
1,275.4

 
 
1,624.2

Average Daily Production (Boe/d)
 
 
15,048.4

 
 
 
16,930.4

 
 
21,271.7

 
 
27,671.2

    Wattenberg Field
 
 
12,201.5

 
 
 
13,774.9

 
 
17,543.4

 
 
22,894.1

    Dorcheat Macedonia Field
 
 
2,584.5

 
 
 
2,814.3

 
 
3,484.5

 
 
4,450.0

Average Production Costs (per Boe)(1)(2)
 
$
9.28

 
 
$
8.20

 
$
7.25

 
$
7.56

_________________________
(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 3,686.9 MBoe, 2,031.6 MBoe, 7,785.4 MBoe, and 10,100.0 MBoe for the Current Successor Period, Current Predecessor Period, and the Prior Predecessor Periods of 2016 and 2015, respectively. Total production volumes exclude volumes from our percentage-of-proceeds contracts in our Mid-Continent region of 77.9 MBoe, 41.9 MBoe, 150.1 MBoe, and 219.4 MBoe for the Current Successor Period, Current Predecessor Period, and the Prior Predecessor Periods of 2016 and 2015, respectively.
(3)
Crude oil sales excludes $0.2 million, $0.1 million, $0.5 million, and $0.2 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the Current Successor Period, Current Predecessor Period, and the Prior Predecessor Periods for 2016 and 2015, respectively.
(4)
Natural gas sales excludes $0.8 million, $0.4 million, $1.5 million, and $0.8 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the Current Successor Period, Current Predecessor Period and the Prior Predecessor Periods for 2016 and 2015, respectively.

Principal Customers
Three of our customers, NGL Crude Logistics, LLC, Lion Oil Trading & Transportation, Inc., and Duke Energy Field Services, comprised 44%, 18%, and 16%, respectively, of our total revenue for the year ended December 31, 2017. No other single non-affiliated customer accounted for 10% or more of our oil and natural gas sales in 2017. We believe the loss of any

20


one customer would not have a material effect on our financial position or results of operations because there are numerous potential customers for our production.
Delivery Commitments
The Company entered into a new purchase agreement upon emergence from bankruptcy. The terms of the agreement consists of defined volume commitments over an initial seven-year term. The Company will be required to make periodic deficiency payments for any shortfalls in delivering minimum volume commitments, which are set in six-month periods beginning in January 2018. The Company's capital program is designed to exceed these minimum volume commitments. During 2018, the average minimum volume commitment will be approximately 10,100 barrels per day and increases by approximately 41% 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 the applicable differential fee, is $154.5 million as of December 31, 2017. Please refer to Note 8 - Commitments and Contingencies for additional discussion.

Productive Wells
The following table sets forth the number of producing oil and natural gas wells in which we owned a working interest at December 31, 2017.
 
 
Oil(2)
 
Natural Gas(1)
 
Total(2)
 
Operated(2)
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Rocky Mountain
   
679
 
   
553.1

   

   

   
679
 
   
553.1

   
568
 
   
533.3

Mid-Continent
 
300
 
 
261.0

 

 

 
300
 
 
261.0

 
297
 
 
261.0

    Total(2)
 
979
 

814.1

 

 

 
979
 
 
814.1

 
865
 
 
794.3

__________________________
(1)
All gas production is associated gas from producing oil wells.
(2)
Count came from internal production reporting system.

Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2017, broken down by the areas where we operate, along with the PV-10 values of each. 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-10
Rocky Mountain
    
76,565

 
62,451

 
37,716

 
19,334

 
114,281

 
81,785

 
 
484,833

    Wattenberg Field
 
61,882

 
50,629

 
32,812

 
16,369

 
94,694

 
66,998

 
 
483,769

    Other Rocky Mountain
 
14,683

 
11,822

 
4,904

 
2,965

 
19,587

 
14,787

 
 
1,064

Mid-Continent
 
11,790

 
10,051

 
2,305

 
1,081

 
14,095

 
11,132

 
 
113,664

    Dorcheat Macedonia Field
 
4,914

 
3,458

 
1,281

 
480

 
6,195

 
3,938

 
 
97,798

    Other Mid-Continent
 
6,876

 
6,593

 
1,024

 
601

 
7,900

 
7,194

 
 
15,866

    Total
 
88,355

 
72,502

 
40,021

 
20,415

 
128,376

 
92,917

 
$
598,497

Undeveloped acreage
We critically review and consider at-risk leasehold with attention to our ability either to convert term leasehold to held-by-production status or obtain term extensions. We focus primarily on the core fields of development where reserve bookings are prevalent. Decisions to let leasehold expire generally relate to areas outside of our core fields of development or when the expirations do not pose material impacts to development plans or reserves.

21


The following table sets forth the number of net undeveloped acres by area as of December 31, 2017 that will expire over the next three years unless production is established within the spacing units covering the acreage or the applicable leases are extended prior to the expiration dates:
 
 
Expiring 2018
 
Expiring 2019
 
Expiring 2020
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Rocky Mountain
    
7,441

 
4,063

 
1,939

 
649

 
6,948

 
2,614

Mid-Continent
 
42

 
8

 
40

 
9

 
80

 
46

    Total
 
7,483

 
4,071

 
1,979

 
658

 
7,028

 
2,660

Drilling Activity
The following table describes the exploratory and development wells we drilled and completed during the years ended December 31, 2017, 2016, and 2015.
 
 
For the Years Ended December 31,
 
 
2017
 
2016
 
2015
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory
    
    
    
    
    
    
    
    
    
    
    
    
Productive Wells
 

 

 

 

 

 

Dry Wells
 

 

 

 

 
2

 
1.8

    Total Exploratory
 

 

 

 

 
2

 
1.8

Development
 
 
 
 
 
 
 
 
 
 
 
 
Productive Wells
 
4

 
4.0

 
4

 
3.9

 
92

 
76.1

Dry Wells
 

 

 

 

 
2

 
1.4

    Total Development
 
4

 
4.0

 
4

 
3.9

 
94

 
77.5

Total
 
4

 
4.0

 
4

 
3.9

 
96

 
79.3

The following table describes the present operated drilling activities as of December 31, 2017.
 
 
As of December 31, 2017
 
 
Gross
 
Net
Exploratory
    
    
    
    
Rocky Mountain
 

 

Mid-Continent
 

 

    Total Exploratory
 

 

Development
 
 
 
 
Rocky Mountain
 
14

 
9.1

Mid-Continent
 

 

    Total Development
 
14

 
9.1

Total
 
14

 
9.1

Capital Expenditure Budget
The Company contemplates running one rig in the first half of 2018 with a second rig added at mid-year. The capital budget for 2018 is expected to be approximately $280.0 million to $320.0 million, which will support drilling 90 gross wells and turning online 55 gross wells in 2018 all within the Rocky Mountain region. Of the wells planned to be drilled, approximately 43 are XRL wells, seven are MRL wells, and 40 are SRL wells. The costs of XRL, MRL, and SRL wells are anticipated to be $5.4 million, $4.2 million, and $3.0 million, respectively. Actual capital expenditures could vary significantly

22


based on, among other things, market conditions, commodity prices, drilling and completion costs, well results, and changes in the borrowing base under our successor credit facility.
Derivative Activity
In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control or predict. We attempt to mitigate a portion of our exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows through the use of derivative contracts. We have successfully hedged approximately 31% of our projected 2018 production.
As of December 31, 2017, the Company had entered into the following commodity derivative contracts:
 
 
Crude Oil
(NYMEX WTI)
 
Natural Gas
(NYMEX Henry Hub)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
1Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$42.00/$52.50
 
5,600

 
$2.75/$3.43
Swap
 
3,000

 
$53.20
 
6,000

 
$3.36
2Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$42.00/$52.50
 
5,600

 
$2.75/$3.43
Swap
 
3,000

 
$53.20
 

 
3Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
5,600

 
$2.75/$3.43
Swap
 
2,000

 
$51.96
 

 
4Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
5,600

 
$2.75/$3.43
Swap
 
2,000

 
$51.96
 

 
1Q19
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$54.53
 
2,600

 
$2.75/$3.40
Swap
 
1,000

 
$53.20
 

 
Q219
 
 
 
 
 
 
 
 
Cashless Collar
 
1,330

 
$44.01/$54.79
 
857

 
$2.75/$3.40
Swap
 
1,000

 
$53.20
 

 
Q319
 
 
 
 
 
 
 
 
Swap
 
2,000

 
$52.50
 

 
Q419
 
 
 
 
 
 
 
 
Swap
 
2,000

 
$52.50
 

 

23


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)
 
 
Bbls/day
 
Weighted Avg. Price per Bbl
 
MMBtu/day
 
Weighted Avg. Price per MMBtu
1Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$42.00/$52.50
 
5,600

 
$2.75/$3.43
Swap
 
3,172

 
$53.60
 
6,000

 
$3.36
2Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$42.00/$52.50
 
5,600

 
$2.75/$3.43
Swap
 
3,500

 
$54.26
 

 
3Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
5,600

 
$2.75/$3.43
Swap
 
3,000

 
$54.97
 

 
4Q18
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$53.50
 
5,600

 
$2.75/$3.43
Swap
 
2,000

 
$51.96
 

 
1Q19
 
 
 
 
 
 
 
 
Cashless Collar
 
2,000

 
$43.00/$54.53
 
2,600

 
$2.75/$3.40
Swap
 
1,000

 
$53.20
 

 
Q219
 
 
 
 
 
 
 
 
Cashless Collar
 
1,330

 
$44.01/$54.79
 
857

 
$2.75/$3.40
Swap
 
1,000

 
$53.20
 

 
Q319
 
 
 
 
 
 
 
 
Swap
 
2,000

 
$52.50
 

 
Q419
 
 
 
 
 
 
 
 
Swap
 
2,000

 
$52.50
 

 
Title to Properties
Our properties are subject to customary royalty interests, overriding royalty interests, obligations incident to operating agreements, liens for current taxes, other industry‑related constraints, and certain other leasehold restrictions. We do not believe that any of these burdens materially interfere with our use of 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 title review process upon receipt of title opinions received from outside legal counsel before we commence drilling operations. Although title to our properties is subject to complex interpretation of multiple conveyances, deeds, reservations, and other instruments that serve to affect mineral title, we believe that none of these risks will materially detract from the value of our properties or from our interest therein or otherwise materially interfere with the operation of our business.
Competition
The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that often have greater resources. Many of these companies explore for, produce, and market oil and natural gas, carry on refining operations, and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, attracting and retaining qualified personnel, and obtaining transportation for the oil and gas we produce in certain regions. There is also competition between producers of oil and gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by federal, state, and local governments; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing, or producing gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect and potential impacts of these risks are difficult to accurately predict.

24


Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 74% of our estimated proved reserves as of December 31, 2017 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. During the year ended December 31, 2017, the daily NYMEX WTI oil spot price ranged from a high of $60.46 per Bbl to a low of $42.48 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu.
Insurance Matters
As 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 not available or customary, or because premium costs are considered cost prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, or cash flows.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state, and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes, and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties or assets for oil and natural gas production have 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 of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, and regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements 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 are subject to the same regulatory requirements and restrictions that affect our operations. The regulatory burden on the industry can increase the cost of doing business and negatively affect profitability. Because such laws and regulations are frequently revised and amended through various legislative actions and rulemakings, it is difficult to predict the future costs or impact of compliance. Additional rulemakings that affect the oil and natural gas industry are regularly considered at the federal, state and various local government levels, including statutorily and through powers granted to various agencies that regulate our industry, and various court actions. We cannot predict when or whether any such rulemakings may become effective and if the outcomes will negatively affect our operations.
We believe that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen incidents may occur or past noncompliance with laws or regulations may be discovered.
Regulation of transportation of oil
Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”) be just and reasonable and non‑discriminatory and that such rates and terms and conditions 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 intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of natural gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

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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 currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (“NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation 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 as wholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased 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 for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed 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 and increases 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 provisions are 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 rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation more accessible to natural gas services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue 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 or practice 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 or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-market manipulation rule and enhanced civil penalty authority reflect 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 its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase 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 been affirmatively 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 that the 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 to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.
Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (“CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect

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our operations in any way that is of material difference from those 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 natural gas.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us 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 production
The 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 concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the spacing and unitization or pooling of oil and natural gas properties, the regulation of well spacing and well density, and procedures for proper plugging and abandonment of wells. The intent of these regulations is to promote the efficient recovery of oil and gas reserves while reducing waste and protecting correlative 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 exceptions to such regulations including applications to increase well densities to more effectively recover the oil and gas resources. Moreover, each state generally imposes a production 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 three U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposal of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, and the unitization and pooling of oil and gas properties.
Regulation of derivatives
The 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 to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users.
Environmental, Health and Safety Regulation
Our natural gas and oil exploration and production operations are subject to numerous stringent federal, regional, state and local laws and regulations governing safety and health, the discharge of materials into the environment or otherwise relating to protection of the environment or natural resources, noncompliance with which can result in substantial administrative, civil and criminal penalties and other sanctions, including suspension or cessation of operations. These laws and regulations may, among other things, require the acquisition of permits before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities that impact threatened or endangered species or that occur in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of investigation or remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker and natural resource protection and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filing obligations. Cumulatively, these laws and regulations may impact the 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 and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

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Hazardous substances and waste handling
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found 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 released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to 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 any liabilities 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, the individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent hazardous waste requirements, 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, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain natural 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 of Columbia that seeks to compel the EPA to review and, if necessary, revise its regulations regarding existing exemptions for exploration and production related wastes. On December 28, 2016, the EPA entered into a consent decree with those environmental groups to settle the lawsuit, which requires the EPA by March 15, 2019 to either propose new regulations regarding exploration and production related wastes or sign a determination that revision of such regulations is not necessary.
We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, exploration and production fluids and 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 these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes were not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed 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 petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxic Release Inventory (“TRI”) program under the Emergency Planning and Community Right-to-Know Act. EPA determined that natural gas processing facilities may be appropriate for addition to TRI applicable facilities and in January 2017, EPA issued a proposed rule to include natural gas processing facilities in the TRI program. EPA review of comments on this proposed rule is ongoing.
Pipeline safety and maintenance
Pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant penalties, liability for natural resources damages, 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 the development and implementation of pipeline integrity management programs, which include the

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inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.
There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. The Pipeline Safety, Regulatory Certainty, and Job Creation Act was signed into law in early 2012. In addition, 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 a number of ways, including through the increased regulation of gathering lines, even in rural areas. In 2016, PHMSA increased its regulations to require crude oil sampling and reporting as an offeror and increased its civil penalty structure.
Air emissions
The Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining required air permits can significantly delay the development of certain oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control 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 New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from certain pneumatic controllers and storage vessels. The EPA issued revised rules in 2013 and 2014 in response to requests for reconsideration of portions the 2012 NSPS and NESHAP rules from industry and the environmental community. As part of that reconsideration, in May 2016, the EPA issued revisions to the NSPS rules focused on achieving additional methane and volatile organic compound reductions from oil and natural gas operations. Among other things, these revisions impose new requirements for leak detection and repair, control requirements for oil well completions, and additional control requirements for gathering, boosting, and compressor stations. On May 26, 2017, the EPA announced a 90-day stay of certain portions of the NSPS standards, which stay was vacated by the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017. The EPA also proposed a two-year stay of the certain portions of the NSPS standards on June 12, 2017. In furtherance of this proposed stay, EPA released two notices of data availability that request information from industry in order to support the 2-year stay of certain requirements.
In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (AQCC) adopted new and revised air quality regulations that impose stringent new requirements to control emissions from both existing and new or modified oil and gas facilities in Colorado. The regulations include new emissions control, monitoring, recordkeeping, and reporting requirements on oil and gas operators in Colorado. For example, the regulations impose Storage Tank Emission Management (STEM) requirements for certain new and existing storage tanks. The STEM requirements require us to install costly emission control technologies as well as monitoring and recordkeeping programs at most of our new and existing well production facilities. The new Colorado regulations also impose a Leak Detection and Repair (LDAR) program for well production facilities and compressor stations. The LDAR program primarily targets hydrocarbon (i.e., methane) emissions from the oil and gas sector in Colorado and represents a significant 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”) for ozone 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 nonattainment areas, including in the DM/NFR area, may be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. The DM/NFR area is at risk of being reclassified to “serious” non-attainment if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from EPA. A “serious” classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements applicable to our operations and significant costs and delays in obtaining necessary permits for new and significantly modified production facilities. A recent decision by the U.S.

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Court of Appeals for the D.C. Circuit also raises the possibility that both the 2008 and 2015 ozone NAAQS will remain in effect for a period of years, further complicating our future compliance and operations in ozone non-attainment areas.
In May 2016, the EPA also finalized a rule regarding source determination, including defining the term “adjacent” under the CAA, which affects how major sources, are defined, particularly regarding criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major sources, thereby triggering more stringent air permitting requirements. These EPA rulemakings will have nominal effect on our operations because the rule clarified our existing presumption on “adjacent” and presents no conflict with the state of Colorado or Arkansas definitions.
The EPA also published Control Technique Guidelines (“CTGs”) in October 2016 aimed at providing states with guidance and setting a presumptive floor for Reasonably Achievable Control Technology (“RACT”) for the oil and gas industry in areas of ozone non-attainment, including the Denver Metro/North Front Range 8-hour Ozone Non-Attainment area (“DM/NFR area”). In November 2017, as required following issuance of the CTGs, the Colorado Air Quality Control Commission (AQCC) adopted additional RACT and other air quality regulations that increased emissions control, monitoring, recordkeeping, and reporting requirements on oil and gas operators in the 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 gas projects and increase our costs of development and production, which costs could be significant.
Climate change
Based on EPA findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA adopted regulations under the CAA that, among other things, established PSD, construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. In a subsequent ruling, the U.S. Supreme Court upheld a portion of EPA’s GHG stationary source program, but also invalidated a portion of it, holding that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, 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 to the 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 the applicable major source thresholds. In October 2016, EPA issued a proposed rule to further revise its PSD and Title V regulations applicable to GHGs in accordance with these court rulings, including a proposed de minimis level of GHG emissions below which BACT is not required. Depending an EPA’s final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations, and may also adversely affect demand 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 production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with 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, on April 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 Power Plan. The comment period on the proposed rule is open until April 26, 2018. Following the comment period, EPA is expected to release a final rule.
Congress has, from time to time, considered but not yet passed legislation to reduce emissions of GHGs. In addition, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG 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 United Nations climate change conference in Paris, France (the Paris Agreement). Within the Paris Agreement, the United States agreed to reduce its GHG emissions by 26-28% by the year 2025 as compared with 2005 levels, and provide periodic updates on its progress. On June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. Although President Trump has the authority to unilaterally withdraw the United States from the Paris Agreement, per the terms of the Agreement, such a withdrawal may not be made until three years from the

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effective date of the Agreement, which is November 4, 2019, and any such withdrawal only becomes effective one year after the notice of withdrawal is provided.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Severe limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.
Water discharges
The Federal Water Pollution Control Act or the Clean Water Act (“CWA”) and analogous state laws impose restrictions and controls regarding the discharge of pollutants into certain surface waters of the U.S., including spills and leaks of hydrocarbons and produced water. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge 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 SPCC plans and, where necessary, will develop or update such plans to implement physical and operation controls, the costs of which are not expected to be material. 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 governs which waters and wetlands are subject to the CWA. The scope of what areas constitute jurisdictional waters of the United States regulated under the CWA is currently the subject of ongoing litigation and related administrative proceedings that are not expected to be resolved for several years. Additionally, in June 2016, EPA finalized new 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 Act
The federal Endangered Species Act restricts activities that may affect endangered and threatened species or their habitats. A final rule amending how critical habitat is designated was finalized in 2016. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Employee health and safety
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes, the purpose of which are to protect the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard, naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens.
Hydraulic fracturing
Regulations relating to hydraulic fracturing. We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulic fracturing specifically are receiving increasing regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under 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 areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic 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 and disclosure of the chemicals used in fracturing.

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Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011 and 2013. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding wellbore integrity, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, and implement additional groundwater testing. In 2014, Colorado enacted legislation to increase the potential sanctions for statutory, regulatory and other violations. Among other things, this legislation and its implementing regulations mandate monetary penalties for certain types of violations, require a penalty to be assessed for each day of violation and significantly increase the maximum daily penalty amount. In early 2016, Colorado adopted rules imposing additional permitting requirements for certain large scale facilities in urban mitigation areas and additional notice requirements prior to engaging in operations near certain municipalities. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.
The federal Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids, primarily via disposal wells or enhanced oil recovery (“EOR”) wells, is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory or the state’s environmental authority. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for EOR is not excluded.
Federal agencies are also considering additional regulation of hydraulic fracturing. The EPA has published guidance for issuing underground injection permits that would regulate hydraulic fracturing using diesel fuel. This guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In addition, on October 21, 2011, the EPA announced its intention to propose regulations under the CWA to regulate wastewater discharges from hydraulic fracturing and other natural gas production. As noted above, in June 2016, EPA finalized regulations that address discharges of wastewater pollutants from onshore unconventional extraction facilities to publicly-owned treatment works. Regulated entities are required to come into compliance with these standards by August 29, 2019. The EPA also published a study of the impact of hydraulic fracturing on drinking water resources in December 2016, which concluded that drinking water resources can be affected by hydraulic fracturing under specific circumstances. The results of this study could result in additional regulations, which could lead to operational burdens similar to those described above. The EPA also has initiated a stakeholder and potential rulemaking process under the Toxic Substances Control Act (“TSCA”) to obtain data on chemical substances and mixtures used in hydraulic fracturing. The EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the potential TSCA rulemaking. As also noted above, in January 2017, the EPA issued a proposed rule to include natural gas processing facilities in the TRI program. The United States Department of the Interior also finalized a new rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. Additionally, in early 2016, the Bureau of Land Management (“BLM”) proposed rules related to further controlling the venting and flaring of natural gas on BLM land. The Department of the Interior (the parent department of BLM) announced in October 2017 that it would delay the effective dates of the BLM venting and flaring rules that were to become effective in January 2018. Recently, a Federal district court in Northern California granted a preliminary injunction to prevent BLM’s stay of those effective dates. The rule is currently in effect, but is also subject to ongoing litigation and rulemaking, which could result in a rescission or substantial rewrite.

Apart from these ongoing federal and state initiatives, local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Voters in Colorado have proposed or advanced initiatives restricting or banning oil and gas development in Colorado. Any successful bans or moratoriums where we operate could increase the costs of our operations, impact our profitability, and even prevent us from drilling in certain locations.
At this time, it is not possible to estimate the potential impact on our business of recent state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. The adoption of future federal, state or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.

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Our use of hydraulic fracturing. We use hydraulic fracturing as a means to maximize production of oil and gas from formations having low permeability such that natural flow is restricted. Fracture stimulation has been used for decades in both the Rocky Mountains and Mid-Continent.
Typical hydraulic fracturing treatments are made up of water, chemical additives and sand. We utilize major hydraulic fracturing service companies who track and report additive chemicals that are used in fracturing as required by the appropriate government agencies, including via the FracFocus, the national hydraulic fracturing chemical registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. Each of the service 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 potential environmental 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.
National Environmental Policy Act
Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an Environmental Assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. The vast majority of our exploration and production activities are not on federal lands. This environmental impact assessment process has the potential to delay or limit, or increase the cost of, the development of 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 Act
The 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 waters of 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 liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.
Other State Laws
Our properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission (the “COGCC”), as well as other state agencies. On August 22, 2017, Colorado Governor John Hickenlooper announced seven policy initiatives developed during the Colorado’s review of oil and gas operations. One rulemaking initiative resulting from Colorado’s review is a strengthening of COGCC’s flowline regulations and requirements. COGCC finalized the new flowline rules on February 19. 2018. The new rule includes: increased registration requirements, flowline design requirements, integrity management requirements, leak detection programs and requirements for abandoned flowlines. Over the past several years, the COGCC has also approved new rules regarding various other matters, including wellbore integrity, hydraulic fracturing, well control waste management, spill reporting, and an increase in potential sanctions for COGCC rule’s violations. Additionally, the COGCC approved rules regarding minimum setbacks, groundwater monitoring, large-scale facilities in urban mitigation areas, and public notice requirements that are intended to prevent or mitigate environmental impacts of oil and gas development and include the permitting of wells Depending on how these and any other new rules are applied, they could add substantial increases in well costs for our Colorado operations. The rules could also impact our ability and extend the time necessary to obtain drilling permits, which would create substantial uncertainty about our ability to meet future drilling plans and thus production and capital expenditure targets. The State of Colorado also created a task force to make recommendations for minimizing land use and other conflicts concerning the location of new oil and gas facilities. In early 2016, COGCC finalized a rulemaking to implement rules applicable to the permitting of large-scale oil and gas facilities in urban mitigation areas and

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rules requiring operators to register with and provide operational information to municipalities prior to conducting oil and gas operations with notice prior to engaging in certain 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 within their jurisdictional limits. Although we do not own or operate within any of these municipal areas, the Colorado Supreme Court decision has bearing on our ability to continue to operate in Colorado. Further, Weld County completed implementation of a revised local government permitting process for land use approval, and Boulder County is substantially revising its oil and gas regulations in conjunction with a permitting moratorium that is about to expire. We do not expect that these local government regulations will have any material impact on our operation.
Employees
As of December 31, 2017, we employed 156 people and also utilized the services of independent contractors to perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.
Offices
As of December 31, 2017, 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 field offices in Evans, Colorado and Magnolia, Arkansas.
Available information
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents 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 the operation 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 commercial document 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 other information 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 as reasonably practicable after we electronically file such material with the SEC. Information contained on our website, other than the documents listed below, is not incorporated by reference into this Annual Report on Form 10‑K.
Item 1A. Risk Factors.
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Risks Related to Our Business
Further declines, in oil and, to a lesser extent, natural gas prices, will adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations or targets and financial commitments.
The price we receive for our oil and, to a lesser extent, natural gas and NGLs, heavily influences our revenue, profitability, cash flows, liquidity, the borrowing base under our $191.7 million revolving credit facility (the “successor credit facility”), 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 are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. In recent years, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because approximately 74% of our estimated proved reserves as of December 31, 2017 were oil and NGLs, our financial results are more sensitive to movements in oil prices. Since mid-2014, the price of crude oil has significantly declined and has not regained previous highs. As a result, we experienced significant decreases in crude oil revenues and recorded asset

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impairment charges due to commodity price declines. A prolonged period of low market prices for oil, natural gas and NGLs, like the current commodity price environment, or further declines in the market prices for oil and natural gas, will result in capital expenditures being further curtailed and will adversely affect our business, financial condition and liquidity and our ability to meet obligations, targets or financial commitments. During the year ended December 31, 2017, the daily New York Mercantile exchange (“NYMEX”) WTI oil spot price ranged from a high of $60.46 per Bbl to a low of $42.48 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $3.71 per MMBtu to a low of $2.44 per MMBtu. As of March 9, 2018, the daily NYMEX WTI oil spot price and NYMEX natural gas HH spot price was $62.04 per Bbl and $2.73 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 and conditions in South America and Russia;
the level of global oil and natural gas exploration and production;
the level of global oil and natural gas inventories;
localized supply and demand fundamentals and transportation availability;
weather conditions and natural disasters;
domestic and foreign governmental regulations;
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
the price and availability of competitors’ supplies of oil and natural gas;
technological advances affecting energy consumption;
variability in subsurface reservoir characteristics, particularly in areas with immature development history;
the availability of pipeline capacity and infrastructure; and
the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under contracts at market-based prices. Declines in commodity prices may have the following effects on our business:
reduction of our revenues, profit margins, operating income and cash flows;
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically and may lead to reduced liquidity and the inability to pay our liabilities as they come due;
certain properties in our portfolio becoming economically unviable;
delay or postponement of some of our capital projects;
significant reductions in future capital programs, resulting in a reduced ability to develop our reserves;
limitations on our financial condition, liquidity and/or ability to finance planned capital expenditures and operations;
reduction to the borrowing base under our successor credit facility or limitations in our access to sources of capital, such as equity or debt;
declines in our stock price;
refinery industry demand for crude oil;

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storage availability for crude oil;
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 the price of oil and natural gas.
Oil and natural gas prices are volatile, and we currently have approximately 31% of our anticipated 2018 production hedged. As a result, some of our future production will be sold at market prices, exposing us to the fluctuations in the price of oil and natural gas, unless we enter into new hedging transactions. To the extent that the price of oil and natural gas decline below current levels, our results of operations and financial condition would be materially adversely impacted. See the Derivative Activity section in Part I, Item I of this Annual Report on Form 10-K for a summary of our hedging activity.
Due to reduced commodity prices and lower operating cash flows we may be unable to maintain adequate liquidity and our ability to make interest payments 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 continued depressed price environment caused a reduction in our available liquidity. We have substantial capital needs, including in connection with the continued development of our oil and gas assets. We may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to meet 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 as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect it against such occurrences. Consequently, it is possible that any of these occurrences, 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 our business 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 can be no assurance that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation 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, dated April 6, 2017 (the “reorganization plan”), we prepared projected financial

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information to demonstrate to the Bankruptcy Court the feasibility of the reorganization plan and our ability to continue operations upon emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy 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 were prepared, the projections reflected numerous assumptions concerning anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, 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 to fair value and our accumulated deficit was restated to zero. Accordingly, our future financial conditions and results of operations following our emergence are not comparable to the financial condition or results of operations reflected in our historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.
Upon emergence from bankruptcy, the composition of our board of directors changed significantly.
Pursuant to the reorganization plan, the composition of our board of directors changed significantly. Our board is made up of six directors, of which five had not previously served on our board. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our board and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.
The successor credit facility has restrictive covenants that could limit our growth and our ability to finance our operations, fund capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
The successor credit facility contains restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the successor credit facility is subject to compliance with certain financial covenants, including the maintenance of certain financial ratios, including a minimum current ratio, a maximum leverage ratio and a minimum interest coverage ratio. In addition, the successor credit facility contains covenants that, among other things, limit our ability:
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;
enter into sale-leaseback transactions;
consolidate, merge or transfer all or substantially all of our assets; and
engage in certain business activities.
     Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. We would not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness. As of the date of this Annual Report on Form 10-K, we are in compliance with all financial and non-financial covenants.

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We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in the successor credit facility. Our ability to comply with the financial ratios and financial condition tests under the successor credit facility may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in commodity prices, our business or the economy in general or otherwise conduct necessary corporate activities.
Borrowings under the successor credit facility are limited by our borrowing base, which is subject to periodic redetermination.
Beginning on April 1, 2018, the borrowing base under the successor credit facility will be redetermined at least semiannually and up to one additional time between scheduled determinations upon request of us or lenders holding 66 2/3% 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 to reduce 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 our outstanding borrowings at such time exceed the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing or sell significant 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, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Any significant 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 that can make a particular project uneconomical. Further, many factors, including, but not limited to, the following, may result in substantial losses, including personal injury or loss of life, penalties, damage or destruction of property and equipment, and curtailments, delays or cancellations of our scheduled drilling projects:
shortages of or delays in obtaining equipment and qualified personnel;
facility or equipment malfunctions;
unexpected operational events;
unanticipated environmental liabilities;
pressure or irregularities in geological formations;
adverse weather conditions, such as blizzards, ice storms, tornadoes, floods, and fires;
reductions in oil and natural gas prices;
delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays;
proximity to and capacity of transportation facilities;
title problems;
safety concerns; 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 be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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The process of estimating oil and natural gas reserves and the production possible from our oil and gas wells is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual 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 oil and natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2017, 2016 and 2015.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, and given the current volatility in pricing, such assumptions are difficult to make. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise particularly as they relate to state-of-the-art technologies being employed 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 recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K and our impairment charges. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
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 and natural 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 and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2017, 2016 and 2015, we based the estimated discounted future net 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 natural gas properties will be affected by factors such as:
actual prices we receive for oil and natural gas and hedging instruments;
actual cost of development and production expenditures;
the amount and timing of actual production;
the amount and timing of future development costs;
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 gas properties 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 based on 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 sustained decrease in prices for oil, natural gas and NGLs, we have taken write-downs of the 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 if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, from time to time, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. Oil, natural gas and NGL prices have significantly declined since mid-2014 and have not regained previous highs. Additionally, given the history of price volatility in the oil and natural gas

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markets, prices could remain depressed or decline further or other events may arise that would require us to record further impairments of the book values associated with oil and natural gas properties. Accordingly, we may incur significant impairment charges in the future which could have a material adverse effect on our results of operations and could reduce our earnings and stockholders’ equity for the periods in which such charges are taken.
We intend to pursue the further development of our properties in the Wattenberg Field through horizontal drilling. Horizontal drilling operations can 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 risk associated with a horizontal well drilling program. Risks associated with our horizontal drilling program include, but are not limited to, the following, any of which could 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 drilling zone;
effectively controlling the level of pressure flowing from particular wells;
staying in the desired drilling zone while drilling horizontally through the formation;
running our casing the entire length of the wellbore;
running tools and other equipment consistently through the horizontal wellbore;
fracture stimulating the planned number of stages;
preventing downhole communications with other wells;
successfully cleaning out the 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 profiles are 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 of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity or depressed natural gas and oil prices, the return on our investment 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 our oil 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 of water for our drilling operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.
The hydraulic fracture stimulation process on which we depend to produce commercial quantities of oil and natural gas requires the use and disposal of significant quantities of water. Our inability to secure sufficient amounts of water (including during times of droughts), or to dispose of or recycle the water used in our operations, could adversely impact our operations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, and all of which could have an adverse 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 adversely affect 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 adversely affect our development and exploration operations or cause us to incur significant expenditures that

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are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations and may lead to reduced liquidity and the inability to pay our liabilities as they come due.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on 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 capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. At this time, we intend to finance future capital expenditures primarily through cash flows provided by operating activities and borrowings under the successor credit facility. Declines in commodity prices coupled with our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional equity securities, debt securities or the strategic sale of assets. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal 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), our borrowing base under the successor credit facility would be reduced. The issuance of additional equity securities could have a dilutive effect on the value of our common stock.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
our proved reserves;
the amount of oil and natural gas we are able to produce from existing wells;
the prices at which our oil and natural gas are sold;
the costs of developing and producing our oil and natural gas production;
our ability to acquire, locate and produce new reserves;
the ability and willingness of our banks to lend; and
our ability to access the equity and debt capital markets.
    
If the borrowing base under the successor credit facility or if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations. If additional capital 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 under the successor credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our undeveloped leases and a decline in our oil 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 credit availability, 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, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling, render us unable to replace reserves and production and place us at a competitive disadvantage.
Concentration of our operations in a few core areas may increase our risk of production loss.
Our assets and operations are concentrated in two core areas: the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southern Arkansas. These core areas currently provide approximately 98% of our current sales volumes and the vast majority of our development projects.
The Wattenberg and Dorcheat Macedonia Fields represent 80% and19%, respectively, of our 2017 total sales volumes. Because our operations are not as diversified geographically as some of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: fluctuations in prices of crude oil, natural gas and NGLs produced from wells in the area, accidents or natural disasters, restrictive governmental regulations and curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide

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rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
We do not maintain business interruption (loss of production) insurance for our oil and gas producing properties. Loss of production or limited access to reserves in either of our core operating areas could have a significant negative impact on our cash flows and profitability.
We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues.
We do not operate all of the properties in which we have an interest. As a result, we may have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. For all of the properties that are operated by others, 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 wells in which we have an interest to adequately perform operations, or an operator’s breach of applicable agreements, could reduce production and revenues we receive from that well. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the timing and amount of capital expenditures, the available expertise and financial resources, the inclusion of other participants and the use of technology. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, revenues, production and related matters.
We are dependent on third party pipeline, trucking and rail systems to transport our production and, in the Wattenberg Field, gathering and processing systems to prepare our 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 could materially 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 gas markets or delay our production getting to market. The marketability of our oil and natural gas and production, particularly from our wells located in the Wattenberg Field, depends in part on the availability, proximity and capacity of gathering, processing, pipeline, trucking and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. 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, maintenance, weather, field labor issues or disruptions in service. Curtailments and disruptions in these systems may last from a few days to several months. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities or lack of availability of transport, would interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect our cash flow and results of operations, and the expected results of our drilling program.
Currently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara formation. In addition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this basin. If neither we nor a third party constructs the required pipeline system and processing facility, we may not be able to fully develop our resources in the North Park Basin.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 47% of our total proved reserves were classified as proved undeveloped as of December 31, 2017. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate or that may be available to us. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

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Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition 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 we conduct successful exploration and development activities or acquire properties containing proved reserves. Thus, our future oil and natural gas production and, therefore, our cash flow and income are highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured 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 oil and 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 other pollution into the environment, including soil, groundwater and shoreline contamination;
releases of natural gas and hazardous air pollutants or other substances into the atmosphere (including releases at our gas processing facilities);
hazards resulting from the presence of hydrogen sulfide (H2S) or other contaminants in natural gas we produce;
abnormally pressured formations resulting in well blowouts, fires or explosions;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
cratering (catastrophic failure);
downhole communication leading to migration of contaminants;
personal injuries and death; and
natural disasters.
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 brief periods from time to time at our well locations. Additionally, at one of our Arkansas properties, we produce a small amount of gas from four wells where we have identified the presence of H2S at levels that would be hazardous in the event of an uncontrolled gas release or unprotected exposure. In addition, our operations in Arkansas and Colorado are susceptible to damage from natural disasters such as flooding, wildfires, tornados and other natural phenomena and weather conditions, including extreme temperatures which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties.

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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 believe the 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 actual losses exceed coverage limits. Insurance costs will likely continue to increase which could result in our determination to decrease coverage and retain more risk to mitigate those cost increases. In addition, pollution and environmental risks generally are not fully insurable. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.
Because hydraulic fracturing activities are part of 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, we may not have coverage if the operator is unaware of the pollution event and unable to report the “occurrence” to the insurance company within the required 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 gathering systems and pipelines, we typically indemnify the drilling contractor for pollution emanating from the well, while the contractor indemnifies us against pollution 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 drilling locations 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 recover drilling 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 the study 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 or natural 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 requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures which 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 potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from 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 properties will likely be reduced. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields 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 the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial 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 to drill and develop these locations is subject to a number of uncertainties, including uncertainty in the level of reserves, the availability of capital to us and other participants, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, availability of permits, costs and drilling results. Because of these 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 or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped 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 be required to downgrade to probable or possible any proved undeveloped reserves that are not developed within this five-year time frame. These limitations 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 units containing 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 extension payment to extend the term of the lease. As of the filing date of this report, the majority of our acreage in Arkansas was held by unitization, production, or drilling operations and therefore not subject to lease expiration. As

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of the filing date of this report, approximately 10,425 net acres of our properties in the Rocky Mountain region were not held by production. For these properties, if production in paying quantities is not established on units containing these leases during the next year, then approximately 4,063 net acres will, unless otherwise extended, expire in 2018, approximately 649 net acres will expire in 2019, and approximately 5,713 net acres will expire in 2020 and thereafter. While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. It is 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 expired leases. 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 and financial condition. Title insurance covering mineral leasehold interests is not generally available. As is industry standard, we may rely upon a land professional’s careful examination of public records prior to purchasing or leasing a mineral interest. Once a mineral or leasehold interest has been acquired, we typically defer the expense of obtaining further title verification by a practicing title attorney until approval to drill that includes the acquired mineral interest is required. We perform the necessary curative work to correct deficiencies in the marketability of the title and we have compliance and control measures to ensure any associated business risk is approved by the appropriate Company authority. 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, as a result, the target area may be deemed to be undrillable until owners can be contacted and curative measures performed to adequately perfect title. In other cases, title deficiencies may result in our failure to have paid royalty owners correctly. Certain title deficiencies may also result in litigation to quiet the title and effectively agree or render a decision upon title ownership.
We face various risks associated with the long-term trend toward increased activism against oil and gas exploration and development activities.
Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling in the United 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 hydraulic fracturing fluids and produced water;
increased severance and/or other taxes;
cyber-attacks;
legal challenges or lawsuits;
negative publicity about us or the oil and gas industry in general;
increased costs of doing business;
reduction in demand for our products; and
other adverse effects on our ability to develop our properties and expand production.
We may need to incur significant costs associated with responding to these initiatives. Complying with any resulting additional legal or regulatory requirements that are substantial could have a material adverse effect on our business, financial condition and results of operations.

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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, the discharge of materials into the environment and the protection of the environment. These laws and regulations may impose on our operations numerous requirements, including the obligation to obtain a permit before conducting drilling 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 activities that impact threatened or endangered species or that occur on certain lands lying within wilderness, wetlands and other sensitive or protected areas; the application of specific health and safety criteria to protect workers; and the responsibility for cleaning up pollution resulting from operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, 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 our operations; delays in granting permits, or even the cancellation of leases.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions into air and water, the underground injection or other disposal of our wastes, the use and disposition 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 parties contributed to the release and the contaminants were released in compliance with all applicable laws then in effect. In addition, accidental spills or releases on 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 hydrocarbons or 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 with environmental laws and regulations, collect penalties for violations, or obtain damages for any related personal injury, or damage and property damage and certain trustees may seek natural resource damages. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that historic contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.
Evolving environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.
We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Governmental authorities frequently add to those requirements, and both oil and gas development generally, and hydraulic fracturing specifically, are receiving increasing regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.
In May 2016, the EPA issued amended New Source Performance Standards under the federal Clean Air Act (CAA). These regulations, known as “Quad Oa,” focused on achieving reductions in methane and volatile organic compound emissions at oil and natural gas operations. These rules, among other things, require leak detection and repair, additional control requirements for pneumatic controllers and pumps, and additional control requirements for oil well completions, gathering, boosting, and compressor stations. On May 26, 2017, the EPA announced a 90-day stay of certain portions of the Quad Oa standards, which stay was vacated in part by the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017. The EPA also proposed a two-year stay of the certain portions of the Quad Oa standards on June 12, 2017, which stay is currently under consideration and the court emphasized is not impacted by its July 3, 2017 decision. At this point, we cannot predict the cost to comply with such air regulatory requirements or the timing of their implementation.
On December 17, 2014, the EPA proposed to revise and lower the existing 75 ppb National Ambient Air Quality Standard (NAAQS) for ozone under the CAA to a range within 65-70 ppb. On October 1, 2015, EPA finalized a rule lowering the standard to 70 ppb. This lowered ozone NAAQS could result in an expansion of ozone nonattainment areas across the United States, including areas in which we operate. In a related development, in 2015, the State of Colorado received a bump-up to its existing ozone non-attainment status from “marginal” to “moderate.” This increase in status will result in additional requirements under the CAA for the State of Colorado and will include a state rulemaking to implement such requirements.

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This rulemaking process started in early 2017 and is ongoing. Oil and natural gas operations in ozone nonattainment areas may be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.
In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (AQCC) finalized regulations imposing strict new requirements relating to air emissions from oil and gas facilities in Colorado that are even more stringent than comparable federal rules. These new Colorado rules include storage tank control, monitoring, recordkeeping and reporting requirements as well as leak detection and repair requirements for both well production facilities and compressor stations and associated equipment. These new requirements, which represent the first time a state has directly regulated methane emissions from the upstream oil and gas sector, have and will continue to impose additional costs on our operations.
The EPA also published Control Technique Guidelines (CTGs) in October 2016 aimed at providing states with guidance and setting a presumptive floor for Reasonably Achievable Control Technology (RACT) for the oil and gas industry in areas of ozone non-attainment, including the Denver Metro/North Front Range 8-hour Ozone Non-Attainment area (DM/NFR area). In November 2017, in response to the recently published CTGS, the Colorado AQCC adopted additional air quality regulations that increased control, monitoring, recordkeeping, and reporting requirements on operations in the state.
Some activists have attempted to link hydraulic fracturing to various environmental problems, including potential adverse effects to drinking water supplies, migration of methane and other hydrocarbons into groundwater, and increased seismic activity. The federal government is studying the environmental risks associated with hydraulic fracturing and evaluating whether to adopt additional regulatory requirements. For example, the EPA has commenced a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources, which was finalized in December 2016 and concludes drinking water resources can be affected by hydraulic fracturing under specific circumstances. In addition, in 2011, the EPA announced its intention to propose regulations under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. EPA finalized these rules on June 28, 2016 and extended the compliance date for these rules until August 29, 2019. The EPA also has issued guidance for issuing underground injection permits for hydraulic fracturing operations that use diesel fuel under the agency’s Safe Drinking Water Act (SDWA) authority.
Moreover, the U.S. Department of the Interior finalized new rules for hydraulic fracturing activities on federal lands that, in general, would cover disclosure of fracturing fluid components, wellbore integrity, and handling of flowback water. The rule was stayed pending the outcome of litigation, but the 10th Circuit Court of Appeals dismissed the appeal from the decision vacating the rule and the underlying case on September 21, 2017 in light of the proposed rescission of those rules by the current administration. It is unclear whether the rule remains in effect, and industry groups have filed for a rehearing of the appeal. Responses to the rehearing requests were due on November 20, 2017. On December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. BLM’s rescission and the rule are also now the subject of ongoing litigation.
The BLM also proposed rules to address venting and flaring of methane on BLM land, which the U.S. House of Representatives has passed a bill to repeal, and the U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing. Additionally, Department of the Interior (the parent department of BLM) announced in October 2017 that it would delay the effectiveness of the BLM methane rules that were to become effective in January 2018. Recently, a Federal district court in Northern California granted a preliminary injunction to prevent BLM’s planned stay. The rule is currently in effect but is also subject to ongoing litigation and rulemaking, which could result in a rescission or substantial rewrite.
Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturing and other aspects of oil and gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011, 2014 and 2015. In early 2016, COGCC finalized a rulemaking to implement rules applicable to the permitting of large-scale oil and gas facilities in urban mitigation areas and rules requiring operators to register with and provide operational information to municipalities prior to conducting oil and gas operations with notice prior to engaging in certain operations. Colorado also finalized new rules regulating flowlines used in oil and gas operations on February 18, 2018. The new rules include: increased registration requirements, flowline design requirements, integrity management requirements, leak detection programs and requirements for abandoned flowlines.
In some instances certain local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Some counties in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. In addition, voters in Colorado have proposed or advanced ballot initiatives restricting or banning oil and gas development in Colorado. Because a substantial portion of our operations and reserves are located in

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Colorado, the risks we face with respect to such ballot initiatives are greater than other companies with more geographically diverse operations.
The adoption of future federal, state or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be material, and any such outcome could have a material adverse impact on our cash flows and results of operations.
Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing 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. Climate change 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, including negatively impacting the costs we incur in providing our products and services and the demand for and consumption of our products and services (due to potential changes in both costs and weather patterns).
In May 2016, the EPA promulgated rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements.
The EPA also adopted regulations requiring the reporting of GHG emissions from specific categories of higher GHG emitting sources in the United States, including certain oil and natural gas production facilities, which include certain of our operations. Information in such report may form the basis for further GHG regulation. Further, the EPA has continued with its comprehensive strategy for further reducing methane emissions from oil and gas operations, with a final rule being issued in May 2016 as part of “Quad Oa” discussed above. The EPA’s GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.
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, on April 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 Power Plan. The comment period on the proposed rule is open until April 26, 2018. Following the comment period, EPA is expected to release a final rule.
In the meantime, many states already have taken such measures, which have included renewable energy standards, development of GHG emission inventories or cap and trade programs. Cap and trade programs typically work by requiring major sources of emissions or major producers of fuels to acquire and 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 to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.
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 secure trained personnel.
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend heavily on our financial resources and ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies

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may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring 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 our operations. The volatility in commodity prices and business performance may affect our ability to retain senior management and the loss of these key employees may affect our business, financial condition and results of operations. These risks may be increased by the fact that we have not had a permanent chief executive officer since June 2017. 

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 in commodity prices and our business performance may affect our ability to incentivize and retain senior management or key employees. Competition for experienced senior management, technical and other professional personnel remains strong. Further, our ability to incentivize and retain senior management and key employees, as well as our ability to attract new senior management and key employees, may be harmed by the fact that we have not had a permanent chief executive officer since June 2017.

If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss 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 any of 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 may in the future enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not in the past designated any of our derivative instruments as hedges for accounting purposes and have recorded all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result 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 and may expose us to cash margin requirements.
We are exposed to credit risks of our hedging counterparties, third parties participating in our wells and our customers.
Our principal exposures to credit risk are through receivables resulting from commodity derivatives instruments, which were $0.5 million at December 31, 2017, joint interest and other receivables of $3.8 million at December 31, 2017 and the sale of our oil, natural gas and NGLs production of $28.5 million in receivables at December 31, 2017, 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 primarily based 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 of customers may impact our overall credit risk since these entities may be similarly affected by

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changes in economic and other conditions. For the year ended December 31, 2017, sales to NGL Crude Logistics, LLC, Lion Oil Trading & Transportation, Inc., and Duke Energy Field Services comprised 44%, 18%, and 16%, respectively, of our total sales. Beginning in 2017 and continuing for seven years, we have contracted to sell all of our crude oil produced for a one-rig program in the Wattenberg Field to NGL Crude Logistics, LLC.
We are exposed to credit risk in the event of default of our counterparty, principally with respect to hedging agreements but also insurance contracts and bank lending commitments. We do not require most of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.  Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter 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 of commodity 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 entities that 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 is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities 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 post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivative as a result of the Dodd-Frank Act and regulations, our results of operations may be more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
We may be involved in legal cases that may result in subst