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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year endedDecember 31, 2019
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)
Delaware61-1630631
(State or other jurisdiction of incorporation or organization)(I.R.S. employer identification number)
410 17th Street,Suite 1400
Denver,Colorado80202
(Address of principal executive offices)(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)(Trading Symbol)(Name of Exchange)
Common Stock, par value $0.01 per shareBCEINew 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 
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 
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  No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes  No ☐
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 FilerAccelerated Filer
Non-accelerated Filer
Smaller Reporting CompanyEmerging 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 
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  No ☐
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates on June 30, 2019, based upon the closing price of $20.88 of the registrant’s common stock as reported on the New York Stock Exchange, was approximately $429.9 million. Excludes approximately 44,463 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 February 24, 2020: 20,648,266
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, 2019, as incorporated by reference into Part III of this report for the year ended December 31, 2019.
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BONANZA CREEK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2019

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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 (the “Exchange Act”). 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. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements include statements related to, among other things:
the Company’s business strategies;
reserves estimates;
estimated sales volumes;
amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;
ability to modify future capital expenditures;
anticipated costs;
compliance with debt covenants;
ability to fund and satisfy obligations related to ongoing operations;
compliance with government regulations, including environmental, health, and safety regulations and liabilities thereunder;
adequacy of gathering systems and continuous improvement of such gathering systems;
impact from the lack of available gathering systems and processing facilities in certain areas;
impact of effectiveness of vapor control systems at central tank batteries;
natural gas, oil, and natural gas liquid prices and factors affecting the volatility of such prices;
impact of lower commodity prices;
sufficiency of impairments;
the ability to use derivative instruments to manage commodity price risk and ability to use such instruments in the future;
our drilling inventory and drilling intentions;
impact of potentially disruptive technologies;
our estimated revenue gains and losses;
the timing and success of specific projects;
our implementation of standard and long reach laterals;
our use of multi-well pads to develop the Niobrara and Codell formations;
intention to continue to optimize enhanced completion techniques and well design changes;
stated working interest percentages;
management and technical team;
outcomes and effects of litigation, claims, and disputes;
primary sources of future production growth;
full delineation of the Niobrara B, C, and Codell benches in our legacy, French Lake, and northern acreage;
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our ability to replace oil and natural gas reserves;
our ability to convert proved undeveloped reserves 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;
operational interruption of centralized gas and oil processing facilities;
competition in the oil and natural gas industry;
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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;
access to adequate gathering systems and pipeline take-away capacity;
our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for oil, natural gas, and natural gas liquids we produce, and to sell the oil, natural gas, and natural gas liquids at market prices;
costs and other risks associated with perfecting title for mineral rights in some of our properties;
continued hostilities in the Middle East, South America, and other sustained military campaigns or acts of terrorism or sabotage; and
other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact 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.
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“Basin.” A large natural depression on the earth’s surface in which sediments generally deposited via water accumulate.
“Completion.” The process of stimulating a drilled well followed by the installation of permanent equipment to allow for the production of crude oil and/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 acres.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development costs.” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing 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 vapor recovery systems.
“Development well.” A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to 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.
“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, laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
“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.
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“GAAP.” Generally accepted accounting principles in the United States.
“HH.” Henry Hub index.
“Gross Wells.” The total wells in which an entity owns a working interest.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a 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.
“LOE.” Lease operating expense.
“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 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.
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“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.
(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.
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(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 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 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.
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.
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“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.
“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 Rocky Mountain region of the United States. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the Denver-Julesburg (“DJ”) Basin. Bonanza Creek was incorporated in Delaware in 2010 and went public in 2011.
The Company's assets and operations are concentrated in the rural portions of unincorporated Weld County, Colorado, within the Wattenberg Field. We operate approximately 83% of all our productive wells, allowing us to control the pace, costs, and completion techniques used in the development of our reserves. The Wattenberg Field has a low cost structure, mature infrastructure, strong production efficiencies, multiple producing horizons, multiple service providers, established reserves, and prospective drilling opportunities, which helps facilitate predictable production and reserve growth.
The challenging commodity price environment that began in late 2014 and continued through 2017 improved marginally during 2018 and 2019. While commodity prices have improved slightly, they continue to be volatile. Nevertheless, we believe we remain well-positioned in this environment due to our healthy balance sheet, ample liquidity, inventory of economic drilling locations, low operating costs, and our operational flexibility, which allows us to respond to commodity price fluctuations. 
During 2019, we demonstrated our operational focus on achieving best-in-class execution by lowering our cost of operations on a per unit basis. We increased drilling efficiencies and improved well performance via enhanced completion designs, which contributed to the growth of our reserves and production. Additionally, we maintained our conservative balance sheet and retained a modest level of borrowings on our reserve-based credit facility, thereby providing substantial available liquidity. We intend to continue our operational focus in 2020, emphasizing responsible growth and development, cost control, and full-cycle returns, with the intent to achieve cash flow neutrality. We will continue to monitor the ongoing commodity price and regulatory environment and expect to retain the operational flexibility to adjust our drilling and completion plans in response to such conditions.
Our Business Strategies
The Company’s primary objective is to maximize shareholder returns by responsibly developing our oil and gas resources. We seek to accomplish this through development of existing inventory and value-accretive acquisition and divestiture activity. We seek to balance production growth with maintaining a conservative balance sheet. Key aspects of our strategy include:
Multi-well pad development across our leasehold. We believe horizontal development is the most efficient and safest way to recover the hydrocarbons located within our leasehold.
Enhanced completions. We continuously evaluate completion designs to increase well productivity and apply a multivariate regression analysis with the objective of optimizing economic returns. Petrophysical, geological, and geophysical analysis is used in conjunction with spacing evaluations and individualized well designs to increase value of each spacing unit.
Continuous safety improvement and strict adherence to health and safety regulations. Our goal is to utilize industry best practices to meet or exceed regulatory requirements and consistently engage stakeholders in our development planning and operations. We strive to maintain a safe workplace for our employees and contractors at all times.
Environmental stewardship. We constantly strive to control and reduce emissions and seek to comply with all applicable air quality and other environmental rules and regulations. We employ best practices, including pipeline gathering and takeaway as well as vapor recovery and leak detection equipment. Additionally, we work closely with our service providers to help ensure they stay in compliance with environmental regulations when operating on our behalf.
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Disciplined approach to acquisitions and divestitures. Opportunities are evaluated in the context of maintaining development flexibility and a healthy balance sheet. We pursue value-accretive acquisitions and strive to maximize scale and minimize financial and operational risk.
Prudent risk management. The Company believes a healthy balance sheet, focus on cost control, and minimizing long-term commitments are critical to controlling risk. A low debt profile and judicious use of hedging practices help reduce cash flow volatility. Continually striving to be a cost-efficient operator and maintaining a flexible capital spending program enable us to respond to changing market conditions.
Significant Developments in 2019
The Company further enhanced its gathering, treating, and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, by installing a new oil gathering line in 2019 to Riverside Terminal, which resulted in a corresponding $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. RMI provides many operational benefits to the Company and cost economies of a centralized system. The RMI system reduces gathering system pressures at the wellhead, thereby improving hydrocarbon recovery. Additionally, with eleven interconnects to four different natural gas processors, RMI helps ensure that the Company's production is not constrained by any single midstream service provider. Furthermore, the system reduces facility site footprints, leading to more cost-efficient operations and reduced surface disturbance. We will continue to look for ways to improve our access to gas gathering and processing services. The net book value of the Company's RMI assets was $147.8 million as of December 31, 2019.
The Company continued its 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 varied to ensure that thorough knowledge could be applied to future drilling programs. Fluid volumes and types, proppant volumes and types, stage spacing, well spacing, and flowback techniques were the primary variables that were tested throughout the 2019 program. The Company will continue to monitor industry trends, public data, and information from non-operated wells to further define optimum completion techniques. We deployed one rig throughout the majority of 2019 and temporarily discontinued our use of the rig in late 2019 in response to the weakening commodity price environment. Sales volumes increased by approximately 37% when comparing the fourth quarters of 2019 and 2018.
The Company's 2019 capital program came in below original guidance at $222.2 million, while production came in higher than the midpoint of original guidance at 23.5 MBoe per day. During 2019, the Company drilled 59 gross operated wells, completed 40 gross operated wells, turned to sales 45 gross operated wells, and participated in the drilling and completion of five gross non-operated wells.
The following table summarizes our estimated proved reserves as of December 31, 2019:
Natural    
CrudeNaturalGasTotal
OilGasLiquidsProved
Estimated Proved Reserves(MBbls)(MMcf)(MBbls)(MBoe)
Developed25,397  105,840  11,566  54,603  
Undeveloped39,016  106,360  10,595  67,338  
Total Proved64,413  212,200  22,161  121,941  
Total proved reserves as of December 31, 2019 increased by approximately 4% over the comparable period in 2018. 
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The following table summarizes our PV-10 reserve value, sales volumes, projected capital spend, and proved undeveloped drilling locations as of December 31, 2019:
Average Net DailyGross Proved
Estimated Proved Reserves atSales VolumesProjectedUndeveloped
December 31, 2019(1)
for the Year Ended2020 CapitalDrilling Locations
Total Proved% ProvedPV-10December 31, 2019Expendituresas of
(MBoe)Developed
($ in MM)(2)
(Boe/d)($ in millions)
December 31, 2019(3)
121,941  45 %$858.1  23,456  $215-235  274
_____________________
(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 $55.85 per Bbl WTI and $2.58 per MMBtu HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $4.63 per Bbl for crude oil and a decrease of $1.14 per MMBtu for natural gas.
(2)We believe that PV-10 provides useful and relevant information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies (specifically, the relative monetary significance of our 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)The Company has 402.0 standard reach lateral equivalent gross proved undeveloped drilling locations as of December 31, 2019.
Our Operations
During 2019, our operations were solely focused in the rural portions of the Wattenberg Field in the Rocky Mountain region. The Company sold all of its assets within the Mid-Continent region and North Park Basin on August 6, 2018 and March 9, 2018, respectively.
Rocky Mountain Region
Our Rocky Mountain Region consists of one operating area in the Wattenberg Field in Weld County, Colorado. As of December 31, 2019, our estimated proved reserves were 121,941 MBoe and contributed 23,456 Boe/d of sales volumes during 2019.
Wattenberg Field - Weld County, Colorado. Our operations are located in the rural portions of the oil and liquids-weighted extension area of the Wattenberg Field targeting the Niobrara and Codell formations. As of December 31, 2019, our Wattenberg position consisted of approximately 92,000 gross (67,000 net) acres.
The Niobrara and Codell formations are now primarily developed 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 currently being delineated.
As of December 31, 2019, we had a total of 678 gross producing wells, of which 539 were horizontal wells. Our sales volumes for the fourth quarter of 2019 were 24.3 MBoe per day. As of December 31, 2019, our working interest for all producing wells averaged approximately 79%, and our net revenue interest was approximately 64%.
We drilled and participated in drilling 91 gross (67.0 net) standard reach lateral (“SRL”) equivalent wells in 2019 in the Wattenberg Field. As of December 31, 2019, we have an identified drilling inventory of approximately 274 gross (188.5 net) proved undeveloped (“PUD”) drilling locations (402.0 gross SRL equivalents) on our acreage.
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The following table summarizes our drilling and completion activity for SRL wells, medium reach lateral wells (“MRL”), and extended reach laterals wells (“XRL”) on a gross basis for the year ended December 31, 2019.
SRLMRLXRL
DrilledCompletedDrilledCompletedDrilledCompleted
Niobrara - Operated35  13  —   23  19  
Codell - Operated—  —  —  —    
Niobrara - Non-operated  —  —    
North Park Basin - Jackson County, Colorado. We successfully sold all of our North Park assets on March 9, 2018 for minimal net proceeds and full release of all current and future obligations. Our North Park sales volumes for 2018, prior to the divestiture, were 10 Boe/d.
Mid-Continent Region
We successfully sold our Mid-Continent assets on August 6, 2018 for net proceeds of $103.5 million. We achieved a sales volume rate for 2018 of 1,728 Boe/d prior to the divestiture, or 10% of sales volume for 2018. At December 31, 2017, the Company had 300 gross producing vertical wells and proved reserves of approximately 10,419 MBoe.
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, 2019, 2018, and 2017 were determined using the preceding twelve month 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, 2019, 2018, and 2017. The proved reserve estimates as of December 31, 2019, 2018, and 2017 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our third-party independent reserve engineers. 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.
As of December 31,
Region/Field201920182017
(MMBoe)
Rocky Mountain121.9  116.8  90.5  
    Wattenberg 121.9   116.8  90.3  
    North Park —   —   0.2  
Mid-Continent —   —   11.5  
    Dorcheat Macedonia —   —   10.4  
    McKamie Patton —   —   1.1  
  Total 121.9   116.8   102.0  
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The following table sets forth more information regarding our estimated proved reserves at December 31, 2019, 2018, and 2017:
As of December 31,
201920182017
Reserve Data(1):
            
  Estimated proved reserves:
    Oil (MMBbls) 64.4  64.4  52.9  
    Natural gas (Bcf) 212.2  165.0  157.7  
    Natural gas liquids (MMBbls) 22.2  24.9  22.8  
      Total estimated proved reserves (MMBoe)(2)
 121.9  116.8  102.0  
      Percent oil and liquids 71 %76 %74 %
  Estimated proved developed reserves:
    Oil (MMBbls) 25.4  23.7  25.8  
    Natural gas (Bcf) 105.8  79.6  92.7  
    Natural gas liquids (MMBbls) 11.6  11.7  12.7  
      Total estimated proved developed reserves (MMBoe)(2)
 54.6  48.7  53.9  
      Percent oil and liquids 68 %73 %71 %
  Estimated proved undeveloped reserves:
    Oil (MMBbls) 39.0  40.6  27.1  
    Natural gas (Bcf) 106.4  85.4  65.0  
    Natural gas liquids (MMBbls) 10.6  13.2  10.1  
      Total estimated proved undeveloped reserves (MMBoe)(2)
 67.3  68.1  48.1  
      Percent oil and liquids 74 %79 %77 %
____________________
(1)Proved reserves were calculated using the preceding twelve month unweighted arithmetic average of the first-day-of-the-month prices, which were $55.85 per Bbl WTI and $2.58 per MMBtu HH, $65.56 per Bbl WTI and $3.10 per MMBtu HH, and $51.34 per Bbl WTI and $2.98 per MMBtu HH for the years ended December 31, 2019, 2018, and 2017, 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, 2019 reserve report are included in our development plan and are scheduled to be drilled within five years from the year they were initially recorded. The Company’s management evaluated the proved undeveloped drilling plan using the most recently supported type curves, NYMEX strip prices, the liquidation model for general and administrative costs, updated capital expenditures and lease operating costs to match revised bids and actuals from year-end. The reserve report factored in a one-and-a-half rig program starting in 2020 and increasing to a two-rig program in the second half of 2022, which results in all PUDs being drilled within the allotted five-year window. We typically book proved undeveloped locations within one development spacing area from developed producing locations. For the instances where a proved undeveloped location is beyond one spacing area from a developed producing location, we utilized reliable geologic and engineering technology. The reliable technologies used to establish our proved reserves are a combination of pressure performance, geologic mapping, offset productivity, electric logs, seismic, and production data.
As of December 31, 2019, we had 274.0 gross (402.0 SRL equivalents) proved undeveloped locations compared to 300.0 gross (444.5 SRL equivalents) for the comparable period in 2018. Of the total gross proved undeveloped locations at December 31, 2019, approximately 84% and 16% are scheduled to be drilled at 8-12 wells per section and 14+ wells per section, respectively. Wells per section are estimated based on equivalent spacing between wells for a 640-acre section.
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Total estimated proved reserves at December 31, 2019 increased 4% to 121.9 MMBoe when compared to December 31, 2018. The net increase in proved reserves of 5.1 MMBoe was the result of promoting 15.0 MMBoe of PUDs, adding 8.1 MMBoe of engineering revisions, adding 0.4 MMBoe of acquired reserves, adding 0.3 MMBoe of converted producing properties from unproven locations, offset by demoting 8.7 MMBoe of PUDs, producing 8.6 MMBoe of reserves, and removing 1.4 MMBoe due to reduced pricing.
The 15.0 MMBoe in PUD promotions was the result of converting 47 operated horizontal locations in the Niobrara and Codell formations in the Wattenberg Field to proved reserves during 2019 and adding infill and extension PUD locations due to the 2020 rig program. The 8.7 MMBoe of PUD demotions is due to those locations being removed from the five-year drilling program. The negative pricing revision of 1.4 MMboe resulted from a decrease in average commodity price from $65.56 per Bbl WTI and $3.10 per MMBtu HH for the year ended December 31, 2018 to $55.85 per Bbl WTI and $2.58 per MMBtu HH for the year ended December 31, 2019.
Reconciliation of Proved Reserves 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. 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, 2019, 2018, and 2017 (in millions):
December 31,
201920182017
PV-10$858.1  $955.0  $598.5  
Present value of future income taxes discounted at 10%(1)
  —  —  —  
Standardized Measure$858.1  $955.0  $598.5  
____________________________
(1) The tax basis of our oil and gas properties as of December 31, 2019, 2018 and 2017 provides more tax deduction than income generated from our oil and gas properties when the reserve estimates were prepared using $55.85 per Bbl WTI and $2.58 per MMBTU HH, $65.56 per Bbl WTI and $3.10 per MMBtu HH, and $51.34 per Bbl WTI and $2.98 per MMBtu HH, respectively.
Proved Undeveloped Reserves
Net Reserves (MBoe)
As of December 31, 2019
Beginning of year68,086  
Converted to proved developed(11,696) 
Additions from capital program15,040  
Removed from capital program(8,706) 
Acquisitions, net259  
Revisions4,355  
End of year67,338  
As of December 31, 2019, our proved undeveloped reserves were 67,338 MBoe, all of which are scheduled to be drilled within five years from the year they were initially recorded. During 2019, the Company converted 17% of its proved undeveloped reserves, which is comprised of 47 gross wells representing net reserves of 11,696 MBoe, at a cost of $178.2 million. The net increase of 15,040 MBoe in PUD additions is the result of adding 46 SRL and 8 XRL infill PUD locations in the areas that are captured in our five-year drilling program. The net decrease of 8,706 MBoe in PUD demotions is the result of removing 32 PUD locations as they were no longer part of our five-year drilling program.
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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, 2019, 2018, and 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 Engineer who has 15 years of experience in the oil and gas industry, including 3 years in their role at the Company. Their professional qualifications include a bachelor's degree in Chemical Engineering from the Colorado School of Mines.
Independent Reserve Engineers
The reserves estimates shown herein for December 31, 2019, 2018, and 2017 have been independently evaluated 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 G. 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, Geophysics (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in 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 fluctuated moderately during 2019. 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. During periods of favorable 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 0.3% and our PV-10 value as of December 31, 2019 would decrease by approximately 24% or $203.3 million. If oil and natural gas SEC prices increased by 10%, our proved reserve volumes would increase by 0.7% and our PV-10 value as of December 31, 2019 would increase by approximately 22% or $186.4 million.
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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.
SuccessorPredecessor
For the Year Ended December 31, 2019For the Year Ended December 31, 2018April 29, 2017 through December 31, 2017January 1, 2017 through April 28, 2017
Oil:    
Total Production (MBbls)5,135.9  3,840.8   2,012.7  1,068.5  
    Wattenberg Field5,135.9  3,500.2   1,568.5  834.4  
    Dorcheat Macedonia Field—  340.6   379.9  193.2  
Average sales price (per Bbl), including derivatives(3)
$52.12  $54.77  $46.44  $48.29  
Average sales price (per Bbl), excluding derivatives(3)
$51.89  $59.38  $47.18  $48.29  
Natural Gas:
Total Production (MMcf)11,966.8  8,591.2  5,767.5  3,242.5  
    Wattenberg Field11,966.8  7,408.3  4,588.1  2,564.9  
    Dorcheat Macedonia Field—  1,182.8  1,179.3  677.6  
Average sales price (per Mcf), including derivatives(4)
$2.10  $2.39  $2.29  $2.57  
Average sales price (per Mcf), excluding derivatives(4)
$2.06  $2.45  $2.29  $2.57  
Natural Gas Liquids:
Total Production (MBbls)1,431.1  1,141.2  712.9  422.7  
    Wattenberg Field1,431.1  1,048.3  656.2  391.1  
    Dorcheat Macedonia Field—  92.8  56.8  31.6  
Average sales price (per Bbl), including derivatives$11.22  $22.46  $18.38  $17.52  
Average sales price (per Bbl), excluding derivatives$11.22  $22.46  $18.38  $17.52  
Oil Equivalents:
Total Production (MBoe)8,561.5  6,413.8  3,686.9  2,031.6  
    Wattenberg Field8,561.5  5,783.2  2,989.4  1,653.0  
    Dorcheat Macedonia Field—  630.6  633.2  337.7  
Average Daily Production (Boe/d)23,456.2  17,572.0  15,048.4  16,930.4  
    Wattenberg Field23,456.2  15,844.0  12,201.5  13,774.9  
    Dorcheat Macedonia Field—  1,728.0  2,584.5  2,814.3  
Average Production Costs (per Boe)(1)(2)
$4.35  $7.11  $9.28  $8.20  
_________________________
(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. Total production volumes exclude volumes from our percentage-of-proceeds contracts in our Mid-Continent region of 65.0 MBoe, 77.9 MBoe, and 41.9 MBoe for the year ended December 31, 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the year ended December 31, 2019.
(3)Crude oil sales excludes $2.4 million, $0.6 million, $0.2 million, and $0.1 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively.
(4)Natural gas sales excludes $3.7 million, $1.3 million, $0.8 million, and $0.4 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively.

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Principal Customers
One of our customers, NGL Crude Logistics, LLC (“NGL Crude”) comprised 82% of our total revenue for the year ended December 31, 2019. No other single non-affiliated customer accounted for 10% or more of our oil and natural gas sales in 2019. We believe the loss of any one customer would not have a material effect on our financial position or results of operations because there are numerous potential customers for our product.
Delivery Commitments
The purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude became effective on April 28, 2017. The NGL Crude agreement includes defined volume commitments over an initial seven-year term. Under the terms of the NGL Crude agreement, the Company will be required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods beginning in January 2018. During 2018, the average minimum gross volume commitment was approximately 10,100 barrels per day, and the minimum gross volume commitment increased by approximately 41% from 2018 to 2019 and will increase approximately 3% each year thereafter for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term, based on the minimum gross volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $81.0 million as of December 31, 2019. Please refer to Part II, Item 8, Note 7 - 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, 2019.
Oil(2)
Natural Gas(1)
Total(2)
Operated(2)
GrossNetGrossNetGrossNetGrossNet
Rocky Mountain678  534.5  —  —  678  534.5  566  516.1  
__________________________
(1)All gas production is associated gas from producing oil wells.
(2)Count was obtained 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, 2019, along with the PV-10 value. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary.
Developed AcresUndeveloped AcresTotal Acres
GrossNetGrossNetGrossNetPV-10
Rocky Mountain66,808  55,423  24,823  11,317  91,631  66,740  $858.1  
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. Decisions to let leasehold expire generally relate to areas outside of our core area of development or when the expirations do not pose material impacts to development plans or reserves.
The following table sets forth the number of net undeveloped acres as of December 31, 2019 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 2020
Expiring 2021
Expiring 2022
GrossNetGrossNetGrossNet
Rocky Mountain7,490  2,669  3,203  1,880  938  1,448  
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Drilling Activity
The following table sets forth the exploratory and development wells completed (operated and non-operated) during the years ended December 31, 2019, 2018, and 2017.
For the Years Ended December 31,
201920182017
GrossNetGrossNetGrossNet
Exploratory                        
Productive Wells—  —  —  —  —  —  
Dry Wells—  —  —  —  —  —  
    Total Exploratory—  —  —  —  —  —  
Development
Productive Wells45  34.1  56  43.8  36  16.0  
Dry Wells—  —  —  —  —  —  
    Total Development45  34.1  56  43.8  36  16.0  
Total45  34.1  56  43.8  36  16.0  
The following table describes the present operated drilling activities as of December 31, 2019.
As of December 31, 2019
GrossNet
Exploratory—  —  
Development42  32.6  
Total42   32.6  
Capital Expenditure Budget
The Company's 2020 capital budget of $215 million to $235 million assumes the continuation of a one-rig operated program in the Company's legacy acreage and the startup of a one-rig non-operated program in the Company's French Lake area in late 2020. The Company's 2020 capital expenditures guidance includes $20 million to $25 million for non-operated capital, which includes approximately $10 million to $15 million for French Lake. The budget includes the drilling of 61 gross wells, completion of 45 gross wells, and turning to sales of 62 gross wells. Actual capital expenditures could vary significantly based on, among other things, changes in the operator’s development pace in French Lake, market conditions, commodity prices, drilling and completion costs, well results, and changes in the borrowing base under our Credit Facility (defined below).
Derivative Activity
In addition to supply and demand, oil and gas prices are affected by seasonal, economic, local and geo-political factors that we can neither control nor 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. Oil revenue represented approximately 85% of our oil and gas sales in 2019. We have successfully hedged approximately 57% and 58% of our average 2020 guided oil production as of December 31, 2019 and as of the filing date of this report, respectively.
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As of December 31, 2019, the Company had entered into the following commodity derivative contracts:
Crude Oil
(NYMEX WTI)
Natural Gas
(NYMEX Henry Hub)
Natural Gas
(CIG Basis)
Natural Gas
(CIG)
Bbls/day  Weighted Avg. Price per BblMMBtu/day  Weighted Avg. Price per MMBtu  MMBtu/day  Weighted Avg. Price per MMBtu  MMBtu/day  Weighted Avg. Price per MMBtu  
1Q20
Cashless Collar5,000  
$55.00/$62.88
—  —  —  —  —  —  
Swap4,500  $60.69  20,000  $2.63  20,000  $0.56  2,500  $2.40  
2Q20
Cashless Collar7,500  
$54.00/$61.01
—  —  —  —  —  —  
Swap1,500  $54.98  10,000  $2.61  20,000  $0.56  —  —  
3Q20
Cashless Collar6,000  
$52.67/$58.40
—  —  —  —  —  —  
Swap3,000  $53.60  —  —  20,000  $0.56  —  —  
4Q20
Cashless Collar6,000  
$52.67/$58.40
—  —  —  —  —  —  
Swap3,000  $53.60  —  —  20,000  $0.56  —  —  
1Q21
Cashless Collar2,000  
$50.50/$55.19
—  —  —  —  —  —  
Swap3,500  $53.89  —  —  —  —  —  —  
2Q21
Cashless Collar500  
$52.00/$55.00
—  —  —  —  —  —  
Swap2,000  $53.35  —  —  —  —  —  —  
3Q21
Swap1,000  $54.87  —  —  
As of the filing date of this report, the Company had entered into the following commodity derivative contracts:
Crude Oil
(NYMEX WTI)
Natural Gas
(NYMEX Henry Hub)
Natural Gas
(CIG Basis)
Natural Gas
(CIG)
Bbls/day  Weighted Avg. Price per BblMMBtu/day  Weighted Avg. Price per MMBtu  MMBtu/day  Weighted Avg. Price per MMBtu  MMBtu/day  Weighted Avg. Price per MMBtu  
1Q20
Cashless Collar5,000  
$55.00/$62.88
—  —  —  —  —  —  
Swap4,500