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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, 2020
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. 
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, 2020, based upon the closing price of $14.82 of the registrant’s common stock as reported on the New York Stock Exchange, was approximately $271.4 million. Excludes approximately 2.5 million 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 15, 2021: 20,839,227
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, 2020, as incorporated by reference into Part III of this report for the year ended December 31, 2020.
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BONANZA CREEK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2020

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 (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 any pandemic or other public health epidemic, including the ongoing COVID-19 pandemic;
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;
the expected timetable for completing the announced merger of the Company with HighPoint Resources Corporation (the “Transaction”), the results, effects, benefits and synergies of the Transaction, future opportunities for the combined company, other plans and expectations with respect to the Transaction, and the anticipated impact of the Transaction on the combined company’s results of operations, financial position, growth opportunities and competitive position; 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;
the effects of disruption of our operations or excess supply of oil and natural gas due to the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;
the scope, duration and severity of the COVID-19 pandemic, including any recurrence, as well as the timing of the economic recovery following the pandemic;
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;
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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;
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.
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“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.
“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 price 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.
“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
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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.
“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.
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“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.
(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.
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(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 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.
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“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.
“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 an independent Denver-based exploration and production company focused on the acquisition, development, and extraction of oil and associated liquids-rich natural gas in the United States. The Company's oil and liquids-weighted assets and operations are concentrated in the rural portions of the Wattenberg Field in Colorado. Our development and extraction activities are primarily directed at the horizontal development of the Niobrara and Codell formations in the Denver-Julesburg (“DJ”) Basin. The majority of our revenues are generated through the sale of oil, natural gas, and natural gas liquids production.
We operate approximately 84% 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.
Although commodity prices have improved slightly over the last few months, the challenging commodity price environment continues to be volatile. Nevertheless, we believe we remain well-positioned in this environment due to our debt-free 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 2020, 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 paid our reserve-based credit facility to a zero balance, thereby providing substantial available liquidity. We intend to continue our operational focus in 2021, emphasizing responsible growth and development, cost control, and full-cycle returns, with the intent to achieve positive cash flow. 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 our production base while achieving positive cash flow. Key aspects of our strategy include:
Multi-well pad development across our leasehold. We believe horizontal development is the most efficient, environmentally responsible, 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, positive cash flows, 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.
The Company is also committed to continuously improving its environment, social, and governance (“ESG”) performance. We work to identify and implement opportunities to minimize our environmental impact. In addition to employing best practices to reduce emissions, generally, our efforts include monitoring and reducing greenhouse gas emissions, and evaluating the risks and opportunities that climate change may present to our business and incorporating them into our business strategy. We invest in our employees by providing regular annual safety training for all employees, hands-on safety training for field employees, and opportunities for professional development across the organization. The Company also plans to conduct regular shareholder outreach efforts focused on a variety of topics, including executive compensation and other ESG issues.
As a further step in these efforts, our Board of Directors recently approved the restructuring of its EHS&RC and Reserves Committee to become its new “ESG Committee.” The ESG Committee will be responsible for overseeing and supporting the Company’s commitment to environmental, health, and safety, social responsibility, sustainability, and other public policy matters relevant to the Company. (Responsibility for oversight of the Company’s processes for estimating and reporting its proved reserves will shift to the Board’s Audit Committee.) The ESG Committee will assist senior management in setting the Company’s general strategy relating to ESG matters and in developing, implementing, and monitoring initiatives and policies based on that strategy.
Significant Developments in 2020
On November 9, 2020, the Company and HighPoint Resources Corporation (“HighPoint”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), providing for our acquisition of HighPoint (the “HighPoint Acquisition”). The strategic combination will result in the Company being the leading unconventional oil producer in rural Weld County, significantly increase free cash flow, and maintain economic resilience. The preliminary merger consideration is expected to be $337.4 million, consisting of a combination of the issuance of shares of our common stock and senior notes. The transaction is expected to close in the first half of 2021, contingent upon a number of factors disclosed in the Merger Agreement.
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 development programs. Fluid volumes and types, fluid rates, proppant volumes and types, stage spacing, perforation architecture, lateral spacing, and flowback techniques were the primary variables that were tested throughout the 2020 program. Along with extensive internal evaluation, the Company will also continue to monitor industry trends, public data, and information from non-operated wells to further define optimum completion techniques. We deployed one rig in the beginning of 2020 and temporarily discontinued our use of the rig in response to the weakening commodity price environment starting in March 2020. Nevertheless, sales volumes increased by approximately 3% when comparing the fourth quarters of 2020 and 2019.
The Company's 2020 capital program and production came in within guidance at $67.7 million and 25.2 MBoe per day, respectively. During 2020, the Company drilled 14 gross operated wells, completed 9 gross operated wells, turned to sales 26 gross operated wells, and participated in the drilling of 11 gross non-operated wells.
The Company's gathering, treating, and production facilities, maintained under its Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, provide many operational benefits to the Company and cost economies of a centralized system. Additionally, in 2019, the Company installed a new oil gathering line to Riverside Terminal (on the Grand Mesa Pipeline), which resulted in a corresponding $1.25 to $1.50 per barrel reduction to our oil differentials for barrels transported on such gathering line. The total value of reduced oil differentials during the year ended December 31, 2020 was approximately $6.2 million.
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The following table summarizes our estimated proved reserves as of December 31, 2020:
Crude OilNatural GasNatural Gas LiquidsTotal Proved
Estimated Proved Reserves(MBbls)(MMcf)(MBbls)(MBoe)
Developed24,320 123,220 14,315 59,172 
Undeveloped28,473 112,508 11,796 59,020 
Total Proved52,793 235,728 26,111 118,192 
Total proved reserves as of December 31, 2020 decreased by approximately 3% over the comparable period in 2019.    
The following table summarizes our PV-10 reserve value, sales volumes, projected capital spend, and proved undeveloped drilling locations as of December 31, 2020:
Average Net DailyGross Proved
Estimated Proved Reserves atSales VolumesProjectedUndeveloped
December 31, 2020(1)
for the Year EndedQ1 2021 CapitalDrilling Locations
Total Proved% ProvedPV-10December 31, 2020
Expenditures(4)
as of
(MBoe)Developed
($ in MM)(2)
(Boe/d)($ in millions)
December 31, 2020(3)
118,192 50 %$437.1 25,242 $35.0 - 40.0216
_____________________
(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 $39.57 per Bbl WTI and $1.99 per MMBtu HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $4.61 per Bbl for crude oil and a decrease of $1.04 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 297.5 standard reach lateral equivalent gross proved undeveloped drilling locations as of December 31, 2020.
(4)The Company is providing guidance for the first quarter of 2021 for Bonanza Creek as a stand-alone company. Additional guidance for 2021 on a combined basis will be provided after the closing of the HighPoint Acquisition.
Our Operations
During 2020, our operations were solely focused in the rural portions of the Wattenberg Field in the Rocky Mountain region in Weld County, Colorado, targeting the Niobrara and Codell formations. As of December 31, 2020, our Wattenberg position consisted of approximately 87,000 gross (65,000 net) acres, and our estimated proved reserves were 118,192 MBoe and contributed 25,242 Boe per day of sales volumes during 2020.
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 still being delineated.
As of December 31, 2020, we had a total of 758 gross producing wells, of which 575 were horizontal wells. Our sales volumes for the fourth quarter of 2020 were 25,029 Boe per day. As of December 31, 2020, our working interest for all productive wells averaged approximately 80%, and our net revenue interest was approximately 66%.
We drilled and participated in drilling 25 gross (13.9 net) standard reach lateral (“SRL”) equivalent wells in 2020 in the Wattenberg Field. As of December 31, 2020, we have an identified drilling inventory of approximately 216 gross (141.0 net) proved undeveloped (“PUD”) drilling locations (297.5 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, 2020.
SRLMRLXRL
DrilledCompletedDrilledCompletedDrilledCompleted
Niobrara – Operated
14 — — — 
Codell – Operated
— — — — — — 
Niobrara – Non-operated
10 — — — — — 
Codell – Non-operated
— — — — — 
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, 2020, 2019, and 2018 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. 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.
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The table below sets forth information regarding our estimated proved reserves, all of which is located in the Wattenberg Field in the Rocky Mountain region, as of December 31, 2020, 2019, and 2018. The proved reserve estimates were prepared by third-party independent reserve engineers Ryder Scott Company, LP. (“Ryder Scott”) as of as of December 31, 2020 and by Netherland, Sewell & Associates, Inc. (“NSAI”) as of December 31, 2019 and 2018. 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,
202020192018
Reserve Data(1):
            
  Estimated proved reserves:
    Oil (MMBbls) 52.8 64.4 64.4 
    Natural gas (Bcf) 235.7 212.2 165.0 
    Natural gas liquids (MMBbls) 26.1 22.2 24.9 
      Total estimated proved reserves (MMBoe)(2)
 118.2 121.9 116.8 
      Percent oil and liquids 67 %71 %76 %
  Estimated proved developed reserves:
    Oil (MMBbls) 24.3 25.4 23.7 
    Natural gas (Bcf) 123.2 105.8 79.6 
    Natural gas liquids (MMBbls) 14.3 11.6 11.7 
      Total estimated proved developed reserves (MMBoe)(2)
 59.2 54.6 48.7 
      Percent oil and liquids 65 %68 %73 %
  Estimated proved undeveloped reserves:
    Oil (MMBbls) 28.5 39.0 40.6 
    Natural gas (Bcf) 112.5 106.4 85.4 
    Natural gas liquids (MMBbls) 11.8 10.6 13.2 
      Total estimated proved undeveloped reserves (MMBoe)(2)
 59.0 67.3 68.1 
      Percent oil and liquids 68 %74 %79 %
____________________
(1)Proved reserves were calculated using the preceding twelve month unweighted arithmetic average of the first-day-of-the-month prices, which were $39.57 per Bbl WTI and $1.99 per MMBtu HH, $55.85 per Bbl WTI and $2.58 per MMBtu HH, and $65.56 per Bbl WTI and $3.10 per MMBtu HH for the years ended December 31, 2020, 2019, and 2018, 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, 2020 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 completion rig working through our DUC inventory starting in 2021 and increasing to a one-and-a-half rig full drilling program starting in 2022, which results in all PUDs being on production within the allotted five-year window. Generally, the Company books 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, the Company utilized reliable geologic and engineering technology inclusive of, but not limited to, pressure performance, geologic mapping, offset productivity, electric logs, seismic, and production data.
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As of December 31, 2020, we had 216 gross (297.5 SRL equivalents) proved undeveloped locations compared to 274 gross (402.0 SRL equivalents) for the comparable period in 2019. Of the total gross proved undeveloped locations at December 31, 2020, approximately 85% and 15% 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.
Total estimated proved reserves at December 31, 2020 decreased 3.7 MMBoe, or 3%, to 118.2 MMBoe when compared to December 31, 2019. A summary of the Company's changes in quantities of proved reserves for the year ended December 31, 2020 is as follows:
Net Reserves (MBoe)
Beginning of year121,941 
Extensions and discoveries18,007 
Production(9,239)
Sales of minerals in place— 
Removed from capital program(22,908)
Purchases of minerals in place2,910 
Revisions to previous estimates7,481 
End of year118,192 
The 18.0 MMBoe in PUD promotions was the result of converting 76 horizontal locations in the Niobrara formation in the Wattenberg Field to proved reserves during 2020 due to the 2021-2025 drilling program. The 22.9 MMBoe of PUD demotions is due to those locations being removed from the five-year drilling program. The positive revision to previous estimates of 7.5 MMBoe is the result of adding 12.3 MMBoe of engineering revisions offset by a pricing revision of 4.8 MMBoe resulting from a decrease in average commodity price from $55.85 per Bbl WTI and $2.58 per MMBtu HH for the year ended December 31, 2019 to $39.57 per Bbl WTI and $1.99 per MMBtu HH for the year ended December 31, 2020.
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 nor the Standardized Measure purports 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, 2020, 2019, and 2018 (in millions):
December 31,
202020192018
PV-10$437.1 $858.1 $955.0 
Present value of future income taxes discounted at 10%(1)
  — — — 
Standardized Measure$437.1 $858.1 $955.0 
____________________________
(1) The tax basis of our oil and gas properties as of December 31, 2020, 2019, and 2018 provides more tax deduction than income generated from our oil and gas properties when the reserve estimates were prepared using $39.57 per Bbl WTI and $1.99 per MMBtu HH, $55.85 per Bbl WTI and $2.58 per MMBtu HH, and $65.56 per Bbl WTI and $3.10 per MMBtu HH, respectively.
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Proved Undeveloped Reserves
Net Reserves (MBoe)
As of December 31, 2020
Beginning of year67,338 
Converted to proved developed(8,023)
Additions from capital program18,007 
Removed from capital program(22,908)
Acquisitions, net1,834 
Revisions2,772 
End of year59,020 
As of December 31, 2020, our proved undeveloped reserves were 59,020 MBoe, all of which are scheduled to be drilled within five years from the year they were initially recorded. During 2020, the Company converted 12% of its proved undeveloped reserves, which is comprised of 26 gross wells representing net reserves of 8,023 MBoe, at a cost of $42.3 million. The net increase of 18,007 MBoe in PUD additions is the result of adding 48 SRL and 28 XRL PUD locations in the areas that are captured in our five-year drilling program. The net decrease of 22,908 MBoe in PUD demotions is the result of removing 117 PUD locations as they were no longer part of our five-year drilling program. The acquisition of 1,834 MBoe in net PUD volumes is the result of adding 9 SRL PUD locations to be captured in our five-year drilling program.
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 are engaged by and have direct access to the Reserves Committee. The reserves estimates shown herein have been independently prepared by Ryder Scott for the year ended December 31, 2020 and by NSAI for the years ended December 31, 2019 and 2018. These reserve estimates are reviewed by our in-house petroleum engineer who oversees and controls preparation of the reserve report data by working with our third-party independent reserve engineers to ensure the integrity, accuracy, and timeliness of data furnished for their evaluation process. The Company's technical person who was primarily responsible for overseeing the preparation of our reserve estimates was our Manager, Reserves Engineering, who has 16 years of experience in the oil and gas industry, including 4 years in her role at the Company. Her 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, 2020 have been independently evaluated by Ryder Scott, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Ryder Scott was founded in 1937 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1580. Within Ryder Scott, the technical person primarily responsible for preparing the estimates set forth in the Ryder Scott reserves report incorporated herein is Scott Wilson. Scott Wilson, a Licensed Professional Engineer in the State of Colorado (No. 36112), has been practicing consulting petroleum engineering at Ryder Scott since 2000 and has over 35 years of industry experience. He graduated from Colorado School of Mines in 1983 with a Bachelor of Science in Petroleum Engineering and from the University of Colorado in 1985 with a Master's of Business Administration. The responsible party meets or exceeds 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 and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
The reserves estimates shown herein for December 31, 2019 and 2018 were 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 were 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 the University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from
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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 significantly during 2020. 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 global demand. 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 2% and our PV-10 value as of December 31, 2020 would decrease by approximately 27% or $117.6 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, 2020 would increase by approximately 27% or $119.3 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.
For the Year Ended December 31,
202020192018
Oil:    
Total Production (MBbls)5,019.4 5,135.9 3,840.8 
    Wattenberg Field5,019.4 5,135.9 3,500.2 
    Dorcheat Macedonia Field— — 340.6 
Average sales price (per Bbl), including derivatives(3)
$44.41 $52.12 $54.77 
Average sales price (per Bbl), excluding derivatives(3)
$34.42 $51.89 $59.38 
Natural Gas:
Total Production (MMcf)14,165.7 11,966.8 8,591.2 
    Wattenberg Field14,165.7 11,966.8 7,408.3 
    Dorcheat Macedonia Field— — 1,182.8 
Average sales price (per Mcf), including derivatives(4)
$1.40 $2.10 $2.39 
Average sales price (per Mcf), excluding derivatives(4)
$1.45 $2.06 $2.45 
Natural Gas Liquids:
Total Production (MBbls)1,858.2 1,431.1 1,141.2 
    Wattenberg Field1,858.2 1,431.1 1,048.3 
    Dorcheat Macedonia Field— — 92.8 
Average sales price (per Bbl), including derivatives$10.39 $11.22 $22.46 
Average sales price (per Bbl), excluding derivatives$10.39 $11.22 $22.46 
Oil Equivalents:
Total Production (MBoe)9,238.6 8,561.5 6,413.8 
    Wattenberg Field9,238.6 8,561.5 5,783.2 
    Dorcheat Macedonia Field— — 630.6 
Average Daily Production (Boe/d)25,242 23,456 17,572 
    Wattenberg Field25,242 23,456 15,844 
    Dorcheat Macedonia Field— — 1,728 
Average Production Costs (per Boe)(1)(2)
$4.00 $4.35 $7.11 
_________________________
(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 for the year ended December 31, 2018. The Mid-Continent region assets were sold August 6, 2018, and therefore, no sales volumes were associated with the Mid-Continent region during the years ended December 31, 2020 and 2019.
(3)Crude oil sales excludes $1.7 million, $2.4 million, and $0.6 million of oil transportation revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2020, 2019, and 2018, respectively.
(4)Natural gas sales excludes $3.7 million, $3.7 million, and $1.3 million of gas gathering revenues from third parties, which do not have associated sales volumes, for the years ended December 31, 2020, 2019, and 2018, respectively.

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Customers
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 Company is party to a purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude. The NGL Crude agreement includes defined volume commitments over a term ending in 2023. Under the terms of the NGL Crude agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. The minimum gross volume commitment will increase approximately 3% each year 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 is $49.7 million as of December 31, 2020. 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 productive oil and natural gas wells in which we owned a working interest at December 31, 2020.
Oil
Natural Gas(1)
TotalOperated
GrossNetGrossNetGrossNetGrossNet
Rocky Mountain758 608.0 — — 758 608.0 633 579.3 
__________________________
(1)All gas production is associated gas from producing oil wells.
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, 2020, along with the PV-10 value. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary.
Developed AcresUndeveloped AcresTotal AcresPV-10
GrossNetGrossNetGrossNet(in millions)
Rocky Mountain81,460 61,223 5,632 3,705 87,092 64,928 $437.1 
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, 2020 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 2021
Expiring 2022
Expiring 2023
GrossNetGrossNetGrossNet
Rocky Mountain3,843 1,859 1,347 1,356 162 297 
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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, 2020, 2019, and 2018.
Year Ended December 31,
202020192018
GrossNetGrossNetGrossNet
Exploratory                        
Productive Wells— — — — — — 
Dry Wells— — — — — — 
    Total Exploratory— — — — — — 
Development
Productive Wells8.5 45 34.1 56 43.8 
Dry Wells— — — — — — 
    Total Development8.5 45 34.1 56 43.8 
Total8.5 45 34.1 56 43.8 
The following table describes the present operated drilling activities as of December 31, 2020.
As of December 31, 2020
GrossNet
Exploratory— — 
Development47 37.0 
Total47 37.0 
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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. As of December 31, 2020, 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/dayWeighted Avg. Price per BblMMBtu/dayWeighted Avg. Price per MMBtuMMBtu/dayWeighted Avg. Price per MMBtuMMBtu/dayWeighted Avg. Price per MMBtu
1Q21
Cashless Collar3,000 
$43.67/$53.58
30,000 
$2.25/$2.57
— — 
Swap5,000 $54.48— 20,000 $0.43— 
2Q21
Cashless Collar2,500 
$34.40/$49.82
20,000 
$2.25/$2.52
— — 
Swap4,000 $54.13— 20,000 $0.43— 
3Q21
Cashless Collar3,000 
$30.00/$50.62
20,000 
$2.25/$2.52
— 20,000 
$2.15/$2.75
Swap2,500 $54.45— 20,000 $0.43— 
4Q21
Cashless Collar4,000 
$30.63/$50.34
20,000 
$2.25/$2.52
— 20,000 
$2.15/$2.75
Swap1,000 $55.20— 20,000 $0.43— 
1Q22
Cashless Collar3,500 
$31.43/$51.00
— — 20,000 
$2.15/$2.75
2Q22
Cashless Collar2,000 
$32.50/$54.85
— — 20,000 
$2.15/$2.75
3Q22
Cashless Collar1,000 
$35.00/$54.88
— — — 
4Q22
Cashless Collar500 
$35.00/$55.00
— — — 
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/dayWeighted Avg. Price per BblMMBtu/dayWeighted Avg. Price per MMBtuMMBtu/dayWeighted Avg. Price per MMBtuMMBtu/dayWeighted Avg. Price per MMBtu
1Q21
Cashless Collar3,000 
$43.67/$53.58
30,000 
$2.25/$2.57
— — 
Swap5,000 $54.48— 20,000 $0.43— 
2Q21
Cashless Collar2,500 
$34.40/$49.82
20,000 
$2.25/$2.52
— — 
Swap4,000 $54.13— 20,000 $0.43— 
3Q21
Cashless Collar3,000 
$30.00/$50.62
20,000 
$2.25/$2.52
— 20,000 
$2.15/$2.75
Swap2,500 $54.45— 20,000 $0.43— 
4Q21
Cashless Collar4,000 
$30.63/$50.34
20,000 
$2.25/$2.52
— 20,000 
$2.15/$2.75
Swap1,000 $55.20— 20,000 $0.43— 
1Q22
Cashless Collar4,000 
$31.88/$51.83
— — 20,000 
$2.15/$2.75
2Q22
Cashless Collar2,500 
$33.00/$55.41
— — 20,000 
$2.15/$2.75
3Q22
Cashless Collar1,000 
$35.00/$54.88
— — — 
4Q22
Cashless Collar500 
$35.00/$55.00
— — — 
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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 prepared by 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. 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.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 67% of our estimated proved reserves as of December 31, 2020 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. During the year ended December 31, 2020, the daily NYMEX WTI oil spot price ranged from a high of $63.27 per Bbl to a low of negative $36.98 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $3.14 per MMBtu to a low of $1.33 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. The jurisdiction in which we own and operate properties or assets for oil and natural gas production has statutory provisions regulating the exploration for and production of oil and natural gas, including, among other things, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the production and operation of wells and other facilities, 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 proper abandonment of wells and pipelines. 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 and the suspension or cessation of operations. 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 or if the outcomes will negatively affect our operations.
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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, it is difficult to estimate the potential impact on our business from regulations adopted by the Colorado Oil and Gas Conservation Commission (“COGCC”) in November 2020, which impose a number of new and amended environmental requirements on our operations. These requirements could make it more difficult and costly to develop new oil and natural gas wells and to continue to produce existing wells, increase our costs of compliance and doing business, and delay or prevent development in certain areas or under certain conditions. The COGCC is still in the process of issuing guidance and direction regarding the new requirements, and we cannot assure that these requirements as implemented will not have a material and adverse impact on our financial position, cashflows, or results of operations. In addition, the current regulatory requirements may change, currently unforeseen incidents may occur, or past noncompliance with laws or regulations may be discovered, any of which could likewise have a material adverse effect on our financial position, cashflows, or results of operations.
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. Colorado, the state in which we own and operate all of our properties, has 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 and associated facilities. These regulations effectively identify 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, Colorado 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 one U.S. state, Colorado. This state regulates 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. Colorado laws also govern a number of environmental matters, including setbacks from buildings and schools, consideration of alternative locations for new wells, the handling and disposal of waste materials, prevention of venting and flaring, mitigation of noise, lighting, visual, odor, and dust impacts, air pollutant emissions permitting, protection of certain wildlife habitat, and evaluation of cumulative impacts.
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 materially different from how it affects operations 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.
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
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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, 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, (1) 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 the state in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from how it affects operations of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
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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 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, state, and local laws and regulations governing safety and health, the discharge of hazardous 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 and other approvals before drilling or other regulated activity commences; restrict the types, quantities, and concentrations of various substances that can be released into the environment; require the assessment and mitigation of potential surface impacts; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities that have certain impacts or that occur in certain 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, public health, and natural resource protection and impose substantial liabilities or curtail operations for unpermitted pollutant emissions or failure to comply with regulatory filing obligations. Cumulatively, these laws and regulations may impact our rate of production.
The following is a summary of the more significant existing environmental and health and safety laws and regulations to which we are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations, or financial position.
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 and operation 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 expenditures for air pollution control equipment or other air emissions-related issues.
In May 2016, the U.S. Environmental Protection Agency (the “EPA”) issued additional New Source Performance Standards (“NSPS”) rules, known as Subpart OOOOa, focused on achieving additional methane and volatile organic compound reductions from oil and natural gas operations. Among other things, these revisions imposed new requirements for leak detection and repair, control requirements for oil well completions, and additional control requirements for gathering, boosting, and compressor stations. On September 14, 2020, EPA finalized the Review Rule rescinding prior source category determinations and parts of the 2016 rules regulating methane emissions from the oil and gas industry. Separately, on September 14, 2020, EPA finalized the Reconsideration Rule that made policy and technical amendments to the NSPS rules that were raised in administrative petitions that include proposed changes to, among other things, the frequency for monitoring fugitive emissions at well sites and compressor stations. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021. Both Rules are subject to ongoing litigation, and therefore, future obligations continue to remain uncertain under the Clean Air Act.
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
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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. In December 2019, the AQCC adopted new and revised air quality regulations that extend the controls adopted in 2014 to many lower producing and emitting facilities statewide, and add storage tank loadout controls to those requirements, among other changes. The new rules also increase the frequency of LDAR monitoring to semi-annual for lower producing facilities previously subject to a one-time monitoring requirement, as well as require monthly LDAR monitoring for facilities within 1,000 ft. of occupied areas, and impose a new emission inventory and reporting of greenhouse gases (“GHGs”), among other requirements. Some of these new requirements became effective as early as January 30, 2020, with others requiring compliance by May 1, 2020, or May 1, 2021. Colorado’s Air Quality Control Commission also revised rules specific to the oil and gas sector in September 2020, and again in December 2020. The September 2020 rules revisions included emission control requirements for natural gas fired engines typically in compression service, for pre-production tanks used in flowback, and also established a preproduction air monitoring plan requirement for operators for the first time. The December 2020 regulatory changes included revisions to leak detection requirements within 1,000 ft. of occupied areas, and proposed certain requirements for the pneumatic devices used in oil and gas production at new and modified facilities, but the latter revisions were not acted upon and were made the subject of a separate hearing which will be held in February 2021.
In October 2015, EPA finalized its rule lowering the existing 75 part per billion (“ppb”) national ambient air quality standard (“ 2008 NAAQS”) for ozone under the CAA to 70 ppb (“2015 NAAQS”). Also in 2019, the state of Colorado’s Denver Metro and North Front Range (“DM/NFR”) air quality control region received a bump-up in its existing non-attainment status for the 2008 NAAQS from “moderate” to “serious.” Oil and natural gas operations in “serious” ozone non-attainment areas, including in the DM/NFR area, are subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements for new and modified facilities, and increased permitting delays and costs. Additionally, The DM/NFR’s non-attainment boundary for the 2015 NAAQS was successfully challenged by environmental groups and local governments seeking to expand the boundary to include all of northern Weld County in the case of Clean Wisconsin v. EPA, No. 18-1203, in which the D.C. Circuit remanded the boundary determination to EPA for further support or re-designation. A response to the court’s remand by EPA is expected later in 2021. Finally, a “severe” non-attainment status designation for the DM/NFR by EPA appears likely in early 2022 due to violations at area monitors during the 2020 ozone season. A “severe” classification would trigger significant additional obligations under the CAA and state statute and will result in new and more stringent air quality control requirements applicable to our operations and significant operating costs and delays in obtaining necessary permits for new and modified production facilities.
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 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 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 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.
In November 2020, the COGCC adopted new regulations that generally prohibit the venting or flaring of natural gas during drilling, completion, and production operations, with limited exceptions. Among other things, these regulations require that operators proposing new oil and gas wells either commit to connecting to a gathering system when production commences or submit a gas capture plan.
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.
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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, the disclosure of the chemicals used in fracturing, or other matters. Colorado, for example, requires operators to reduce hydrocarbon emissions associated with hydraulic fracturing, compile and report additional information regarding wellbore integrity, publicly disclose the chemical ingredients used in hydraulic fracturing, maintain minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, and implement additional groundwater testing. 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 to 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 have periodically considered 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. 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, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules. 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 United States Department of the Interior also finalized a 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 Bureau of Land Management (“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 BLM proposed rules related to further controlling the venting and flaring of natural gas on BLM land. Following the adoption of these rules in late 2016, a group led by the states of Wyoming and Montana, later joined by North Dakota and Texas, challenged the rules in the United States District Court for the District of Wyoming. On September 28, 2018, the BLM published a final rule that revised the 2016 rules. The new rule, among other things, rescinded the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the states of California and New Mexico filed challenges to the 2018 rule in the United States District Court for the Northern District of California. In July of 2020, the California court vacated the 2018 revisions but stayed its vacatur of the rules for 90 days. On October 8, 2020, before the 90-day stay of the California court’s vacatur expired, the Wyoming court struck down the 2016 rules on the grounds that the BLM exceeded its statutory authority by adopting rules to protect air quality, a role delegated to the EPA. The federal government appealed the decision from California and the citizen groups, New Mexico, and California appealed the decision from Wyoming. Future litigation therefore creates some uncertainty as to how BLM’s regulation of venting and flaring will impact our business.
Apart from these ongoing federal and state initiatives, some state and local governments have adopted their own 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, but these initiatives have failed to date. 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. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators have adopted or are considering additional requirements related to seismic
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safety for hydraulic fracturing activities or the underground injection of fluid wastes. For example, the regulations that the COGCC adopted in November 2020 impose various new requirements on the underground injection of fluid wastes to further seismic safety and protect the environment. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could have a material adverse effect on our business.
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. We cannot assure 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.
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 the Rocky Mountain region.
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 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.
Other State Laws
Our properties located in Colorado are subject to the authority of the COGCC, as well as other state agencies. The COGCC finalized new flowline rules in February 2018. The new rules include: increased registration requirements, flowline design requirements, integrity management requirements, and leak detection programs, and requirements for abandoned flowlines. In November 2019, the COGCC further amended its flowline rules to impose additional requirements regarding flowline mapping, operational status, certification, and abandonment, among other things. 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, spacing of wells and pooling of mineral interests, and an increase in potential sanctions for COGCC rule violations. In June 2020, the COGCC adopted new regulations to further enhance wellbore integrity and improve safety and environmental protection during hydraulic fracturing and in November 2020 also took action to revise its 800 Series Rules for Class II underground injection control (UIC) wells as part of its historic “Mission Change” rulemaking. 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 to operate 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.
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 lease minerals 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 substantially revised its oil and gas regulations. We do not expect that these local government regulations will have any material impact on our operations.
In April 2019, new legislation became effective in Colorado, which substantially changes the state’s regulation of oil and gas exploration and production activities. The new law changes the COGCC's mission from “fostering” responsible and balanced development to “regulating” development to protect public health and the environment. The required composition of the COGCC was changed to remove two seats for industry experts and add experts on wildlife/environmental protection and public health, and the Commissioners changed from volunteer to full-time positions. The state’s statutory pooling provisions were also changed by the new law to require that an applicant own, or obtain the consent of, more than 45% of the applicable working or mineral interest, whereas previously the consent of only one mineral interest owner was required.
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Among the most significant changes under the legislation was the provision of local government control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments may now inspect oil and gas operations and impose fines for leaks, spills, and emissions.
The legislation mandates COGCC rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned, or shut-in, financial assurance, wellbore integrity, and application fees. The COGCC completed rulemaking on flowlines and wells that are inactive, temporarily abandoned, or shut-in in November 2019, completed rulemaking on wellbore integrity in June 2020, and completed a major rulemaking on the COGCC’s “mission change” in November 2020. The mission change rulemaking was intended to align the regulations to the COGCC’s new mission. It addressed a wide range of topics including facility siting, cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection. The mission change rules took effect on January 15, 2021, and they apply to permit applications pending on or submitted after that date and generally to operations occurring on or after that date. The agency is currently in the process of issuing written guidance on many of the issues addressed to provide direction on regulatory interpretation and compliance. The COGCC is expected to undertake rulemaking on financial assurance and application fees during 2021.
Additionally, the new legislation requires the state’s AQCC to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic compounds and nitrogen oxides associated with certain oil and gas facilities. The AQCC adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, and expanded storage tank control requirements and loadout control requirements statewide in December 2019. The AQCC may also adopt requirements for installation of continuous emission monitoring equipment at certain oil and gas facilities, and reduced emissions from pneumatic devices in future rulemaking scheduled for 2021. The legislation also grants the AQCC regulatory authority over a broad range of oil and gas facilities during pre-production activities, drilling and completion.
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 parties 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 oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent and costly 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 required 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. Pursuant to the consent decree, EPA determined in April 2019 that revision of the regulations is unnecessary. EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address
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emerging issues to ensure that exploration, development, and production wastes continue to be managed in a manner that protects human health and the environment. Environmental groups, however, expressed dissatisfaction with EPA’s decision and will likely continue to press the issue at the federal and state levels, especially under the new Biden Administration.
In 2018, the Colorado State legislature passed Senate Bill 245 that gave the Colorado Department of Public Health & Environment (“CDPHE”) the authority to promulgate rules for the safe management of Technologically Enhanced Naturally Occurring Radioactive Material (“TENORM”). TENORM is naturally occurring radioactive material whose radionuclide concentrations are increased through human activity, such as through generation of water treatment residuals, scales and sediments from oil and gas production, and other processes. The bill requires the Department to review TENORM residual management and regulatory limits from other states as well as prepare a report that considers background radiation levels in the state, waste stream identification and quantification, use and disposal practices, current engineering practices, appropriate test methods, economic impacts, and data gaps. This work was completed by CDPHE in 2019. During 2020, CDPHE promulgated new rules governing TENORM waste, which were adopted in November 2020 and became effective January 14, 2021, but are not enforceable until July 14, 2022, to provide operators time to come into compliance. During drilling, completion, and production, numerous waste streams that may contain TENORM are created that are hauled for disposal at permitted disposal facilities. Depending on the final waste streams chosen for characterization and regulatory levels set for disposal, costs for characterization, storage, and disposal of waste could significantly increase.
We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore for and produce 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, but no further regulatory action has been taken by EPA to date.
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 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” (as defined under the PHMSA) and increased its civil penalty structure.
In Colorado, the Public Utilities Commission (“PUC”) adopted amended Rules Regulating Pipeline Operators and Gas Pipeline Safety for intrastate pipelines on December 16, 2020. Following public and stakeholder comment, an Administrative Law Judge for the PUC issued a Recommended Decision on November 4, 2020, recommending that the PUC formally adopt proposed revisions. The scope of the rules includes all gas public utilities, all municipal or quasi-municipal corporations transporting natural gas or providing natural gas services, all operators of master meter systems, and all operators of pipelines transporting
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gas in intrastate commerce including gas gathering system operators (certain provisions are tailored to the location and size of the gathering systems involved). The rules require all filed reports to be publicly available and all Notices of Proposed Violation, Notices of Action, pleadings and decisions to be filed publicly. The rules also provide a revised methodology for calculating civil penalties in an effort to provide clarity to both operators and the public.
Climate change
Based on EPA findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment, the EPA adopted regulations under the CAA that, among other things, established Prevention of Significant Deterioration (“PSD”), construction, and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated air 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 Best Available Control Technology (“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. This rulemaking process was not finalized. If EPA promulgates new rules under the Biden Administration, 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. On July 8, 2019, EPA finalized the Affordable Clean Energy (“ACE”) rule, which established emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE replaced the CPP and provided states with new emission guidelines that informed their development of standards of performance to reduce carbon dioxide (CO2) emissions from existing coal-fired power plants. Long-pending legal challenges to the CPP rule filed by states, industry and environmental groups were dismissed as moot by the D.C. Circuit Court of Appeals on September 17, 2019, given the issuance of a final replacement ACE rule. On January 19, 2021, the D.C. Circuit struck down the ACE Rule and remanded it to the EPA; therefore, the regulation of GHG emissions is uncertain at this time.
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 former President Trump's announced withdrawal finally took effect on November 4, 2020, among President Biden's first actions was the issuance of an executive order and the provision of 30-day advance notice to the United Nations of the United States' return to the Paris Agreement.
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On May 30, 2019, Colorado also passed GHG inventory legislation and climate action legislation. House Bill 19-1261 concerns the reduction of greenhouse gas pollution and established statewide greenhouse gas pollution reduction goals. Senate Bill 19-096 concerns the collection of greenhouse gas emissions data to facilitate measures to cost-effectively meet the states GHG emissions reduction goals established in HB 19-1261. Regulations implementing the GHG inventory requirements of these statutes were promulgated by the Colorado Air Quality Control Commission in May of 2020 and became effective on July 15, 2020. Additionally, on September 30, 2020, the Colorado Energy Office and Colorado Department of Public Health and Environment released a draft Greenhouse Gas Pollution Reduction Roadmap for public comment, and finalized the document on January 14, 2021. The GHG Roadmap lays out a pathway to meet the state's climate action targets established in HB 19-1261.
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 our production operations and/or demand for the oil and natural gas we produce. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities.
Water 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 (the “Corps”) adopted a new regulatory definition of “waters of the U.S.” (“WOTUS”), which was repealed by the EPA on October 22, 2019, restoring the 1986 regulatory definition of “Waters of the United States,” – step 1 of a two-step process. Then in January 2020, EPA and the Corps released the Navigable Waters Protection Rule (“NWPR”) which updates the federal definition for a WOTUS – the second step in the two-step process to repeal and replace the 2015 rule – and published the final rule on April 21, 2020. The NWPR went into effect on June 22, 2020. Numerous environmental, agricultural and business groups and state governments have challenged the NWPR in various courts, and one such challenge in Colorado resulted in the grant of a stay of the rule in that state, where the 2015 rule remains in effect. At President Biden’s direction, the EPA and the U.S. Army Corps of Engineers requested the litigation be stayed while the agencies review the NWPR.
Endangered Species Act and Migratory Bird Treaty Act
The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered and threatened species or their habitats. In August 2019, the U.S. Fish and Wildlife Service (the “FWS”) and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. We anticipate the rule will be subject to litigation. A final rule amending how critical habitat and suitable habitat areas are designated was finalized by the U.S. Fish and Wildlife Service in 2016. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA, however the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review. Future implementation of the rules implementing the ESA and the MBTA are uncertain. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened
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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 impact our operations. These changes include among other items: record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures below the new limits by June 23, 2021), naming oil and gas as a high hazard industry, and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes, requires 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.
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 federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a detailed environmental impact statement 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 review 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. On July 16, 2020, the Council on Environmental Quality (“CEQ”) revised NEPA’s implementing regulations to make the NEPA process more efficient, effective, and timely. The final rule requires federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date. The new regulations are subject to ongoing litigation in several federal district courts and future implementation of the regulations is unclear.
Oil Pollution Act
The Oil Pollution Act of 1990 (“OPA”) establishes strict liability for owners and operators of facilities that release 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.
Human Capital
As of December 31, 2020, the Company had 109 employees, of which 29 full-time employee equivalents were dedicated to our Rocky Mountain Infrastructure, LLC operations. The Company's diverse team of talented employees possess a vast array of skills including engineering, geology, research and development, midstream operations, production, logistics and administrative support, such as accounting, information technology, legal, human resources and finance. Certain of the Company's employees have highly specialized skills and subject-matter expertise in their respective fields, which helps enable the Company to deliver industry leading innovation and results.
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The Company attracts and maintains talent by offering market rate competitive salaries for the locations in which it operates, and by engaging employees with rewarding opportunities to contribute to the success of the Company. The Company is committed to supporting and developing its employees through learning and development programs. These programs are designed to build and strengthen employees’ skills, including leadership and professional competencies. Such efforts also include routine and consistent compliance training, covering a wide-range of relevant subjects. The Company has consistently re-invested in necessary resources to effectively staff and efficiently support its business.
Employee health and safety in the workplace is one of the Company’s core values. Safety efforts are led by the Environmental, Health, and Safety & Regulatory Compliance (“EHS&RC”) team and supported by individuals at the local site level. Hazards in the workplace are timely identified, and management actively tracks incidents so remedial actions may be implemented to improve workplace safety. The Company also provides an injury case management program that provides medical management services tailored to any injured employee to best meet their recovery needs. Additionally, all field employees attend training provided by the COGCC or by the EHS&RC department to proactively ensure compliance and adherence related to recently issued rules and regulations. In response to the COVID-19 pandemic, the Company has taken actions aligned with the World Health Organization and the Centers for Disease Control and Prevention to protect its workforce so they can more safely and effectively perform their work. In so doing, the Company has prioritized the initiation of comprehensive health and safety protocols, further ensuring strict adherence to responsive measures for mitigating the spread of COVID-19.
The Nominating and Corporate Governance Committee of the Board (the “Governance Committee”) considers diversity as a criteria evaluated as part of the attributes and qualifications that a Board candidate possesses. The Governance Committee construes the notion of diversity broadly, considering differences in viewpoint, professional experience, education, skills and other individual qualities, in addition to race, gender, age, ethnicity and cultural backgrounds as elements that contribute to a diverse Board. In keeping with this diversity commitment, the most recent director appointed to the Board, who brings substantial experience in the form of executive leadership in the petroleum industry, furthered the Board’s goal of enhancing diversity. The Company is committed to efforts to increase diversity and foster an inclusive work environment that supports the Company’s workforce.
We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.
Offices
As of December 31, 2020, we leased 63,783 square feet of office space in Denver, Colorado at 410 17th Street where our principal offices are located, and we leased 7,780 square feet near our operations in Weld County, Colorado, where we have a field office and storage facilities. We also own a field office in Evans, Colorado.
Available Information
We are required to file annual, quarterly, and current reports, proxy statements and other information with the SEC. Our filings with the SEC are 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 is not incorporated by reference into this Annual Report on Form 10-K.
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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.
Summary of the Risk Factors We Face:
Further declines in oil and 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.
Excess supply of oil and natural gas resulting from reduced demand caused by COVID-19 pandemic and effects of actions by oil and natural gas producing countries have resulted, and may continue to result, in transportation and storage constraints, and reductions of our planned production, and may cause shut-in of our wells.
Terrorist attacks could have a material adverse effect on our business, financial condition, or results of operations.
Our production is not fully hedged, and we are exposed to fluctuations in price of oil, natural gas, and NGLs and will be affected by continuing and prolonged declines in such prices. At the same time, our derivative activities could result in financial losses or could reduce our income.
Extent to which COVID-19 pandemic impacts our business, results of operations, and financial condition will depend on future developments, which cannot be predicted.
Our Credit Facility has restrictive covenants that could limit our growth and our ability to finance operations, fund capital needs, respond to changing conditions, and engage in other business activities. Further, borrowings under our Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.
Our exploration, development, exploitation, and production 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 decline in our oil and natural gas reserves or anticipated production volumes.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties.
Our estimated proved reserves and ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate.
Present value of future net revenues from our proved reserves will not necessarily be same as current market value of our estimated oil and natural gas reserves.
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 intend to pursue further development through horizontal drilling and completion. Horizontal development operations can be more operationally challenging and costly relative to our historic vertical drilling operations.
We may be unable to make attractive acquisitions, and any inability to do so may disrupt our business and hinder our ability to grow.
The HighPoint Acquisition is subject to number of regulatory approvals and conditions, which may delay the Acquisition, result in additional expenditures of money and resources or reduce anticipated benefits or result in termination of the Merger Agreement.
The Merger Agreement subjects us to restrictions on our business activities prior to closing.
We may not realize anticipated benefits from acquisitions, including HighPoint Acquisition.
Concentration of our operations in one core area may increase our risk of production loss.
As a Colorado-only oil and gas operator, we face disproportionate risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities.
State law requiring that we own or control more than 45% of working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests.
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We have limited control over activities on properties in which we own interest but we do not operate, which could reduce our production and revenues.
Concentrated nature of RMI system may increase risk that we suffer lengthy interruptions in production.
Development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Our undeveloped reserves may not be ultimately developed or produced.
Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over next several years unless production is established.
Unless we replace our oil and natural gas reserves, our reserves and production will decline.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are subject to health, safety, and environmental laws and regulations that may expose us to significant costs and liabilities.
Evolving environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.
Climate change laws and regulations restricting emissions could result in increased operating costs and reduced demand for oil and natural gas, while physical effects of climate change could disrupt our production and cause us to incur significant costs.
Negative shift in investor sentiment of oil and gas industry could have adverse effects on our ability to raise debt and equity capital and on our operations.
We are exposed to credit risks of our hedging counterparties, third parties participating in our wells, and our customers.
Current or proposed financial legislation and rulemaking could adversely affect on our ability to use derivative instruments.
We may be involved in legal cases that may result in substantial liabilities.
We may become subject to new taxes, and certain tax deductions and exemptions currently available with respect to oil and gas exploration and development may be eliminated or reduced.
Transactions in connection with the HighPoint Acquisition could trigger limitation on utilization of our historic net operating loss carryforwards and will trigger limitation on utilization of HighPoint’s historic net operating loss carryforwards.
We are at risk of cyber security incidents that could result in information theft, data corruption, operational disruption, or financial loss.
Market price for our common stock following the HighPoint Acquisition may be affected by factors different from those that historically have affected or currently affect our common stock.
We do currently not intend to pay, and are subject to certain restrictions on our ability to pay, dividends on our common stock.
We have experienced recent volatility in market price and trading volume of our common stock and may continue to do so in the future.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals.
Our certificate of incorporation designates Delaware Court of Chancery as sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain favorable judicial forum.
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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 natural gas liquids (“NGLs”), heavily influences our revenue, profitability, cash flows, liquidity, access to capital, present value and quality of our reserves, the nature and scale of our operations, and future rate of growth. Oil and natural gas 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 67% of our estimated proved reserves as of December 31, 2020 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 unproved property asset impairment charges. A prolonged period of low market prices for oil, natural gas, and NGLs or further declines in the market prices for oil and natural gas, could result in capital expenditures being further reduced 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, 2020, the daily NYMEX WTI oil spot price ranged from a high of $63.27 per Bbl to a low of negative $36.98 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu. As of February 10, 2021, the daily NYMEX WTI oil spot price and NYMEX natural gas HH spot price was $58.68 per Bbl and $3.73 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 reduction in our liquidity and inability to pay our liabilities as they come due;
certain properties in our portfolio becoming economically unviable;
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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 Credit Facility (defined below) or limitations in our access to sources of capital, such as equity or debt;
declines in our stock price;
reduction in industry demand for crude oil;
reduction in storage availability for crude oil;
reduction in pipeline and processing industry demand and capacity for natural gas;
reduction in the ability of our vendors, suppliers, and customers to continue operations due to the prevailing adverse market conditions; and
asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment.
The excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries has resulted, and may continue to result, in transportation and storage constraints, and reductions of our planned production, and may cause shut-in of our wells, which could adversely affect our business, financial condition, and results of operations.
The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19, and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production, followed by curtailment agreements among OPEC and other countries, including Russia, has increased uncertainty and volatility around global oil supply-demand dynamics and further increased the excess supply of oil and natural gas. To the extent that the outbreak of COVID-19 continues to negatively impact demand, and OPEC members and other oil exporting nations fail to implement production cuts or other actions that are sufficient to support and stabilize commodity prices, we expect there to be excess supply of oil and natural gas for a sustained period. This excess supply has, in turn, resulted, and may continue to result, in transportation and storage capacity constraints in the United States, including in the DJ Basin where we operate, which may continue for a sustained period. For example, the substantial number of outstanding futures contracts, in conjunction with the market’s perception that crude oil storage in Cushing, Oklahoma was inadequate for May 2020 deliveries, caused NYMEX WTI futures prices to settle at negative $37.63 per Bbl on April 20, 2020, a dynamic that has not previously occurred.
If, in the future, our ability to sell our production is hindered because of transportation or storage constraints, we may be required to shut-in or curtail production or flare our natural gas. Further, any prolonged shut-in of our wells may result in decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may adversely affect our business, financial condition, and results of operations.
Due to the commodity price environment, we have postponed a significant portion of our developmental drilling. A sustained period of weakness in oil, natural gas, and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Such actions would likely result in the reduction of our PUDs and related PV-10 and a reduction in our ability to service our debt obligations. If we are required to further curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGLs prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
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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 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.
Our production is not fully hedged, and we are exposed to fluctuations in the price of oil, natural gas, and NGLs and will be affected by continuing and prolonged declines in such prices.
Oil, natural gas, and NGL prices are volatile. We hedge a portion of our oil and natural gas production to reduce our exposure to adverse fluctuations in these prices. We have stated limitations as prescribed in our reserve-based revolving credit facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions as lenders (the “Credit Facility”) as to the percentage of our production that can be hedged. The limitations range from 85% to 100% of our projected production from our proved developed properties and 65% to 85% of our projected production from our total proved properties, dependent on the duration of the hedge. Due to the Credit Facility's restrictions and/or management's decision to hedge less than 100% of our projected production, some of our future production will be sold at market prices, exposing us to fluctuations in the price of crude oil and natural gas. Currently, we have hedged approximately 6,200 Bbls per day in 2021, representing approximately 50% of our oil sales volume during the three months ended December 31, 2020, and our hedging for 2022 oil production is even more limited. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant reduction in prices, which would have a material negative impact on our results of operations. 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.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have, and may in the future enter into additional, derivative arrangements for a portion of our oil and natural gas production, including swaps, collars, and puts. 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. Further, our Credit Facility provides for certain limitations to the extent of our hedging, which may expose us to unfavorable fluctuations in the prices of oil and natural gas.
The extent to which the COVID-19 pandemic impacts our business, results of operations, and financial condition will depend on future developments, which cannot be predicted.
The outbreak of COVID-19, which has been declared by the World Health Organization to be a pandemic, has spread across the globe and is impacting worldwide economic activity, including the global demand for oil and natural gas. Any pandemic or other public health epidemic, including COVID-19, poses the risk that we or our employees, vendors, suppliers, customers, and other business partners may be prevented from conducting business activities for an indefinite period of time due to the potential spread of the disease within these groups or due to restrictions that may be requested or mandated by governmental authorities, including quarantines of certain geographic areas, restrictions on travel, and other restrictions that prohibit employees from going to work. To date, the COVID-19 outbreak has surfaced in all regions around the world and has severely impacted the global economy, disrupted consumer spending and global supply chains, and created significant volatility and disruption of financial markets, all of which are expected to continue.
The COVID-19 pandemic has caused us to modify our business practices (including employee travel, employee work locations, and cancellation of physical participation in meetings, events, and conferences), and we may take further actions as
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may be required by government authorities or that we determine are in the best interests of our employees, vendors, suppliers, customers, and other business partners. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus or otherwise be satisfactory to government authorities.
The extent to which COVID-19 impacts our business, results of operations, and financial condition will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, and how quickly and to what extent normal economic and operating conditions can resume. If COVID-19 continues to spread or the response to contain COVID-19 is unsuccessful, we could experience a material adverse effect on our business, financial condition, and results of operations. Even after the coronavirus outbreak has subsided, we may continue to experience materially adverse impacts to our business as a result of its global economic impact, including any recession that has occurred or may occur in the future.
The 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 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 Credit Facility is subject to compliance with certain financial covenants, including the maintenance of certain financial ratios, including a minimum current ratio and a maximum leverage ratio. In addition, the Credit Facility contains covenants that, among other things, limit our ability to:
incur or guarantee additional indebtedness;
issue preferred stock;
sell or transfer assets;
pay dividends on, redeem, or repurchase capital stock;
repurchase or redeem subordinated debt;
make certain acquisitions and investments;
create or incur liens;
engage in transactions with affiliates;
enter into agreements that restrict distributions or other payments from restricted subsidiaries to us;
consolidate, merge, or transfer all or substantially all of our assets; and
engage in certain other business activities.
Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. We may 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.
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 Credit Facility. Our ability to comply with the financial ratios and financial condition tests under the 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 Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.
The borrowing base under the Credit Facility is redetermined at least semiannually and up to two additional times per year between scheduled determinations upon request of us or lenders holding more than 50% of the aggregate commitments. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors.
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In our June 2020 redetermination, the borrowing base under the Credit Facility was reduced from $375.0 million to $260.0 million. In our December 2020 redetermination, our most recent one, the borrowing base was reaffirmed at $260.0 million.
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.
Our exploration, development, exploitation, and production 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, exploitation, and production 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 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 or 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 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 new and existing wells;
the prices at which our oil and natural gas are sold;
the costs of developing and producing our oil and natural gas;
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 Credit Facility decreases 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 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.
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, lease, 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
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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, completion, and infrastructure projects:
shortages of or delays in obtaining equipment and qualified personnel;
facility or equipment malfunctions;
unexpected operational events;
unanticipated environmental liabilities;
pressure or irregularities in geological formations;
adverse weather conditions, such as extreme cold temperatures, blizzards, ice storms, tornadoes, floods, and fires;
reductions in oil and natural gas prices;
delays imposed by or resulting from compliance with regulatory requirements, such as permitting delays;
proximity to and capacity of transportation facilities;
title problems;
safety concerns; and
limitations in the market for oil and natural gas.
Our estimated proved reserves and our ultimate number of prospective well development locations are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
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, 2020, 2019, and 2018.
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 reserves information contained herein is reviewed by independent reserves 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 cause potential 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.
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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, 2020, 2019, and 2018, 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 activities;
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 predominately sustained decrease in prices for oil, natural gas, and NGLs since the fourth quarter of 2014, 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 the middle of 2014 and have not regained previous highs. Additionally, given the history of price volatility in the oil and natural gas 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.
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We intend to pursue the further development of our properties in the Wattenberg Field through horizontal drilling and completion. Horizontal development 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 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 hydrocarbon reservoir;
effectively controlling the level of pressure flowing from particular wells;
staying in the desired hydrocarbon reservoir while drilling horizontally through the formation;
running our casing through the entire length of the wellbore;
running tools and other equipment consistently through the horizontal wellbore;
successful design and execution of the fracture stimulation process;
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.
We may be unable to make attractive acquisitions, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of producing properties or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future oil, natural gas and NGL prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire
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identified targets. In addition, our Credit Facility imposes certain limitations on our ability to enter into mergers or combination transactions. The Credit Facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.
The HighPoint Acquisition is subject to a number of regulatory approvals and conditions to the obligations of the parties, which may delay the HighPoint Acquisition, result in additional expenditures of money and resources or reduce the anticipated benefits or result in termination of the Merger Agreement.
The completion of the HighPoint Acquisition Resources Corporation may be subject to antitrust review in the United States. While no filing or waiting period requirements under the HSR Act apply, the DOJ or the FTC, or any state, could take such action under the antitrust laws as it deems necessary or desirable in the public interest, including seeking to enjoin the completion of the HighPoint Acquisition. Private parties may also seek to take legal action under the antitrust laws under certain circumstances. Our obligations and the obligations of HighPoint to consummate the HighPoint Acquisition are subject to the satisfaction (or waiver by all parties, to the extent permissible under applicable laws) of a number of conditions described in the Merger Agreement. Many of the conditions to completion of the HighPoint Acquisition are not within our control and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the outside date, it is possible that the Merger Agreement may be terminated.
Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the HighPoint Acquisition as promptly as practicable, these and other conditions may fail to be satisfied. In addition, completion of the merger may take longer, and could cost more, than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the HighPoint Acquisition for a significant period of time or prevent them from occurring. Any delay in completing the HighPoint Acquisition may adversely affect the cost savings and other benefits that we expect to achieve if the HighPoint Acquisition and the integration of businesses are completed within the expected timeframe.
The Merger Agreement subjects us to restrictions on our business activities prior to closing the HighPoint Acquisition.
The Merger Agreement subjects us to restrictions on our business activities prior to closing the HighPoint Acquisition. The Merger Agreement obligates us to generally conduct our businesses in the ordinary course until the closing and to use our reasonable best efforts to (i) preserve substantially intact our present business organization, goodwill and assets, (ii) keep available the services of our current officers and employees and (iii) preserve our existing relationships with governmental entities and significant customers, suppliers, licensors, licensees, distributors, lessors and others having significant business dealings with us. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of business.
We may not realize anticipated benefits from acquisitions, including the HighPoint Acquisition.
We seek to complete acquisitions in order to strengthen our position and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations. Acquisitions could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate such properties.
With respect to the HighPoint Acquisition, we believe that the addition of HighPoint will complement our strategy by providing operational and financial scale, increasing free cash flow, and enhancing our corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the merger, and there can be no assurance that we will be able to successfully integrate HighPoint's assets or otherwise realize the expected benefits of the transaction. This growth and the anticipated benefits of the HighPoint Acquisition may not be realized fully or at all, or may take longer to realize than expected. Difficulties in integrating HighPoint may result in the combined company performing differently than expected, or in operational challenges or failures to realize anticipated efficiencies. Potential difficulties in realizing the anticipated benefits of the HighPoint Acquisition include:
disruptions of relationships with customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners as a result of uncertainty associated with the HighPoint Acquisition;
difficulties integrating our business with the business of HighPoint in a manner that permits us to achieve the full revenue and cost savings anticipated from the transaction;
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complexities associated with managing a larger and more complex business, including difficulty addressing possible inconsistencies in, standards, controls or operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;
difficulties realizing anticipated operating synergies;
difficulties integrating personnel, vendors and business partners;
loss of key employees of HighPoint who are critical to our future operations due to uncertainty about their roles within our company following the HighPoint Acquisition or other concerns regarding the HighPoint Acquisition;
potential unknown liabilities and unforeseen expenses;
performance shortfalls at one or both of the companies as a result of the diversion of management’s attention to integration efforts; and
disruption of, or the loss of momentum in, each company’s ongoing business.
We have also incurred, and expect to continue to incur, a number of costs associated with completing the HighPoint Acquisition and combining the businesses of HighPoint and Bonanza Creek. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two companies, may not initially offset integration-related costs or achieve a net benefit in the near term, or at all.
Our future success will depend, in part, on our ability to manage our expanded business by, among other things, integrating the assets, operations and personnel of HighPoint and Bonanza Creek in an efficient and timely manner; consolidating systems and management controls; and successfully integrating relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our business, reputation, financial condition and results of operations.
Concentration of our operations in one core area may increase our risk of production loss.
Our assets and operations are currently concentrated in one core area: the Wattenberg Field in Colorado. The core area currently provides 100% of our current sales volumes and development projects.
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, including ozone non-attainment and climate action regulations in Colorado, curtailment of production, 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 single producing formation exposes us to risks, such as changes in field-wide rules or local regulations, which could adversely affect development activities or production relating to the formation. 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, pressure pumping fleets, 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 our core operating area could have a significant negative impact on our cash flows and profitability.
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As a Colorado-only oil and gas operator, we face disproportionate risk associated with the long-term trend toward increased activism against oil and gas exploration and development activities in Colorado.
Opposition toward oil and gas drilling and development activity has been growing globally. Companies in the oil and gas industry are often 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;
revocation or modification of drilling permits or other necessary authorizations;
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 or other protected areas;
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 operations and development;
reduction in demand for our products; and
other adverse effects on our ability to develop our properties and expand production.
Specifically in Colorado, anti-development activity has both increased and become more effective in recent years. In April 2019, new legislation became effective in Colorado, which substantially changed the state’s regulation of oil and gas exploration and production activities. The new law changed the mission of the COGCC from “fostering” responsible and balanced development to “regulating” oil and natural gas development to protect public health and the environment. The required composition of the COGCC was also changed to remove two seats for oil and gas industry experts and add experts on wildlife/environmental protection and public health, and the Commissioners changed from volunteer to full-time positions. The state’s statutory pooling provisions were changed by the new law to require that an applicant own, or obtain the consent of, more than 45% of the applicable working or mineral interest, whereas previously the consent of only one mineral interest owner was required.
Among the most significant changes under the legislation was the provision of local government control over facility siting and surface impacts associated with oil and gas development. Whether an applicable local government determines to implement regulatory changes is optional, but if changes are adopted, the resulting regulations may be stricter than state requirements. Further, local governments may now inspect oil and gas operations and impose fines for leaks, spills, and emissions.
The legislation mandates the COGCC conduct rulemaking on environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned, or shut-in, financial assurance, wellbore integrity, and application fees. The COGCC completed rulemaking on flowlines and wells that are inactive, temporarily abandoned, or shut-in in November 2019, completed rulemaking on wellbore integrity in June 2020, and completed rulemaking on the agency’s “mission change” in November 2020. The mission change rulemaking addressed a wide range of topics including facility siting,
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cumulative impacts, development approvals, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection.
The mission change rules took effect on January 15, 2021, and the agency is currently in the process of issuing written guidance on many of the issues addressed to provide direction on regulatory interpretation and compliance. Among other things, the amended rules adopt an increased required setback of 2,000 feet between an oil and gas location and a residential or high occupancy building unit unless one or more conditions are satisfied to allow for a lesser setback that the COGCC determines is sufficiently protective of public health, safety and welfare, the environment, and wildlife resources. In addition, as part of wildlife protections, the COGCC adopted a setback of 500 feet between oil and gas locations and/or certain operations thereon and the ordinary high water mark for certain high priority aquatic habitats, though the Colorado Parks and Wildlife Division may waive this setback beyond 300 feet.
Permitting delays that result from the new COGCC rules and regulations, could substantially curtail the Company’s near-term pace of new oil and gas development. We have previously observed a marked decline in the pace at which permit applications are being granted, and if this trend continues, it could have a material adverse effect on our business, financial condition, and results of operations.
Additionally, the new legislation requires the state’s AQCC to undertake rulemaking efforts to minimize methane emissions and emissions of other hydrocarbons, volatile organic compounds, and nitrogen oxides associated with oil and gas facilities. The AQCC has more recently adopted more stringent standards for leak detection and repair inspection frequency, pipeline and compressor station inspection and maintenance frequencies, the development of pre-production air monitoring plans at certain oil and gas facilities, and will soon take action on proposed measures for reducing emissions from pneumatic devices. The legislation also granted the AQCC regulatory authority over a broad range of oil and gas facilities during pre-production activities, drilling, and completion.
Rules adopted by the COGCC and AQCC pursuant to the new legislation may significantly increase the Company’s operating costs and have a material adverse effect on our business, financial condition, and results of operations.
Additionally, anti-development activists succeeded in adding a measure to the November 6, 2018 ballot in Colorado, which sought to require a minimum 2,500 foot setback from occupied structures and vulnerable areas for all new oil and gas development on non-federal land. While this initiative was ultimately unsuccessful, had it been successful, it may have resulted in dramatically reducing the area of future oil and gas development in Colorado. Similar ballot measures were submitted for the 2020 election by anti-development activist groups. In addition, there have been several citizen/activist lawsuits filed against industry and state and local regulators associated with air quality, siting, environmental justice, and climate change. Such anti-development efforts are likely to continue in the future, which could result in dramatically reducing the area of future oil and gas development in Colorado or outright banning oil and gas development in Colorado. These efforts could have a material adverse effect on our business, financial condition, and results of operations.
State law requiring that we own or control more than 45% of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.
In many cases, we do not own more than 45% working interest or mineral interest in a prospective area of development, which is now required to statutorily pool our applicable working or mineral interests. In such cases, unless we can obtain the consent of more than 45% of all applicable working or mineral interest owners (who can be located through reasonable diligence) to pursue statutory pooling, or achieve a voluntary pooling agreement with 100% of the applicable interest owners, we may be prohibited from developing the resources in that area.
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. For example, we will not operate the majority of our assets in the French Lake area. 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
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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.
The concentrated nature of our RMI system may increase the risk that we suffer lengthy interruptions in our production.
Through our Rocky Mountain Infrastructure, LLC (“RMI”) subsidiary, we have consolidated and interconnected our gathering, treating, and production facilities. This approach includes, for example, greater use of central processing facilities and central compression stations than some other operators in the Wattenberg Field. The concentrated nature of the RMI system, by itself, could increase the length and magnitude of a production interruption caused by operational problems located in otherwise localized portions of the system. Such interruptions could materially and adversely affect our ability to meet our public guidance, our financial condition, and our results of operations.
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 50% of our total proved reserves were classified as proved undeveloped as of December 31, 2020. 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.
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 well performance. 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 categories 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.
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.
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 December 31, 2020, approximately 3,705 net acres of our properties were not held by production. For these properties, if production in paying quantities is not established on units containing leases during the next year, then approximately 1,859 net acres will expire in 2021, approximately 1,356 net acres
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will expire in 2022, and approximately 490 net acres will expire in 2023 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 or cause us to lose the leases entirely. If our leases expire, we will lose our right to develop the related properties.
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, surface water, groundwater, and shoreline contamination;
releases of natural gas and hazardous air pollutants or other substances into the atmosphere (including releases at our oil and gas facilities);
hazards resulting from the presence of hydrogen sulfide (H2S) or other contaminants in natural gas and oil we produce;
abnormally pressured formations resulting in well blowouts, fires, or explosions;
mechanical difficulties, such as stuck down-hole tools or casing collapse;
cratering (catastrophic failure);
downhole communication leading to migration of contaminants;
personal injuries and death; and
natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
injury or loss of life;
damage to and destruction of property, natural resources, and equipment;
pollution and other environmental and natural resource 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 and facility locations. In addition, our operations in Colorado are susceptible to damage from natural disasters, such as flooding, wildfires, tornadoes, and other natural phenomena
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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.
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 integral to our operations, they are covered by our insurance against claims made for bodily injury, property damage, and clean-up costs stemming from a sudden and accidental pollution event. However, 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.
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 or completion activities; the application of specific health and safety criteria to protect the public or 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 our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions into air, water and the environment, 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.
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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. For example, during 2020, the COGCC revised its regulations on a range of topics including facility siting, development approvals, cumulative impacts, asset transfers, pollution standards, hearings and variances, groundwater monitoring, underground injection control and enhanced recovery wells, venting and flaring restrictions, spill reporting, cleanup responsibility, and wildlife protection. And legislation passed in 2019 requires the COGCC to assess and potentially revise its financial assurance requirements for oil and gas development. 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.
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, increased seismic activity, and human health effects. The federal government has periodically studied the environmental risks associated with hydraulic fracturing and evaluated whether to adopt, and in some cases have adopted, additional regulatory requirements.
In some instances certain state and 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. Under current Colorado law, local governments can regulate both facility siting and the surface impacts associated with oil and gas development, and local government regulations may be more protective or stricter than State requirements. In addition, voters in Colorado have proposed or advanced ballot initiatives restricting or banning oil and gas development in Colorado. Because our operations and reserves are solely located in 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 and financial assurance obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance operations, delay 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. We cannot assure 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 broad consensus of scientific opinion that human-caused (anthropogenic) emissions of greenhouse gases GHGs are 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 the demand for and consumption of our products (due to potential changes in both costs and weather patterns).
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 reporting 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 the Subpart OOOOa NSPS rules 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 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, and the adoption of ambitious climate action targets in Colorado under HB 19-1261. 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. Such a program has been proposed by an environmental group to the Colorado AQCC in a petition filed on December 23, 2020. The AQCC will consider action on that petition later in 2021.
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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 and vapor control systems, to acquire emissions allowances, or to 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. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas we produce. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities.