The data in the above table represent estimates only. Oil, natural gas and NGLs reserve engineering is an estimationreserves are estimates of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered. See "Item“Item 1A. Risk Factors"Factors”.

The following tables illustrate the history of our proved undeveloped reserves from December 31, 20162018 through December 31, 2018:2020:

At December 31, 2018, our proved undeveloped reserves were 53.2 MMBoe. At December 31, 2017, our proved undeveloped reserves were 44.3 MMBoe. During 2018, 21.1 MMBoe, or 48% of our December 31, 2017 proved undeveloped reserves (69 wells), were converted into proved developed reserves and required $269.1 million of drilling and completion capital and $28.5 million of facilities capital. These wells produced 2.9 MMBoe in 2018. During 2018, we added 41.3 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Negative engineering revisions decreased proved undeveloped reserves by 6.7 MMBoe as discussed above. During 2018, 10.0 MMBoe were removed from the proved undeveloped reserves category as a result of being excluded from our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2017 that remained in the proved undeveloped reserves category at December 31, 2018 were 11.2 MMBoe.

We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we believe that our reservoir and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance relative to the estimates of third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the third party engineers. We investigate any such differences and discuss the differences with the third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for the relevant field. These variances also are reviewed with our Reserves and EHS Committee. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, include but are not limited to the following:

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is William K. Stenzel.Paul Geiger. Mr. StenzelGeiger is our Senior Vice President of Corporate Development and PlanningChief Operating Officer and became responsible for our reserves estimates starting in September 2014.January 2019. Mr. StenzelGeiger earned a Bachelor of Science degree in CivilPetroleum Engineering and an MBA from Colorado Statethe University in 1977.of Texas. Mr. StenzelGeiger has over 4020 years of experience in reserves and economic evaluations, as well as broad experience in production, completions, reservoir analysis and planning and development.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAI since 2007 and has over two2 years of prior industry

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same as or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI'sNSAI’s audit report does not state the degree of its concurrence with the accuracy of our estimate of the proved reserves attributable to our interest in any specific basin, property or well.

The NSAI audit process is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted at 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:

The reserves audit letter provided by NSAI states that "in“in our opinion the estimates shown herein of HighPoint'sHighPoint’s reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards."” The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements ("FASB"(“FASB”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its employees have no interest in those properties,

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain cost information for each of the periods indicated:

The following table sets forth information at December 31, 20182020 relating to the productive wells in which we owned a working interest as of that date.

The following table sets forth information as of December 31, 20182020 relating to our leasehold acreage.

Substantially all of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth, as of December 31, 2018,2020, the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities or value of reserves found.

In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be the operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. WeIn certain circumstances we construct, operate and maintain gas gathering and water facilities associated with our operations. We employ drilling, completion, facility, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties. We strive to minimize our impact on the communities in which we operate.

Our natural gas and related NGLs are generally marketed by third parties under percentage of proceeds ("POP"(“POP”) or fee-based contracts. Based on where we operate and the availability of other purchasers and markets, we believe that our production could be sold in the market in the event that it is not sold to our existing customers. However, in some circumstances, a change in customers may entail significant transition costs.

We normally sell production to a relatively small number of customers, as is customary in the development and production business. During 2018,2020, four customers individually accounted for over 10% of our oil, gas and NGL production revenues. During 2017,2019, three customers individually accounted for over 10% of our oil, gas and NGL production revenues. During 2016, three2018, four customers individually accounted for over 10% of our oil, gas and NGL production revenues.

We have submittedThe following table sets forth information about a bidmaterial long-term firm oil pipeline transportation contract, which entails a demand charge for committed space on a crude pipeline for crude production fromreservation of capacity. This contract was initiated to mitigate rising transportation costs in our Hereford field in the DJ BasinBasin. This firm transportation contract requires the pipeline to mitigate risingprovide transportation costs, but will not know our allocated volume on this crude pipeline until the closecapacity and requires us to pay monthly transportation charges regardless of the carrier's open season.amount of pipeline capacity utilized and will expire April 30, 2025. The costs of this transportation contract are included in oil, gas and NGL production in the Consolidated Statements of Operations.

The following table sets forth information about material long-term firm natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company-marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly

Our hedging program is intended to mitigate the risks of volatile prices of oil, natural gas, and NGLs. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month to 18-month basis. As of February 21, 2019,4, 2021, we have hedged 6,736,1843,098,000 barrels and 365,000 barrels of our expected 2021 and 2022 oil production, respectively, and 3,275,0007,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas for our 2019 production, and 3,292,000 barrels of oil for our 2020 productionrespectively, at price levels that provide some economic certainty to our cash flows. Currently, eight7 of our 11 lenders (or affiliates of lenders) under our credit facilityCredit Facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our credit facility.Credit Facility. For additional information on our hedging activities, see "Item“Item 7A. Quantitative and Qualitative Disclosures About Market Risk"Risk”.

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of drilling operations on those properties, we typically conduct a title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing such defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. However, our title review processes may not be successful in preventing disputes and losses related to actual or asserted title defects. Our oil, natural gas and NGL producing properties are subject to customary royalty and other interests, liens for current taxes, liens under our Amended Credit Facility and other burdens that we believe do not materially interfere with the use of our properties.

These laws, rules and regulations may also restrict the rate of oil, natural gas and NGLs production below the rate that would otherwise be possible, for example, by limiting the flaring of associated natural gas from an oil well while awaiting a pipeline connection. The regulatory burden on the oil and gas industry increases the cost and delays the timing of doing business and consequently affects profitability. Additionally, Congress, state legislatures, and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not extraordinary. We believe that our compliance with existing requirements has been accounted for and will not have a material adverse impact on our financial condition and results of operations. For the year ended December 31, 2018, we did not incur any material capital expenditures for remediation of well sites or production facilities or to retrofit emission control equipment at any of our facilities. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations, including organized, well-funded "keep“keep it in the ground"ground” efforts to turn public opinion against the use of fossil fuels. For example, statewide ballot initiatives intended to impose further restrictions on oil and gas development have been pursued several times in recent years in Colorado. Because substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.

In 2018 a new Democratic Governor was elected, along with Democratic majorities in both chambers of the General Assembly. Following the November 2018 election, Colorado enacted Senate Bill 19-181 (“SB 19-181”), which, among other things, authorizes local governments to approve the siting of and regulate the surface impacts from oil and natural gas facilities, and empowers them to adopt requirements and impose conditions that are more stringent than state regulations. The statute changes the mission of the Colorado Oil and Gas Conservation Commission (the “COGCC”) from fostering responsible and balanced development to regulating development to protect public health and the environment as the primary goal. It requires the COGCC to undertake rulemaking on environmental protection, facility siting, cumulative impacts, flowline safety, orphan wells, financial assurance, wellbore integrity, and application fees. It also requires the Air Quality Control Commission to review its leak detection and repair regulations and adopt rules to further minimize emissions of hydrocarbons and nitrogen oxides. These rulemakings, some of which were completed in late 2019 and 2020, have imposed new approval and operating requirements and may have an adverse effect on our development program, particularly in terms of costs and delays in the permitting process and the siting of new wells. The majority of these regulations were approved late in 2020 and became effective on January 15, 2021, and the COGCC is still in the process of issuing guidance and direction on implementation of the new regulations. However, we believe that the location of our assets in rural areas of Weld County, a jurisdiction generally supportive of oil and gas development, is likely to mitigate these impacts to a significant extent. Additionally, our staff were extensively involved in the rulemaking process throughout 2020 and we believe that we have been able to effectively evaluate the new requirements and implement the measures necessary to maintain compliance with the new regulations.

Other environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:include the following:

Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater and released its preliminary report in 2015, finding no systematic impact on groundwater resources. In its final report, issued in late 2016, EPA removed the conclusion of no systemic impact from the executive summary of the report, although it cited no new evidence to the contrary. In April 2015,June 2016, the EPA has also published proposed pre-treatmentfinalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the Clean Water Act for wastewater discharges from shale hydraulic fracturing operations.SDWA or other regulatory mechanisms. Congress may consider legislation to amend the Federal Safe Drinking Water ActSDWA or the Toxic Substances Control Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have already issued such disclosure rules. Several environmental groups have also petitioned the EPA to extend release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry and in 2015, EPA granted, in part, one of these petitions to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals"“toxic chemicals” under the Toxic Release Inventory ("TRI"(“TRI”). On January 6, 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. In addition, the Department of the Interior finalized expanded or new regulations concerning the use of hydraulic fracturing on lands under its

In Colorado, certain local jurisdictions imposed moratoria or bans on hydraulic fracturing, all of which have been invalidated, including on appeal to the Colorado Supreme Court. In 2016, citizen initiativesSenate Bill 19-181 subsequently authorized local jurisdictions to empower local governments toapprove the siting of and regulate or prohibitthe surface impacts from oil and gas development and to adopt regulations and impose conditions more stringent than state requirements. In the wake of Senate Bill 19-181 several local jurisdictions established temporary moratoriums, citing a 2,500' statewide setback from occupied buildings and a variety of water ways and other natural resource areas failed to attract enough signaturesneed for the rules required by Senate Bill 19-181 to be certified for the ballot. On the other hand, another ballot initiative, supported by the industry and business community, as well as a number of elected officials made the ballot and was approved by the electorate. This "Raise the Bar" initiative was designedenacted. It remains unclear whether local governments will attempt to make it muchuse this new authority to more difficult to qualify ballot initiatives to amend the state constitution, and raised the vote threshold to enact such measures into law. Proposition 112, which was included on the ballot for the November 2018 election in Colorado but was defeated at the polls, would have amended the Colorado Oil and Gas Conservation Act to, among other things, require all newpermanently restrict hydraulic fracturing or oil and gas development not on federal land toor whether such action would be located at least 2,500 feet away from any occupied structure or broadly defined "vulnerable area". If enacted, Proposition 112 would have effectively prohibited drilling activities across a substantial majority of the surface area of the State of Colorado. Disputes at the local level regarding high-intensity oillawful under SB 19-181 and gas development in proximity to residential areas have not subsided and local ordinances or state legislation may be proposed that could result in additional restrictions on oil and gas development in Colorado. We participate in industry organizations mobilized to combat such measures, including by litigation where necessary.Colorado Supreme Court precedent.

Our operations are subject to other types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, bonds securing plugging, abandonment and reclamation obligations, and reports concerning our operations. Most states, and some counties and municipalities also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing well density and location, as well as the pooling of oil and natural gas properties. Some states provide statutory mechanisms for compulsory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, compulsory pooling or unitization may be implemented by third parties and subject our interest to third party operations. While not currently an issue in Colorado, other states establish maximum rates of production from oil and natural gas wells and impose requirements regarding ratable takes by purchasers of production. Such laws and regulations, if adopted in Colorado, might limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, our production is generally subject to multiple layers of severance and/or ad valorem taxation by states, counties and special taxing districts.

FERC also regulates interstate natural gas transportation rates and service conditions pursuant to the Natural Gas Act, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Interstate gas pipeline companies are required to provide nondiscriminatory, non-preferential transportation services to producers, marketers and other shippers regardless of whether such shippers are affiliated with an interstate pipeline company, and pursuant to such orders, regulations, and rules, interstate gas pipeline companies are required to file the tariff rates and other terms and conditions of such services with FERC.

The Energy Policy Act of 2005 (the "EPAct 2005"“EPAct 2005”) was signed into law in August 2005. The EPAct 2005 amends the Natural Gas Act to make it unlawful for "any entity"“any entity”, including otherwise non-jurisdictional producers, to use any deceptive or

FERC'sFERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach pursued by FERC and Congress over the past few decades will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have on our natural gas-related activities.

As of February 5, 2019,4, 2021, we had 162124 employees of whom 11071 work in our Denver office and 5253 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

As of December 31, 2018,2020, we leased 81,833have 79,279 square feet of leased office space for our principal office in Denver, Colorado at 1099 18th555 17th Street, which expires in March 2019. Due to the Merger, we acquired 23,363April 2028. We also have 15,160 square feet of remaining leased office space from Fifth Creek in Greenwood Village, Colorado, which was acquired in the 2018 Merger and extends through July 2023. In addition, we entered into a new lease for 79,279 square feet of office space in Denver, Colorado which will serve as our principal office starting in March 2019 through April 2028. We also own a field office in Greeley, Colorado and lease a field office in Hereford, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

As required by New York Stock Exchange rules, on December 19, 2018April 30, 2020 we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

Our revenue, profitability and cash flow depend upon the prices for oil, natural gas and NGLs. The markets for these commodities are very volatile, based on supply and demand, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor

Lower oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore the quantity and the estimated present value of our reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down or impair, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management'smanagement’s plans change with respect to those assets. We recorded impairment charges of $572.4 million in the year ended December 31, 2015 on our proved and unproved

As described above, oil, and gas properties, and may record similar charges in the future.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. 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 such as lease expirations, changes in drilling plans and growth rates. Low commodityadverse drilling results, we may be required to take an impairment against the carrying value of our properties. An impairment constitutes a non-cash charge to earnings. For the year ended December 31, 2020, we recorded non-cash impairment charges of approximately $1.3 billion on proved and unproved oil and gas properties, and if market or other economic conditions deteriorate further or if oil and gas prices impactcontinue to decline, we may incur additional impairment charges, which may have a material adverse effect on our revenue, which we partially mitigate with our hedging program. Continued low commodity prices make it more challenging to hedge production at higher price levels.results of operations.

Drilling for oil, natural gas and NGLs may involveresult in unprofitable efforts from wells that are productive but do not produce sufficient commercial quantities to cover drilling, operating and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues, midstream constraints and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil, natural gas or NGLs are present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in some of our plays may be more uncertain than in other plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and/or impairment charges due to any of these factors.

We have acquired significant amounts of proved and unproved property in order to attempt to further our exploration and development efforts. Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire proved and unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. We cannot guarantee that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such proved or unproved property or wells, or that we will succeed in bringing on additional partners.

Our operations are focused on the DJ Basin, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many 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 oil, natural gas and NGLs produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.

Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of contaminated soil and groundwater, protection of surface and groundwater, land reclamation and preservation of natural resources. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects, leading to delays. One of the first actions of the new Biden Administration was to suspend the processing of federal permits, followed by a 90-day hiatus of the federal leasing program.

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

We are not insured against all risks. Losses and liabilities arising from uninsured or under-insured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

We have elected, and may in the future elect, not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, we do not carry business interruption insurance for these reasons. In addition, pollution and environmental risks generally are not fully insurable. Further, we could be unaware of a pollution event when it occurs and therefore be unable to report the event within the time period required under the relevant policy. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations and overall financial condition.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production and acquisition of oil, natural gas and NGL reserves. To date, we

If our revenues or the borrowing base under our Amended Credit Facility decreasesdecrease as a result of lower oil, natural gas and NGLs prices, which was the case for both semi-annual borrowing base redeterminations in 2020, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. We may, from time to time, need to seek additional financing. Our Amended Credit Facility and senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing. Recent commodity price decreases have made it substantially more difficult for us and other industry participants to raise capital, and will likely continue to have an adverse effect on our borrowing base.

If additionalOur future drilling plans were suspended in 2020 and continue to be suspended due to significant declines in commodity prices and a decrease in borrowing capacity on our Credit Facility. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, and that agreement restricts our near-term capital is needed,spending levels and does not allow for drilling or completion operations. Furthermore, if the Merger does not close as contemplated, we maydo not be ablehave assurance that we will have the capital availability to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our Amended Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could resultresume drilling and completion operations. This resulted in a curtailmentreduction in our oil, natural gas and NGL reserves as of December 31, 2020 primarily due to removing all PUD reserves, as we are not reasonably certain the PUD reserves will be drilled within the five year development window at the time the applicable PUD reserve is booked. Continued delays in our operations relating to exploration and development of our prospects, which in turnplans could lead to a possible loss of properties and a declineadditional declines in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. Because of these uncertainties, we

The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for, develop and produce oil, natural gas and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for producing oil, natural gas and NGLs properties and exploration and development prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors are better able than we are to absorb the burden of existing and any changes to federal, state, local and Native American tribal laws and regulations, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial resources than many companies in our industry, we may be at a disadvantage in bidding for producing properties and exploration and development prospects.

Our Amended Credit Facility has commitments from 11 lenders. If credit markets become more turbulent as a result of anthe current economic downturn, increased regulatory oversight, lower commodity prices or other factors, our lenders may become more restrictive in their lending practices or may be unwilling or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures, operations or meet other obligations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses.

Underground accumulations of oil, natural gas and NGLs cannot be measured in an exact way. Oil, natural gas and NGLs reserve engineering requires estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate.

Our estimates of proved reserves are based on prices and costs determined at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see "Items“Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves"Reserves” and "Supplementary“Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves"Reserves” in this Annual Report on Form 10-K.

Producing oil, natural gas and NGL reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from our existing wells declines in amay be different manner than we have estimated and canmay change under other circumstances. Thus, ourover time. Our future oil, natural gas and NGL reserves and production, and therefore our cash flow and income, are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

One of our strategies is to capitalize on opportunistic acquisitions of oil, natural gas and NGLs reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:

In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.Credit Facility.

Our counterparties are financial institutions that are lenders under our Amended Credit Facility or affiliates of such lenders. The risk that a counterparty may default on its obligations increases when overall economic conditions deteriorate. Losses resulting from adverse economic conditions or other factors may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving lower prices for our production. As a result, our financial condition could be materially adversely affected.

Substantially all of our accounts receivable result from oil, natural gas and NGLs sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil, natural gas and NGLs hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. An economic downturn and/or an extended period of low commodity prices would increase these risks.

If one or more rating agencies downgrades our outstanding debt, future debt issuance could become more difficult and costly. Also, we may be required to provide collateral or other credit support to certain counterparties, which would increase our costs and limit our liquidity.

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information, acquire cash or other assets through theft or fraud or render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and

Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions that are opposed by our board. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and this may limit the price that investors are willing to pay in the future for shares of our common stock.

The Tax Cut and Jobs Act (the "TCJA"“TCJA”) was passed in December 2017 and included provisions that could limit certain tax deductions:

These changes may increase our future tax liability in some circumstances. In addition, proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating certain key

We have significant deferred tax assets for Federal and state NOL carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce our federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"“Code”), the ability to utilize NOL carryforwards to offset future taxable income is subject to limitation if a greater than 50% ownership change occurs ("(“Section 382 change of ownership"ownership”). A Section 382 change of ownership refers to an increase in ownership of more than 50% of our shares by certain groups of shareholders during any three-year period, as determined under certain conventions.