During 2019, we spent $295.7 million in capital expenditures to convert 28.4 MMBoe of PUD reserves to proved developed reserves. We added 30.5 MMBoe of PUD reserves from extensions and discoveries during the year primarily due to (i) an increasenew PUD locations that resulted from our 2019 drilling program, the majority of approximately 14,773 MBoe attributablewhich were in the Upper Wolfcamp A formation in our Texas position and in the 2nd Bone Spring formations in our New Mexico acreage. Revisions to extensions resulting from strategic drillingprevious estimates added 6.5 MMBoe net PUD reserves and consisted of wells delineating our acreage position; (ii) the conversion21.4 MMBoe of approximately 2,112 MBoe from proved undeveloped into proved developed reserves; (iii) a revision inupward revisions partially related to well performance of approximately 2,488 MBoe duerevisions to improved results in completion techniques and adjustments of naturalreflect higher gas and NGL treatment through the gas plants;yields on older wells, which in turn increased total estimated ultimate recovery (“EURs”) for most of our PUD locations. These upward revisions were partially offset by 14.9 MMBoe of negative revisions for downward pricing adjustments (7.5 MMBoe) and (iv) an increasePUD locations that were reclassified to unproven reserves due to: (i) such locations no longer being a part of 23,221 MBoeour active development program, and (ii) 1.0 MMBoe removed for locations no longer expected to be developed within five years of their initial recording in proved undeveloped reserves mainly due to the Silverback Acquisition.

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

As of December 31, 2016,2019, we owned an approximate 67%76% average working interest in 199484 gross (133(368 net) productive wells. Our wells are primarily oil wells (467 gross/354 net productive oil wells) that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.

The following table sets forth information as of December 31, 20162019 relating to our gross and net developed and undeveloped leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

The following table sets forth the gross and net undeveloped acreage, as of December 31, 2016,2019, that will expire over the next five years unless production is established within the spacing units covering the acreage, or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates:dates, or pursuant to other terms of the lease agreements.

The following table sets forth the results of our drilling activity, as defined by wells placed on production, for the periods indicated. Productive wells are thoseexploratory, development or extension wells that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are thoseexploratory, development or extension wells that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.incurring the costs associated with completion as an oil or gas well.

We believe that we have satisfactory title to substantially all of our material assets. Although title to theseproducing properties isin accordance with generally accepted industry standards. Individual properties may be subject to encumbrances in some cases,burdens such as customary interests generally retained in connection with the acquisition of real property, customary royalty, interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxesoverriding royalty, working and other burdens, easements, restrictions and minor encumbrancesoutstanding interests customary in the oilindustry. In most cases, we investigate title and natural gas industry,obtain title opinions from counsel only when we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of theseacquire producing properties or from our interest in these properties or materially interfere with our usebefore commencement of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report.drilling operations.

We market the majority of ourthe production from properties we operate foron account of both our accountourselves and the accountthat of the other working interest owners in these properties. We generally sell our oil, natural gas and NGL production to purchasers at prevailing market prices. We sell allprices, and the majority of our natural gas and NGLs underrevenue contracts withhave terms of greater than twelve months and all of our oil under contracts with terms of less than twelve months.

We normally sell production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2016, sales to Plains Marketing, LP (“Plains”), Shell Trading (US) Company, and Permian Transport and TradingThe tables below present percentages by purchaser that accounted for 48%, 22%, and 11%, respectively,10% or more of our net revenues for the total revenue. For the years ended December 31, 2015 and December 31, 2014, we only had one major customer, Plains, which accounted for 64% and 78%, respectively, of total revenue. periods presented:

During these periods, no other purchaser accounted for 10% or more of our revenue.net revenues. The loss of any of our major purchasers could materially and adversely affect our revenues in the short-term.near-term. However, since crude oil and natural gas are

The oil and natural gas industry is intenselya highly competitive and weenvironment. We compete with both major integrated and other companies that have greater resources. Many of these companies not only explore for and produceindependent oil and natural gas but also carry on midstreamcompanies in all aspects of our business including exploring, developing and refining operationsoperating our properties as well as transporting and market petroleum and other products on a regional, national or worldwide basis. These companiesmarketing our production. Competitive conditions may be ableaffected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to pay morefactors that affect the supply and demand for productive oil and natural gas propertiesproduction, such as price fluctuations (including basis differentials), domestic and exploratory prospects or to define, evaluate, bid forforeign political conditions, weather conditions, the proximity and purchase a greater numbercapacity of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing,pipelines and any changes to, federal, stateother transportation facilities and local lawsoverall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and regulations more easily than we can, which would adversely affect our competitive position.electric power. Our ability to acquire additional propertiesprospects and to discoverfind and develop reserves in the future will be dependent upondepend 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 and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production. OurThe majority of our oil production is transported fromsold at the wellhead to our tank batteries by ourlease as it enters third-party gathering systems.pipelines. The purchaser then transports the oil by truckpipeline or pipelinetruck to a tank farm, another pipeline or a refinery. Our natural gas is generally transported by our gathering lines from the wellhead to a Central Delivery Point (“CDP”)central delivery point and is then is gathered by third-party lines from these CDPs to a gas processing facility. At a small number of our wells, we own natural gas pipeline facilities that connect our wells to third-party natural gas gathering systems located in the vicinity of those wells.

Our operations are substantially affected bysubject to extensive federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including, but not limited to, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affectaffecting the oil and natural gas industry are regularly considered by Congress, the states, FERCregulatory authorities, including the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

The production of oil, and natural gas and NGLs 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 permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in New Mexico and Texas, which regulatesregulate drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of New Mexico and Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, and natural gas and NGLs that we can produce from our wells and to limit the number of wells or the locations at whichwhere we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, New Mexico and Texas imposesimpose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within itstheir jurisdiction.

Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.operations, and as a result we do not expect compliance with such regulatory requirements to affect our operations in any way that is of material difference from our competitors who are similarly situated. However, the failure to comply with these rules and regulations can result in substantial penalties.

Sales of oil, condensate and NGLs from our producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.

Our salesSales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.

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. We rely on third-party pipelinespipeline systems to transport the majority of crude oil produced by ours wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Changes in law and to FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies 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 oil producers and marketers with which we compete.

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. In the past, the federal government 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 NGPA,Natural Gas Policy Act of 1978 (the “NGPA”) and culminated in

The EPfederal Energy Policy Act of 2005 (the “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 amendsamended the NGA to add an anti-market manipulation provision whichthat makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provided FERC with the power to assess civil penalties of up to $1,000,000$1.0 million per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000$1.0 million per violation per day. On June 29, 2016,In January 2020, FERC issued an order (Order No. 826)a final rule increasing theits maximum civil penalty amountsauthority under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of $1,193,970$1,291,894 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, to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) 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, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

We are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and those enforced by the US Commodity Futures Trading Commission (the “CFTC”) under the Commodity Exchange Act, (“CEA”as amended (the “CEA”), and CFTC regulations promulgated thereunder by the CFTC.thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, oras well as the market for financial instruments on

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

Changes in law and to FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action that FERC or state regulatory bodies 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 and marketers with which we compete.

Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statuteslaws and regulations governing the occupational safety and health aspects of our operations, the discharge of materials into the environment, or otherwise relatingand protection of the environment and natural resources (including threatened and endangered species and their habitats). Numerous governmental entities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to environmental protection, some of which carry substantial administrative, civilenforce compliance with these laws and criminal penalties for failure to comply.regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things, (i) require the acquisition of a permit beforepermits to conduct drilling orand other regulated activity commences;activities; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment or injected into formations in connection with drilling and production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process;activities; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require some form of remedial actionmeasures to prevent or mitigate pollution from former and ongoing operations, such as pluggingrequirements to close pits and plug abandoned wells or closing earthen pits; establishwells; (v) apply specific safetyhealth and healthsafety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from operations ordrilling and production operations. Any failure to comply with regulatory filings. In addition, these laws and regulations may restrictresult in the rateassessment of production.administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health and safety laws, and regulations, as amended from time to time, to which our business operations are or may be subject, and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The Resource Conservation and Recovery Act (“RCRA”) and analogouscomparable state laws impose detailed requirements forregulate the generation, handling,transportation, treatment, storage, treatmentdisposal and disposalcleanup of nonhazardoushazardous and hazardousnonhazardous solid wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, specifically excludes drillingsometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development orand production of crude oil, natural gas or geothermal energyand NGLs, if properly handled, are currently exempt from regulation as hazardous wastes. However, these wastes may bewaste under RCRA and,

We currently own, lease or operate numerous properties that have been used for oil, and natural gas development and NGL exploration, production activitiesand processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recyclingtreatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.contamination, the costs of which could be substantial.

The Clean Water Act (the “CWA”) and comparable state laws impose restrictions and strict controls regardingwith respect to the discharge of pollutants, including producedspills and leaks of hazardous substances, into state waters and other oil and natural gas wastes, into or near navigable waters.waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the state. CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other CWA requirements and analogous state laws and regulations.

The CWA also prohibits the discharge of dredge and fill material ininto regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued bypermit. The EPA and the U.S. Army Corps of Engineers issued final rules attempting to clarify the federal jurisdictional reach over Waters of the United States in 2015 (the “Corps”“WOTUS rule”). In September 2015,However, in 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps issuedof Engineers to review the WOTUS rule and, if the agencies’ reviews find that the rule does not meet the executive order’s goal of promoting economic growth while reducing regulatory uncertainty, to initiate a new rules definingrulemaking to repeal or revise the scoperule. Pursuant to the executive order, in June 2017, the EPA and U.S. Army Corps of Engineers formally proposed to rescind the WOTUS rule. In January 2018, the EPA and the U.S. Army Corps of Engineers finalized a rule that would delay applicability of the EPA’s andWOTUS rule for two years, but a federal judge barred the Corps’ jurisdiction under the Clean Water Act with respect to certain typesagencies’

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”(the “OPA”), which amends and augments the oil spill provisions of the Clean Water ActCWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as for example, compressor stations,tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. OverThe need to obtain permits has the next several years, we may be requiredpotential to incur certain capital expenditures for air pollution control equipment or otherdelay the development of our projects. Recently, there has been increased regulation with respect to air emissions related issues.from the oil and natural gas sector. For example, in October 2015, the EPA loweredpromulgated rules in 2012 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”), and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National AmbientEmissions Standards for Hazardous Air Quality StandardPollutants program.

In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rules include NSPS to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on volatile organic compound (“NAAQS”VOC”) emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. Several states and industry groups have filed suit before the U.S. Court of Appeals for ozone from 75 to 70 parts per billion. Statethe D.C. Circuit (the “D.C. Circuit”) challenging the EPA’s implementation of the revised NAAQS could resultmethane rule and the EPA’s legal authority to issue the methane

The EPA also finalized separate rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently,CAA in MayJune 2016

Compliance with one or more of these and other air pollution control and permitting requirements and rules has the potential to delay the development of natural gas, oil and natural gasNGL projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment togreenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations pursuant tounder existing provisions of the federal Clean Air ActCAA that, among other things, requireestablish Prevention of Significant Deterioration (“PSD”) preconstruction and Title V operating permitspermit reviews for certain large stationary sources.sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain preconstructionPSD permits for their GHG emissions arewill also be required to meet “best available control technology” standards that are beingwill typically be established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore oil and natural gas productionlarge GHG emission sources in the United States, on an annual basis,including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls forAs discussed above, federal regulatory action regarding GHG emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. Thesector has focused on methane emissions; however, federal implementation of the finalized 2016 methane rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA hasis uncertain at this time (as also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.discussed above).

While Congress has, from time to time, considered legislation to reduce emissions of GHGs, thereno significant legislation has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.level. In the absence of such federal climate legislation, a number of state and regional effortscap-and-trade programs have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires memberan international climate change agreement in Paris, France that calls for countries to reviewset their own GHG emissions targets and “represent a progression” in their intended nationally determined contributions, which setbe transparent about the measures each country will take to achieve its GHG emission reduction goals, every five years beginning in 2020.emissions targets. The agreement was signed in April 2016, andParis Agreement entered into force on November 4, 2016 upon achieving its threshold for ratification by signatory countries. A long-

Although it is not possible at this time to predict how legislationnew laws or new regulations that may be adopted or issued to address GHG emissions would impact our business, any such future laws, and regulations or legal requirements imposing reporting or permitting 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. Substantialoperations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and natural gasNGLs we produce.produce and lower the value of our reserves. Finally, some scientists have concludedit should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have a materialan adverse effect on our exploration and production operations.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, and/or natural gas and NGLs from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, butcommissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuelspublished final CAA regulations in 2012 and, published permitting guidancemore recently, in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air ActJune 2016, establishing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and advanced notice of proposed rulemaking under the Toxic Substances Control Actpermitting (which are subject to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rulesrevision, as discussed above); published in June 2016 that prohibitan effluent limitation guideline final rule prohibiting the discharge of wastewater from hydraulic fracturing operationsonshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition,plants; and issued in 2014 a prepublication version of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act (“TSCA”) reporting of the Bureau of Land Management finalized ruleschemical substances and mixtures used in hydraulic fracturing. Also, in March 2015, that impose new or morethe BLM adopted rules establishing stringent standards for performingrelating to hydraulic fracturing on federal and American Indian lands. The U.S. District Court ofIn June 2016, a federal district court judge in Wyoming struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That ruling was appealed, but in September 2017 the U.S. Court of Appeals for the Tenth Circuit dismissed the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. However, following the issuance of an executive order by President Trump to review rules related to the energy industry, the BLM initiated a rulemaking to rescind the final rule in December 2017. Shortly after the final rulemaking was issued, the state of California and several environmental groups filed lawsuits against the BLM, the Secretary of the Interior, and the Assistant Secretary for Land and Minerals Management, seeking an injunction and a declaration that the repeal violated numerous federal statutes. After the suits were filed, multiple industry groups and the state of Wyoming sought to intervene and transfer the case to federal court in Wyoming, which decided the initial legal challenge to the Obama administration’s fracking regulations. A hearing was held in January 2020 to consider a motion for summary judgment in the case. However, those legal challenges are still pending. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The BLM has appealed this decision. The appeal remains pending. In addition, Congress has fromfinal report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under certain limited circumstances.”

From time to time, considered legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing under the

In the event that a new, or more stringent federal state or locallevel of legal restrictions relating to the hydraulic fracturing process areis adopted in areas where we operate, we couldmay incur potentially significant addedadditional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and perhaps evenlands administered by the BLM, are frequently subject to permitting delays. Operations on these lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an

The federal Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a 2011 settlement approved by the U.S. District Court for the District of Columbia in September 2011,agreement, the U.S. Fish and Wildlife Service is(the “FWS”) was required to make a determination on listing of more than 250numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Similar protections are offeredThe FWS did not meet that deadline. If we were to migratory birds underhave a portion of our leases designated as critical or suitable habitat, it could adversely impact the Migratory Bird Treaty Act. Thevalue of our leases. In addition, the federal government recently has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found dead near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or could result in limitations on our developmentexploration and production activities, thatwhich could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHAOSHA’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities and to maintain these permits and compliance with their requirements for on-goingongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this

As of December 31, 2016,2019, we had 57195 full-time employees. We hire independent contractors on an as needed basis and have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Our principal executive offices are located at 14011001 Seventeenth Street, Suite 1000,1800, Denver, Colorado 80202, and our telephone number is (720) 441-5515.499-1400. We also leasehave office space in Midland, Texas,Texas; Sugar Land, TexasTexas; Pecos, Texas; and Pecos, Texas.Jal, New Mexico.

Our internet website address is www.cdevinc.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual reportreports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. Information on our website is not incorporated by reference into this reportAnnual Report and should not be considered part of this document.

The public may also read and copy materials we file with the SEC at the SEC’s Public Reference Room, which is located at 100 F Street, NE, Room 1580, Washington, DC 20549. You can obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov.

The prices we receive for our oil, natural gas and NGLs production heavily influence our revenue, cash flows, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, natural gas and NGLs and market uncertainty. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through December 31, 2016, the WTI spot price for oil has declined fromvolatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a highvariety of $107.95 per Bbl on June 20, 2014 to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas has declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, whichadditional factors that are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:including:

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, and natural gas and NGL price movements with any certainty. Compared to 2014, our realized oilFrom 2015 through 2019, the WTI spot price for oil averaged $53.05 per Bbl, which is down substantially from the $60.21 average for the prior five-year period. The Henry Hub average spot price from 2015 fell 47% to $42.43through 2019 of $2.77 per barrel, and further decreased in 2016 to $39.91MMBtu similarly declined from $3.12 per barrel. Similarly, our realized natural gas priceMMBtu, which was the average for 2015 dropped 43% to $2.60 per Mcf and our realized price for the prior five-year period. Likewise,

The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. We have funded and we expect that we will continue to fund, our capital expenditures with cash generated by operations, and borrowings under CRP’s revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially throughfacility and the net proceeds from CRP’s issuance of senior notes. We intend to finance our capital expenditures with cash flow from operations, proceeds received from the contemplated divestiture of our saltwater disposal assets, borrowings under CRP’s revolving credit facility and proceeds from offerings of debt orand equity securities or the sale of assets.securities. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under CRP’s revolving credit facility decrease as a result of lower oil, natural gas and NGL 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 at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under CRP’s revolving credit facility are 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 properties. This, in turn, could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include the following:

Risks that we face while completing wells include the following:

In addition, certain of the new techniques we are adopting, such as infilling drilling and multi-well pad drilling, may cause irregularities or interruptions in production due, in the case of infill drilling, to offset wells being shutshut-in and, in andthe case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Further, many factors may curtail, delay, cancel or cancelotherwise negatively impact our scheduled drilling projects, including the following:

The process of estimating oil and natural gas reserves 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 our reserves. In order to prepare reserve estimates, we must project production rates and 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.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, ourOur estimated proved reserves as of December 31, 2016,2019, and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of $39.25$52.19 per barrel of oil (WTI)(WTI Posted) and $2.48$2.58 per MMBtu (Henry Hub spot), which may be substantially higher or lower than the available spot prices in 2017. If spot2020. For example, if the crude oil and natural gas prices are below such calculated amounts, using more recent pricesused in estimatingour year-end reserve estimates were to increase or decrease by 10%, our proved reserve quantities at December 31, 2019 would increase by 4.4 MMBoe (1%) or decrease by 22.3 MMBoe (7%), respectively, and the pre-tax PV10% of our proved reserves may result in a reduction in proved reserve volumes due to economic limits.would increase by $509.4 million (23%) or decrease by $503.1 million (23%), respectively.

As of December 31, 2016,2019, we have leased or acquired approximately 76,06778,195 net acres, approximately 85%93% of which we operate. As of December 31, 2016,2019, we were the operator on 1,230 of our 1,951 identifiedoperated 349 gross producing horizontal drilling locations. We acquired approximately 35,500 net acres in the Silverback Acquisition, approximately 90% of which we operate. Of the net acres acquired, 1,250 net acres are subject to consents to assign, which are expected to be assigned in the first quarter of 2017.wells. We will have limited ability to exercise influence over the operations of the drilling locations operated by our partners, and there is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, including permitting, and other factors. Because of these uncertain factors, we do not know if the numerous identified drilling locations will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

As of December 31, 2016, approximately 50%2019, over 87% of our total net acreage (approximately 51% of our operated net acreage in Reeves and Ward counties) was held by production. Of the net acreage acquired in the Silverback Acquisition, approximately 37% was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. Some of our leases also expire as to certain depths if continuous drilling obligations are not met. If our leases expire in whole or in part and we are unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas in past years. These drought conditions have led governmental authoritiessome local water districts to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

All of ourOur producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, primarily in West Texas.Texas and New Mexico. At December 31, 2016,2019, all of our total estimated proved reserves were attributable to properties located in this area.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is generally transported from the wellhead toby gathering systems that are either owned by us or third-party midstream companies, although some of our tank batteries by our gathering systems. The oil is theninitially transported by the purchaser by truck to a transportation facility. Our natural gas production is generally transported by third-party gathering lines that are owned either by us or third-party midstream companies from the wellhead to a gas processing facility. WeIn general, we do not control these trucks and other third-party transportation facilities and our access to them may be limited or denied. In some instances, we have contractual guarantees relating to the transportation of our production through firm transportation arrangements, but third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents or other reasons. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or third-party midstream companies or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production.production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

As of December 31, 2016, 70%2019, 51% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs 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 PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.

Accounting rulesguidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and 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, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Recently,Over the last several years, commodity prices have declined significantly. On December 30, 2016, the WTI spot price for crude oil was $53.75 per barrel and the Henry Hub spot price for natural gas was $3.71 per MMBtu, representing decreases of 50% and 54%, respectively, from the high of $107.95 per barrel of oil and $8.15 per MMBtu for natural gas during 2014. Likewise, NGLs have suffered significant recent declinesA sustained or further extended decline in realized prices. NGLs are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flowflows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to stringent, complex and complexevolving federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”)EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our development activities 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 loss to us as a result of claims for:

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further,

We utilize multi-well pad drilling operationswhere practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may be curtailed, delayed or canceled ascause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, of numerous factors, including:

In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, thereThe successful acquisition of producing properties requires an assessment of several factors, including:

The accuracy of these assessments is no guaranteeinherently uncertain. 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 be ablenot reveal all existing or potential problems, nor will it permit us to identify attractive acquisition opportunities. Inbecome sufficiently familiar with the event we are ableproperties to identify attractive acquisition opportunities, wefully assess their deficiencies and capabilities. Inspections may not always be ableperformed 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 completeprovide effective contractual protection against all or part of the acquisition or do soproblems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.an “as is” basis.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to

CertainSome of our propertiesreserves are subjectlocated near urban areas, including the city of Pecos, Texas. If these urban areas expand and develop the area around our operations or the surface above our wells, or if we expand our operations closer to land use restrictions,the urban areas, we may be exposed to additional operational and regulatory risk in that area.  In such event, we may incur additional expenses, including city ordinances, which could limitexpenses relating to mitigation of noise, odor and light that may be emitted in our operations, expenses related to the manner in which we conduct our business. Although none of our drilling locations associated with proved undeveloped reserves as of December 31, 2016 are on properties currently subject to such land use restrictions, such restrictions could affect, among other things, our access to and the permissible usesappearance of our facilities as well as the mannerand limitations regarding when and how we can operate. The process of obtaining permits for drilling or for gathering lines to move our production to market in which we produce oilsuch areas may also be more time consuming and natural gas and may restrict or prohibit drillingcostly than in general.more rural areas.  The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from the drilling of wells.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which industry had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as accessIn addition, to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improveour suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. We cannot predict whether these conditions will exist in the future anyand, if so, what their timing and duration will be. Such shortages or cost increases could delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary forcause us to resume or increaseincur significant expenditures that are not provided for in our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs,capital budget, which could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient numberbusiness, financial condition or results of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.operations.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, suchSuch costs may rise faster than increases in our revenue ifas commodity prices rise, thereby negatively impacting our profitability, cash flowflows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

Under the Domenici-Barton Energy PolicyEP Act of 2005, (“EP Act of 2005”), the Federal Energy Regulatory Commission (“FERC”)FERC has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”)NGA and the Natural Gas Policy Act (“NGPA”)NGPA to impose penalties for current violations of up to $1approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air ActCAA that, among other things, require PSD preconstruction and Title V operating permits for certain large stationary sources. Facilities required to obtain preconstructionPSD permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States, on an annual basis, which include certain of our operations. Furthermore, in MayJune 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. However, the EPA recently indicated that it intends to reconsider certain aspects of this rule, and in June 2017 issued a proposed rulemaking that would stay the requirements of the methane rule for a period of two years. In September 2018, the EPA proposed amendments to the 2016 standards that would reduce the rule’s fugitive emissions monitoring requirements and expand exceptions to controlling methane emissions from pneumatic pumps, among other charges. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Instead, in August 2019, the EPA proposed two options for rescinding the 2016 standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds (VOCs), and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the 2016 standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of VOCs in general. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and tradecap-and-trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, theThe United States isbecame one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. TheIn June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement unless it is onerenegotiated, and in November 2019 formally initiated the withdrawal process, which will result in an exit date of over 70 nations that has ratified or otherwise consented to be bound by the agreement.November 2020. 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. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”)SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air ActCAA establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing (although those standards are currently subject to revisions proposed by the Trump Administration), and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land ManagementBLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. Thelands (which was challenged in a U.S. District Courtfederal trial court, resulting in a decision in June 2016 against the rule, an appeal of that decision, and a U.S. federal appeals court ruling in September 2017 dismissing the appeals and vacating the trial court decision); the rule is currently the subject of a December 2017 final rulemaking by the BLM to rescind it. Shortly after the final rulemaking was issued, the state of California and several environmental groups filed lawsuits against the BLM, the Secretary of the Interior, and the Assistant Secretary for Land and Minerals Management, seeking an injunction and a declaration that the repeal violated numerous federal statutes. After the suits were filed, multiple industry groups and the state of Wyoming struck downsought to intervene and transfer the rulecase to federal court in June 2016. The BLM appealedWyoming, which decided the rulinginitial legal challenge to the Tenth Circuit. This appeals remainsObama administration’s fracking regulations. A hearing was held in January 2020 to consider a motion for summary judgment in the case. However, those legal challenges are still pending. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and belowabove-and-below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed in other states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of saltwater disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

We dispose of large volumes of saltwater gathered from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. Furthermore, regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. It may be costly and time consuming to comply with requirements imposed by these authorities, and compliance may result in delays in the commencement or continuation of our exploration and production. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of saltwater gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to evaluate because weobtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. At December 31, 2016,2019, we had no$175.0 million in borrowings outstanding debt. However, for example, ifunder our entire credit facility borrowing basefacility. Interest is calculated under the terms of $250.0 million was outstanding at December 31, 2016,CRP’s credit agreement based on a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $2.5 million, assuming the $250.0 million of debt was outstanding for the full year.LIBOR spread. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. TheTitle VII of the Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”)CFTC, the SEC and the SECprudential regulators to promulgate rules and regulations implementing the derivatives-related provisions of the Dodd-Frank Act. In October 2011,While most of these regulations are already in effect, the implementation process is still ongoing, and the CFTC issuedcontinues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, we cannot yet predict the ultimate effect of the regulations on our business and, while most of the regulations have been adopted, any new regulations or modifications to setexisting regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.

The CFTC has re-proposed position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions forequivalents, although certain bona fide hedging transactions. Astransactions would be exempt from these newposition limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may have an impact on our ability to hedge exposure to price fluctuation of certain commodities. In addition to the CFTC federal position limit rules are not yet final,regime, designated contract markets (“DCMs”) also have established position limit and accountability regimes. We may have to modify trading decisions or liquidate positions to avoid exceeding such limits or at the impactdirection of those provisionsthe exchange to comply with accountability levels. Further, any such position limit regime, whether imposed at the federal or at the DCM level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.

The Dodd-Frank Act requires that certain classes of swaps be cleared on us is uncertain at this time.

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. As a result, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received, and the standardized measure of our estimated reserves included in this prospectusAnnual Report should not be construed as accurate estimates of the current fair value of our proved reserves.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In particular, we are required to comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

We are subject to income taxes in the United States, and our domestic tax liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

Subject to the restrictions in the priceinstruments governing CRP’s outstanding indebtedness (including CRP’s revolving credit facility and senior notes), CRP and its subsidiaries may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the instruments governing CRP’s outstanding indebtedness do contain restrictions on the incurrence of our securities could contributeadditional indebtedness, these restrictions will be subject to the losswaiver and a number of all or part of your investment. Prior to the closing of the Business Combination, tradingsignificant qualifications and exceptions, and indebtedness incurred in our Class A Common Stock and Public Warrants had been limited. If an active market for our securities develops and continues, the trading price of our securitiescompliance with these restrictions could be volatilesubstantial. As of December 31, 2019, CRP had additional borrowing capacity of $624.2 million under its revolving credit facility (after giving effect to our elected commitment and $0.8 million of outstanding letters of credit), all of which would be secured if borrowed.

CRP’s ability to make scheduled payments on or to refinance its indebtedness depends on our financial condition and operating performance, which are subject to wide fluctuations in response to variousprevailing economic and competitive conditions and certain financial, business and other factors some of which are beyond our control. AnyWe may not be able to maintain a level of cash flows from operating activities sufficient to permit CRP to pay the principal, premium, if any, and interest on CRP’s indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance CRP’s indebtedness will depend on the condition of the factors listed belowcapital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require CRP to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm CRP’s ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The agreements governing CRP’s indebtedness restrict CRP’s ability to dispose of assets and CRP’s use of the proceeds from such disposition. CRP may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit CRP to meet scheduled debt service obligations.

In the future, we may not be able to access adequate funding under CRP’s revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, CRP could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service CRP’s indebtedness.

Although our securities may trade at prices significantly below the priceClass A Common Stock is listed on The NASDAQ Capital Market, we cannot assure you paidthat an active public market will continue for them. In such circumstances,our Class A Common Stock. If an active public market for our Class A Common Stock does not continue, the trading price and liquidity of our securitiesClass A Common Stock will be materially and adversely affected. If there is a thin trading market or “float” for our Class A Common Stock, the market price for our Class A Common Stock may not recoverfluctuate significantly more than the stock market as a whole. Without a large float, our Class A Common Stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our Class A Common Stock may experience a further decline.be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our Class A Common Stock could fluctuate widely in response to several factors, including:

Factors affecting the trading price of our securitiesClass A Common Stock may include:

Many of the factors listed above are beyond our control. In addition, broad market and industry factors may materially harm the market price of our securities irrespective of our operating performance. The stock market in general, and NASDAQ havehas experienced extreme price and volume fluctuations in recent years that have often been unrelated or disproportionate tosignificantly affected the operating performancequoted prices of the particularsecurities of many companies, affected.including companies in our industry. For example, the closing price per share of our common stock as reported by The trading prices and valuationsNASDAQ Capital Market ranged from a high of these stocks, and$22.75 per share in October 2018 to a low of $2.56 per share in February 2020. The changes often appear to occur without regard to specific operating performance. The price of our Class A Common Stock could fluctuate based upon factors that have little or nothing to do with our company and Public Warrants which trade on NASDAQ, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to the Companythese fluctuations could depress the price ofmaterially reduce our securities regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.stock price.

The trading market for our securities will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market or our competitors. Securities and industry analysts do not currently, and may never, publish research on us. If no securities or industry analysts commence coverage of us, our stock price and trading volume would likely be negatively impacted. If any of the analysts who may cover us change their recommendation regarding our securities adversely, or provide more favorable relative recommendations about our competitors, the price of our securities would likely decline. If any analyst who may cover us were to cease coverage of us or fail to regularly publish reports on it, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

Riverstone and its affiliates including our Sponsor, beneficially own approximately 44.0%28% of our voting common stock and, upon the conversionas of our Series B Preferred Stock, par value $0.0001 per share (the “Series B Preferred Stock”), will

The interests of Riverstone and its affiliates including our Sponsor, may not align with the interests of our other stockholders. Our SponsorRiverstone is in the business of making investments in companies and may acquire and hold interests in businesses that compete directly or indirectly with us. Riverstone and its affiliates including our Sponsor, may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our Charter provides that we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.

Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:

These provisions, alone or together, could delay hostile takeovers and changes in control of the Company or changes in our board of directors and management.

As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, (the “DGCL”), which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.

We believe that we are a United States real property holding corporation (a “USRPHC”).corporation. As a result, Non-U.S. holders (defined below in the section entitled “Material U.S. Federal Income Tax Considerations”) that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common Stock during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock and may be required to file a U.S. federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.

None.

From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment-related disputes. WeWhile the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations, or liquidity.

Not applicable.

We have not paid any cash dividends on our Class A Common Stock or Class C Common Stock to date. Our board of directors may from time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations and, accordingly, we do not anticipate the board of directors declaring any dividends in the foreseeablenear future.

We are an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentratedprimarily in the Delaware Basin, a sub-basin of the Permian Basin. Our horizontal wells span an area approximately 45 miles long by 20 miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C.

The oil and natural gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. In 2016, oil prices were volatile, and itIt is likely that oilcommodity prices will continue to fluctuate due to the ongoing global supply and demand, imbalance,inventory levels, weather conditions, geopolitical events and other factors. For example, WTI spot prices for crude oil declined significantly to a low of $42.53 per barrel in the second quarter of 2017 but reached a high inventories and geopolitical factors.of $76.41 per barrel in the fourth quarter of 2018, while the average quarterly crude oil price remained below $60 per barrel during the entirety of 2019.

Our revenue, profitability and future growth are highly dependent onThe following table highlights the prices we receivesquarterly average NYMEX price trends for ourcrude oil and natural gas production, as well as NGLs that are extracted from our natural gas during processing. Compared to 2014, our realized oil price for 2015 fell 47% to $42.43 per barrel, and our realized oil price for 2016 further decreased to $39.91 per barrel. Similarly, our realized natural gas price for 2015 dropped 43% to $2.60 per Mcf and our realized price for NGLs declined 52% to $14.66 per barrel. For 2016, our realized price for natural gas was $2.52 per Mcf and our realized price for NGLs was $15.01 per barrel. Lowersince the first quarter of 2017: