As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
During the initial development of our fields we evaluate all gathering and delivery infrastructure in the areas of our production. Currently, a majority of our production in the Midland Basin isand Delaware Basins are transported to purchasers by pipeline. During 2019, several oil and saltwater disposal gathering systems were installed. We believe that these gathering systems will help us reduce our lease operating expense and improve our margins on sales in future periods.
The following table presents the average percentage of produced oil sold by pipeline and the average percentage of produced water connected to saltwater disposals by pipeline:
|
| | | | | | | | |
| Midland Basin | | Delaware Basin | | Total |
% of produced oil sold by pipeline | 94 | % | | 68 | % | | 88 | % |
% of produced water connected to pipeline | 94 | % | | 92 | % | | 93 | % |
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.50%12.5% to 30.00%30.0%, resulting in a net revenue interest to us generally ranging from 70.00%70.0% to 87.50%87.5%.
Seasonal Nature of Business
Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. SeasonalIn our exploration and production business, seasonal weather conditions, such as, for example, the recent severe winter storms in the Permian Basin, and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations. In our midstream operations business, the volumes of condensate produced at Rattler’s processing facilities fluctuate seasonally, with volumes generally increasing in the winter months and decreasing in the summer months as a result of the physical properties of natural gas and comingled liquids. Severe or prolonged summers may adversely affect our results of operations in the midstream operations segment.
Regulation
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.
Environmental Matters and Regulation
Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.
Waste Handling. The Resource Conservation and Recovery Act, or the RCRA, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the Resource Conservation and Recovery Act,RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with
the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservation and Recovery Act,RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or
categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and natural gas waste. It has until MarchHowever, in April 2019, the EPA concluded that revisions to determine whether any revisionsthe federal regulations for the management of oil and natural gas waste are necessary.not necessary at this time. Any such changes in thesuch laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law 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. The Clean Water ActCWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act.CWA. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules. The rules2015 rule and the 2019 repeal are subject to several ongoing litigation and have been stayed in more than half the States, including Texas.legal challenges. Also, on December 11, 2018,April 21, 2020, the EPA and the Corps releasedpublished a proposedfinal rule that would replacereplacing the 2015 rule, and significantly reducereducing the waters subject to federal regulation under the Clean Water Act. Such proposal is currently subject to public review and comment, after which additional legal challenges are anticipated.CWA. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act.CWA. Several state and environmental groups have challenged the replacement rule and, on January 20, 2021, the Biden Administration directed the EPA and the Corps to review the rule. To the extent the rule expandsrules expand the range of properties subject to the Clean Water Act’sCWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The Oil Pollution ActOPA is the primary federal law for oil spill liability. The Oil Pollution ActOPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the
requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution ActOPA subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
Non-compliance with the Clean Water ActCWA or the Oil Pollution ActOPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions. The federal Clean Air Act, or the CAA, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air ActCAA that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “–“—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air ActCAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.
Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined thatrecent years, federal, state and local governments have taken steps to reduce emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because, according to thegases. The EPA emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new greenhouse gas emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their greenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.
Additionally, in September 2009, the EPA issuedhas finalized a final rule requiring the reportingseries of greenhouse gas monitoring, reporting and emissions from specified large greenhouse gas emission sources incontrol rules for the U.S., including natural gas liquids fractionators and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded the greenhouse gas reporting rule to include onshore and offshore oil and natural gas productionindustry, and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the greenhouse gas reporting rule to add the reporting of greenhouse gas emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.
As a result of this continued regulatory focus, future greenhouse gas regulations of the oil and gas industry remain a possibility. In addition, the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions of greenhouse gases and almostemissions. Almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas capcap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and trade programs. Althoughnatural gas operations. For example, on November 4, 2020, the U.S. Congress has notTexas Railroad Commission adopted such legislation at this time, it may do so innew guidance on when flaring is permissible, requiring operators to submit more specific information to justify the future and many states continueneed to pursue regulations to reduce greenhouse gas emissions.flare or vent gas.
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced thatAlthough the United States would withdrawwithdrew from the Paris Agreement and begin negotiationseffective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to either re-enter or negotiate an entirely
new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw fromrejoin the Paris Agreement, whether a new agreement can be negotiated,which went into effect on February 19, 2021. The United States has indicated its plan to announce in advance of an April 22, 2021 climate summit its nationally determined contribution, or what terms would be included in such an agreement.its commitment to reduce its national greenhouse gas emissions to meet this objective. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to upholdsupport the commitments set forth in the international accord.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any
such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions, such as, for example, the recent severe winter storms in the Permian Basin, can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.
In addition, onOn June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean Air ActCAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will
likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, Presidentthe Trump Administration directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017,Accordingly, on August 13, 2020, the EPA published a proposed ruleissued final amendments to stay for two years certainthe 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Various state, municipal and environmental groups have challenged the amendments and, on January 20, 2021, President Biden issued an executive order directing the EPA to review the amendments consistent with several policy objective, including reducing greenhouse gas emissions. Thus substantial uncertainty exists regarding the scope of the New Source Performance standards for oil and natural gas operations. The 2012 and 2016 regulations, including fugitive emission requirements. Also, on October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example, reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. The aboveNew Source Performance standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Endangered Species
The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. On August 12, 2019, the U.S. Fish and Wildlife Service and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service jointly published final rules that, among other things, tighten the critical habitat designation process and eliminate certain automatic protections for threatened species going forward. Nevertheless, the designation of previously unprotected species in areas where we operate as threatened or endangered could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.
Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:
following; the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal
of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates or negotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.
Natural Gas Gathering. Although FERC has not made a formal determination with respect to the facilities we considerRattler LLC considers to be natural gas gathering pipelines, we believeRattler believes that ourits natural gas gathering pipelines meet the traditional tests that FERC has used to determine that pipelines perform primarily a gathering function and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated interstate transportation services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the Natural Gas Act of 1938, or NGA, and that the facility provides interstate transportation service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act, or NGPA. Such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, adversely affect our results of operations and cash flow. In addition, if any of ourthe facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.
Even though we consider ourRattler LLC considers its natural gas gathering pipelines to be exempt from the jurisdiction of FERC under the NGA, FERC regulation of interstate natural gas transportation pipelines may indirectly impact gathering services. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release and market center promotion may indirectly affect intrastate markets and gathering services. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure youthere can be no assurance that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.
Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, ourRattler LLC’s natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gatheringGathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on Rattler’s or our operations, but we could be required to incur additional capital expenditures and increased operating costs may result depending on future legislative and regulatory changes.
Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act, and our subsidiary Rattler Midstream Operating LLC has a tariff on file with FERC to perform gathering service in interstate commerce. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline
rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines, including our subsidiary Rattler Midstream Operating LLC, must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Safety and Maintenance Regulation. In our midstream operations, Rattler LLC is subject to regulation by the U.S. Department of Transportation, or DOT, underthe Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including natural gas liquids and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.
Rattler LLC is also subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.
The Pipeline Safety and Job Creation Act, enacted in 2011, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, enacted in 2016, amended the HLPSA and NGPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $218,647 and $2,186,465, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.
PHMSA has undertaken rulemakings to address many areas of this legislation. For example, on October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside High Consequence Areas. The rules, once effective, also extend reporting requirements to certain previously unregulated gathering lines. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act and the PIPES Act, as well as any implementation of PHMSA rules thereunder and/or related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.
States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards. The Railroad Commission of Texas is the agency vested with intrastate natural gas pipeline regulatory and enforcement authority in Texas. The Commission’s regulations adopt by reference the minimum federal safety standards for the transportation of natural gas. In addition, on December 17, 2019, the Commission adopted rules requiring that operators of gathering lines take 'appropriate' actions to fix safety hazards. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Texas. Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Rattler LLC and the entities in which it owns an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the CAA to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.
State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Operational Hazards and Insurance
The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selected wells, comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date), excess umbrella liability and other coverage.
Our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See Item 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.”
We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our
financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.
Generally, we also require our third partythird-party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.
Human Capital
EmployeesWe have developed a culture grounded upon the solid foundation of our core values—leadership, integrity, excellence, people and teamwork—that are adhered to throughout our company. We set a high bar for all of our employees in terms of how they operate and interact, both within the office and out in the field. We challenge them to identify new ways to foster a better future for themselves and for us.
As of December 31, 2018,2020, we had approximately 711732 full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hireutilize independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full timefull-time employees.
Diversity and Inclusion
Equal employment opportunity is one of our core tenets and, as such, our employment decisions are based on merit, qualifications, competencies and contributions. We actively seek to attract and retain an increasingly diverse workforce and continue to cultivate an inclusive and respectful work environment. We deeply value the perspectives and experiences from our diverse team and are proud of our team, rich in a range of ethnic, cultural and ideological backgrounds. Nearly a third of our employees are women and 25% self-identify as ethnic minorities. We have taken various actions during 2020 to increase the diversity in our candidate pool, and broaden our outreach, particularly within our intern program, through various student organizations to support this inclusion effort.
Health and Safety
Protecting employees, the public and the environment is a top priority in our operations and in the way we manage our assets. We are focused on minimizing the risk of workplace incidents and preparing for emergencies as an indelible element of our corporate responsibility. We also strive to comply with all applicable health, safety and environmental standards, laws and regulations.
Through a unified orientation initiative called Basin United, we and other oil and natural gas operators have committed to reduce injuries and fatalities in our industry. We are aligning our employees and independent contractors around the International Association of Oil & Gas Producers Life Saving Rules, safety culture improvements, safety leadership actions and human performance principles. We also involve employees from all operational levels on our Safety Committee, which provides suggested improvements to the overall safety program, recommended preventative measures based on reviewing vehicle and personnel incidents, safety and environmental audits at operational locations and audit and oversight of the Diamondback Hazard Communication Program, in accordance with OSHA regulations.
From 2016 through 2020, we had zero employee work-related fatalities. Our employee OSHA recordable cases, comprising work-related injuries and illnesses that require medical treatment beyond first aid, totaled three in 2020, flat from three in 2019. Our employee total recordable incident rate (TRIR) in 2020 was flat from 2019 and lost-time incident rate (LTIR) decreased in 2020. We have set a short-term target of maintaining an employee TRIR of 0.5 or less.
Training and Development
We support employees in pursuing training opportunities to expand their professional skills. Our internal course offerings in 2020 included a wide array of topics such as Excel Power Lunch, Performance Management, COVID-19 Safety Training, as well as various and extensive safety and other compliance training sessions. In 2020, our team completed nearly 8,000 hours of training. Additionally, our people also undergo training and education each year on regulatory compliance, industry standards and innovative opportunities to effectively manage the challenges of developing our resources.
Our Facilities
Our corporate headquarters is located at the Fasken Center in Midland, Texas. We also lease additional office space in Birmingham, Alabama, Houston, Texas, Midland, Texas and Oklahoma City, Oklahoma. We believe that our facilities are adequate for our current operations.
Availability of Company Reports
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.diamondbackenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Form 10-KAnnual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
ITEM 1A. RISK FACTORS
The nature of our business activities subjects us to certain hazards and risks. The following is a summary of somethe principal risks that could adversely affect our business, operations and financial results. Please refer to Item 1A “Risk Factors” of this Form 10-K below for additional discussion of the material risks relating to our business activities. Other risks are describedsummarized in Item 1. “Business and Properties” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently knownthis Risk Factors Summary.
Risks Relating to the Company or that we currently deemPending Merger and to Diamondback Following the Completion of the Pending Merger
•The pending merger may not be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operationscompleted and the tradingmerger agreement may be terminated in accordance with its terms, which could negatively impact the price of our sharescommon stock and our results.
•We will incur significant transaction and merger-related costs in connection with the pending merger.
•We and our subsidiaries will have substantial indebtedness after giving effect to the pending merger, which may limit our financial flexibility and adversely affect our financial results.
•An adverse ruling in the pending or any future lawsuits relating to the merger could decline.result in an injunction preventing the completion of the merger and/or substantial costs to us and QEP.
Risk Related to Our Recently Completed Merger with Energen
The integration of Energen’s business into our business may not be as successful as anticipated, and we•We may not achieve the intended benefits of the pending merger or do so within the intended timeframe.
We completed the merger with Energen on November 29, 2018. The merger involves numerous operational, strategic, financial, accounting, legal, taxtimeframe, and other risks, including potential liabilities associated with the acquired business. Difficulties in integrating Energen’s business into our business, and our ability to manage the combined company, may result in the combined company performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have an adverse effect on our financial condition, results of operations or cash flows. Potential difficulties that may be encountered in the integration process include, among other factors:
the inability to successfully integrate the businesses of Energen into our business, operationally and culturally;
complexities associated with managing the larger, more complex, integrated business;
complexities resulting from the different accounting methods of our company and Energen;
not realizing anticipated operating synergies;
integrating personnel from the two companies and the loss of key employees;
potential unknown liabilities and unforeseen expenses associated with the merger or integration;
integrating relationships with customers, vendors and business partners;
performance shortfalls as a result of the diversion of management’s attention caused by integrating Energen’s operations into operations; and
the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies encountered during integration of our business with that of Energen.
Additionally, the success of the merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and Energen’s businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the mergerit may not be realized fully or at all,accretive, and may take longerbe dilutive, to realize than expected or could have other adverse effects that we do not currently foresee.our earnings per share.
Our results may suffer if we do not effectively manage our expanded operations following the merger.
Following the merger, the size of our business increased significantly beyond the former size of our business. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of Energen into our business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows.
Sales of substantial amounts of our common stock in the open market, by former Energen shareholders or otherwise, could depress our common stock price.
Our stockholders may not wish to continue to invest in the additional operations of the combined company, or for other reasons may wish to dispose of some or all of their interests in the combined company, and as a result may seek to sell their shares of our common stock. Shares of our common stock that were issued to the former holders of Energen common stock in the merger are freely tradable by such stockholders without restrictions or further registration under the Securities Act of 1933, which we refer to as the Securities Act, provided, however, that any stockholders who are our affiliates will be subject to the resale restrictions of Rule 144 under the Securities Act. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner. In the merger, we issued approximately 62.8 million shares of our common stock to Energen shareholders. As of February 15, 2019, we had approximately 164,381,522 shares of common stock outstanding and approximately 77,659 shares of common stock subject to unvested restricted stock units outstanding.
If our stockholders sell substantial amounts of our common stock in the public market following, the market price of our common stock may decrease. These sales might also make it more difficult for us to raise capital by selling equity or equity-related securities at a time and price that it otherwise would deem appropriate.
•The market price of our common stock will continue to fluctuate after the pending merger is completed, and may decline if the benefits of the pending merger do not meet the expectations of financial analysts.
The market price of our common stock may fluctuate significantly following•Following the merger, including if we do not achieve the perceived benefitscompletion of the merger as rapidly, or to the extent anticipated by, financial analysts or the effect of the merger on our financial results is not consistent with the expectations of financial analysts. If the price of our common stock decreases, our stockholders will lose some or all of the value of their investment in our common stock. In addition, the stock market has experienced significant price and volume fluctuations in recent times which, if they continue to occur, could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.
In connection with thepending merger, we incorporated Energen’smay incorporate QEP’s hedging activities into our business. We will bear all of the economic impact of such hedgesbusiness and, as a result, may be exposed to additional commodity price risks arising from such hedges. Actual crude oil, natural gas
•The combined company may record goodwill and natural gas liquids pricesother intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined company in the future.
•The combined company may differ fromnot be able to retain customers or suppliers, and customers or suppliers may seek to modify contractual obligations with the combined company, either of which could have an adverse effect on the combined company’s expectationsbusiness and as a result, such hedges could have a negative impact on our business.operations.
Risks Related to the Oil and Natural Gas Industry and Our Business
•Our business and operations have been and will likely continue to be adversely affected by the ongoing COVID-19 pandemic.
•Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas have in the past adversely affected, and may in the futurecontinue to adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:
the domestic and foreign supply of oil and natural gas;
the level of prices and expectations about future prices of oil and natural gas;
the level of global oil and natural gas exploration and production;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the price and quantity of foreign imports;
political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
speculative trading in crude oil and natural gas derivative contracts;
the level of consumer product demand;
weather conditions and other natural disasters;
risks associated with operating drilling rigs;
technological advances affecting energy consumption;
the price and availability of alternative fuels;
domestic and foreign governmental regulations and taxes;
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and
overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $26.19 per barrel, or Bbl, in February 2016 to a high of $107.95 per Bbl in June 2014. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. During 2018, WTI prices ranged from $44.48 to $77.41 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On January 28, 2019, the WTI posted price for crude oil was $51.79 per Bbl and the Henry Hub spot market price of natural gas was $3.05 per MMBtu, representing decreases of 33% and 51%, respectively, from the high of $77.41 per Bbl of oil and $6.24 per MMBtu for natural gas during 2018. In response to recent declines in commodity prices, many producers have reduced their capital expenditure budgets. If the prices of oil and natural gas remain at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growth may have an adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
Our development and exploration operations and our ability to complete acquisitions require substantial capital and we•We may be unable to obtain needed capital or financing on satisfactory terms or at all to fund our acquisitions or development activities, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2018, our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $3.3 billion. Our 2019 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $2.7 billion to $3.0 billion, representing an increase of 85% over our 2018 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.
We intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:
our proved reserves;
the volume of oil and natural gas we are able to produce from existing wells;
the prices at which our oil and natural gas are sold;
our ability to acquire, locate and produce economically new reserves; and
our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2019 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production,
revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.production.
•Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings, and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, 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 identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our recently completed and pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact
our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may incur losses as a result of title defects in the properties in which we invest.invest may lead to losses.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.
Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.
•Our identified potential drilling locations which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 11,868 gross (7,633 net) identified economic potential horizontal drilling locations in multiple horizons on•Despite our acreage. As of December 31, 2018, only 416 of our gross identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 3,195 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of 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 sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist,hedging activities, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2018, we are the operator of, have participated in, or have
acquired a total of 1,465 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where 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, which may cause volatility in our quarterly operating results.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2018, we had leases representing 37,536 net acres expiring in 2019, 27,690 net acres expiring in 2020, 6,867 net acres expiring in 2021, 254 net acres expiring in 2022 and no net acres expiring in 2023. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2019, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.
We have entered into fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options and may in the future enter into forward sale contracts or additional fixed price swap, fixed price basis swap derivatives or costless collars for a portion of our production. Although we have hedged a portion of our estimated 2018 and 2019 production, we may still be adversely affected by continuing and prolonged declines in the price of oil.
We use fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our oil and natural gas sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oilmay be exposed to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. Under the Company’s costless collar contracts, we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the call option price. The counterparty is required to make a payment to us if the settlement price for any settlement period is less than the put option price. These contracts and any future economic hedging arrangements may expose us to risk of financial loss in certain circumstances,other risks, including instances where production is less than expected or oil prices increase.
As of December 31, 2018, we had the following commodity contracts in place covering NYMEX WTI (Cushing and Magellan East Houston) crude oil, Brent crude oil and NYMEX Henry Hub and Waha Hub natural gas for the production period of January 2019 through December 2019:
crude oil swap contracts priced at a weighted average price of $61.07 WTI Cushing for 10,638,000 aggregate Bbls;
crude oil swap contracts priced at a weighted average price of $72.39 WTI Magellan East Houston for 1,270,000 aggregate Bbls;
crude oil swap contracts priced at a weighted average price of $68.02 Brent for 2,005,000 aggregate Bbls;
crude oil basis swap contracts priced at a weighted average price of $(5.56) for 17,012,000 aggregate Bbls for the spread between the WTI Midland price and the WTI Cushing price;
natural gas swap contracts priced at a weighted average price of $3.06 Henry Hub for 25,550,000 aggregate MMBtu;
natural gas basis swap contracts priced at a weighted average price of $(1.60) Waha Hub for 18,250,000 aggregate MMBtu;
natural gas liquid swaps priced at a weighted average price of $27.30 Mont Belvieu for 2,760,000 aggregate Bbls;
crude oil three-way collars contracts with a WTI Cushing short put price of $38.10, floor price of $48.10 and a ceiling price of $63.70 for 7,570,000 aggregate Bbls;
crude oil three-way collars contracts with a WTI Magellan East Houston short put price of $56.82, floor price of $66.82 and a ceiling price of $77.60 for 994,000 aggregate Bbls; and
crude oil three-way collars contracts with a Brent short put price of $55.00, floor price of $65.00 and a ceiling price of $82.47 for 2,000,000 aggregate Bbls.
We have crude oil basis swap contracts priced at a weighted average price of $(1.21) WTI for 15,120,000 aggregate Bbls with a production period of January 2020 through December 2020. To the extent that the prices of oil and natural gas remain at current levels or decline further, we will not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.
Our derivative transactions expose us to counterparty credit risk.
Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
•If production from our Permian Basin acreage decreases, due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to the counterparty and may have an adverse effect onadversely affect our operations.
We are a party to long-term agreements with Trafigura, Shell Trading (US) Company and Vitol under which we are obligated to deliver specified quantities of oil to such companies. Our maximum delivery obligation under these agreements varies for different periods, ranging from 23,750 barrels of oil per day to up to a maximum of 50,000 barrels of oil per day. See “Business and Properties—Marketing and Customers” above. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under the oil purchase agreement, which may result in deficiency payments to the counterparty and may have an adverse effect on our operations.
•The inability of one or more of our customers to meet their obligations, or loss of one or more of our significant purchasers, may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $95.5 million at December 31, 2018) and receivables from purchasers of our oil and natural gas production (approximately $296.5 million at December 31, 2018). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (26%); Koch Supply & Trading LP (15%) and Occidental Energy Marketing Inc (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.
•Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $12.62, $11.11 and $11.23 for the years ended December 31, 2018, 2017 and 2016, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2018, 2017 and 2016 was $594.8 million, $321.9 million and $176.4 million, respectively.
The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.
No impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2018 and 2017. An impairment on proved oil and natural gas properties of $245.5 million was recorded for the years ended December 31, 2016. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates–Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.
Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. •Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves as of December 31, 2018, 2017 and 2016 (which include those attributable to Viper)•We are based on reports prepared by Ryder Scott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The estimates of reserves as of December 31, 2018, 2017 and 2016 included in this report were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods December 31, 2018, 2017 and 2016, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods.
The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.
The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities–Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe because they have become uneconomic or otherwise.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 35% of our total estimated proved reserves as of December 31, 2018, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operatingour primary operations concentrated in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
All of our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays•If transportation or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
In addition to the geographic concentration of our producing properties described above, as of December 31, 2018, all of our proved reserves were attributable to the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (26%); Koch Supply & Trading LP (15%) and Occidental Energy Marketing Inc (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
We have incurred losses from operations during certain periods since our inception and may do so in the future.
Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. 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 often have limited or no production history and consequently we are less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Conservation measures and technological advances could reduce demand for oil and natural gas.
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 services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilitiescontrol, or rigs, equipment, raw materials, oil services or personnel are unavailable, our operations could be interrupted and our revenues reduced.
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 transported from the wellhead to our tank batteries by our gathering system, which interconnects with third party pipelines. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers 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. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. 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. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. 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 adversely affect our financial condition and results of operations.
•Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Our oilexpensive and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge
permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitationsimpose restrictions on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws
•Recent and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business–Regulation” for a description of certain laws and regulations that affect us.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.
In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties–Regulation–Regulation of Hydraulic Fracturing.”
We use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, 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 addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can 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 and 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 exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The Commodities Futures Trading Commission’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the Commodities Futures Trading Commission to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the Commodities Futures Trading Commission has indicated that it intends to appeal the court’s decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.
In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the Commodities Futures Trading Commission will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation 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 legislation 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 legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect ourbusiness, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Ac, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code. Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personal property for a period of time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations and (v) enacts new limitations regarding the deductibility of interest expense. The Tax Act is complex and far-reaching, and while we have evaluated the resulting impact of its enactment on us and recorded adjustments as required in our financial statements, aspects of the Tax Act are unclear and may not be clarified for some time. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes
are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.flow.
Regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties–Regulation–Environmental Regulation-Climate Change.”
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between 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. In addition, a number of lawsuits have been filed in some 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 regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water 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. The Commission has used this authority to deny permits for waste disposal wells.
We dispose of large volumes of produced water gathered from our drilling and production operations by injecting it into wells 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. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by owned disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938 exempts natural gas gathering facilities from regulation by the FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore are exempt from FERC’s jurisdiction under the Natural Gas Act of 1938. However, the distinction between FERC–regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. 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, which could have a material adverse effect on our business, financial condition or results of operations.
Rattler Midstream Operating LLC’s rates are subject to review by federal regulators, which could adversely affect our revenues.
Our subsidiary Rattler Midstream Operating LLC has a tariff on file with FERC to gather crude oil in interstate commerce. Pipelines that gather or transport crude oil for third parties in interstate commerce are, among other things, subject to regulation of the rates and terms and conditions of service by the FERC. Rattler is also subject to annual reporting requirements and may also be required to respond to requests for information from government agencies, including compliance audits conducted by FERC.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
•Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.
Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:
unusual or unexpected geological formations;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages or delivery delays of equipment and services;
compliance with environmental and other governmental requirements; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices
for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to
discover reserves in the future will be dependent upon 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.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D 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. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
We may not be able to keep pace with technological developments in our industry.
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 certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
Increased costs of capital could adversely affect our business.
Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We recorded stock-based compensation expense in 2018, 2017 and 2016, and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.
As a result of outstanding stock-based compensation awards, for the years ended December 31, 2018, 2017 and 2016 we incurred $36.8 million, $34.2 million and $33.5 million, respectively, of stock based compensation expense, of which we capitalized $10.0 million, $8.6 million and $7.1 million respectively, pursuant to the full cost method of accounting for oil and natural gas properties. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and possible future incentive plans. These additional expenses could adversely
affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
•A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist effortsbusiness and other armed conflicts involving the United States or other countries maycould adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. business.
We are subject to cyber security risks. •A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.
Risks Related to Our Indebtedness
•Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the senior notesour indebtedness, and we and our other indebtedness.
As of December 31, 2018, we had total long-term debt of $4.5 billion, including $2.1 billion outstanding under our 4.750% Senior Notes due 2024, which we refersubsidiaries may be able to as the 2024 Notes, our 5.375% Senior Notes due 2025, which we refer to as the 2025 Notes and an aggregate of $530.0 million of notes issued by Energen, which became our wholly owned subsidiary at the effective time of the merger, which notes remained outstanding following the closing of the merger and are collectively referred to as the Energen Notes, and we had an unused borrowing base availability of $0.5 billion under our revolving credit facility. As of December 31, 2018, Viper, one of our subsidiaries, had $411.0 million in outstanding borrowings, and $144.0 million available for borrowing, under its revolving credit facility. We mayincur substantial additional indebtedness in the future incur significant additional indebtednessfuture.
•A reduction in availability under our revolving credit facility orand the inability to otherwise in order to make acquisitions, to developobtain financing for our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following:
our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including any repurchase obligations that may arise thereunder;
a significant portion of our cash flows could be used to service the senior notes and our other indebtedness, which could reduce the funds available to us for operations and other purposes;
a high level of debt could increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry;
a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redeterminationcapital programs could require us to repay a portion of our then-outstanding bank borrowings;
a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;
a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering ofcurtail our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.expenditures.
•Restrictive covenants in certain of our revolving credit facility, the indentures governing the senior notesexisting and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
Our revolving credit facility and the indentures governing our outstanding senior notes contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things:
incur or guarantee additional indebtedness;
make certain investments;
create additional liens;
sell or transfer assets;
issue preferred stock;
merge or consolidate with another entity;
pay dividends or make other distributions;
designate certain of•We depend on our subsidiaries as unrestricted subsidiaries;
create unrestricted subsidiaries;
engage in transactions with affiliates; and
enter into certain swap agreements.
In connection with the closing of Viper’s initial public offering on June 23, 2014, we entered into an amendment to our revolving credit facility, which modified certain provisions of our revolving credit facility to allow us, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under the amended revolving credit facility, we designated Viper, the general partner and Viper’s subsidiary as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the amended revolving credit facility, including the related guaranty, and all liens on the assets of, and the equity interests in, Viper, the general partner and Viper’s subsidiary under the amended revolving credit facility were automatically released. Further Viper, the general partner and Viper’s subsidiaries, Viper Energy Partners LLC and Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), are designated as unrestricted subsidiaries under the indentures governing our outstanding senior notes.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indentures governing our senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interestfor dividends, distributions and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.payments.
Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.
Availability under our revolving credit facility is currently subject to a borrowing base of $2.65 billion, of which we have elected a commitment amount of $2.0 billion. The borrowing base is subject to scheduled annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2018, we had $1.5 billion borrowings outstanding under our revolving credit facility, of which approximately $559.0 million was used by us to repay in full all borrowings under Energen’s credit facility outstanding immediately prior to the effective time of the merger. Our weighted average interest rate on borrowings under our revolving credit facility was 4.10% on December 31, 2018. We expect to borrow under our revolving credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance
our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indentures governing our senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2018, our borrowing base under our revolving credit facility was set at $2.65 billion, of which we have elected a commitment amount of $2.0 billion and we had $1.5 billion of outstanding borrowings under this facility, of which approximately $559.0 million was used by us to repay in full all borrowings under Energen’s credit facility outstanding immediately prior to the effective time of the merger. As of December 31, 2018, Viper had $411.0 million in outstanding borrowings, and $144.0 million available for borrowing, under its revolving credit facility. Further, the indentures governing the senior notes allow us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indentures governing the senior notes also allow us to incur certain other additional secured debt and allows us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
•If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
•Borrowings under our, Viper LLC’s and Viper’sRattler LLC’s revolving credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2018, we had $1.5 billion borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 4.10% on December 31, 2018. Viper’s weighted average interest rate on borrowings from its revolving credit facility was 4.34% during the year ended December 31, 2018. As of December 31, 2018, Viper had $411.0 million in outstanding borrowings, and $144.0 million available for borrowing, under its revolving credit facility. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
Risks Related to Our Common Stock
•The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
•If the price of our common stock fluctuates significantly, your investment could lose value.
•The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors, and there is no guarantee that we will pay any dividends on or repurchases of our common stock in the future or at levels anticipated by our stockholders.
•A change of control could limit our use of net operating losses.
•If our operating results do not meet expectations of securities or industry analysts, our stock price could decline.
•We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
•Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.
ITEM 1A. RISK FACTORS
The nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in Item 1. “Business and Properties,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.
Risks Relating to the Pending Merger
The pending merger may not be completed and the merger agreement may be terminated in accordance with its terms. Failure to complete the pending merger could negatively impact the price of shares of our common stock and our future businesses and financial results.
The pending merger is subject to a number of conditions that must be satisfied, including the approval by QEP stockholders of the merger agreement proposal, or, to the extent permitted by applicable law, waived, in each case prior to the completion of the pending merger. The conditions to the completion of the pending merger, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the pending merger may be delayed or may not be completed.
In addition, if the pending merger is not completed by June 30, 2021, or, in certain instances, on or before September 30, 2021, either we or QEP may choose not to proceed with the pending merger by terminating the merger agreement, and the parties can mutually decide to terminate the merger agreement at any time, before or after stockholder approval. Further, either we or QEP may elect to terminate the merger agreement in certain other circumstances specified in the merger agreement. If the transactions contemplated by the merger agreement are not completed for any reason, our ongoing business, financial condition and financial results may be adversely affected. Without realizing any of the benefits of having completed the transactions, we will be subject to a number of risks, including the following:
•we may be required to pay our costs relating to the transactions, which are substantial, such as legal, accounting, financial advisory and printing fees, whether or not the transactions are completed;
•time and resources committed by our management to matters relating to the transactions could otherwise have been devoted to pursuing other beneficial opportunities;
•we may experience negative reactions from financial markets, including negative impacts on the price of our common stock, including to the extent that the current market price reflects a market assumption that the transactions will be completed;
•we may experience negative reactions from employees, customers or vendors; and
•since the merger agreement restricts the conduct of our business prior to completion of the pending merger, we may not have been able to take certain actions during the pendency of the merger that would have benefitted us as an independent company and the opportunity to take such actions may no longer be available.
We will be subject to business uncertainties while the merger is pending, which could adversely affect our business.
Uncertainty about the effect of the pending merger on employees, industry contacts and business partners may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel until the pending merger is completed and for a period of time thereafter and could cause industry contacts, business partners and others that deal with us to seek to change their existing business relationships with us. In addition, the merger agreement restricts the parties to the merger agreement from entering into certain corporate transactions and taking other specified actions without the consent of the other party. These restrictions may prevent us from pursuing attractive business opportunities that may arise prior to the completion of the pending merger.
We will incur significant transaction and merger-related costs in connection with the pending merger, which may be in excess of those anticipated by us.
We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the pending merger, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the pending merger and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.
We will also incur transaction fees and costs related to the integration of the companies, which may be substantial. Moreover, we may incur additional unanticipated expenses in connection with the pending merger and the integration, including costs associated with any stockholder litigation related to the pending merger. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow us to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all. The costs described above, as well as other unanticipated costs and expenses, could have a material adverse effect on the financial condition and operating results of the combined company following the completion of the pending merger.
We and our subsidiaries will have substantial indebtedness after giving effect to the pending merger, which may limit our financial flexibility and adversely affect our financial results.
Under the merger agreement, QEP’s outstanding debt (other than its existing credit facility) will remain outstanding, which debt, as of December 31, 2020 was approximately $1.6 billion and consisted of amounts outstanding under QEP’s senior notes. As of December 31, 2020, we had total long-term debt of approximately $5.6 billion, consisting primarily of the amounts outstanding under our revolving credit facility, our senior unsecured notes, the notes issued by our subsidiary Energen Corporation, the senior notes issued by our publicly traded subsidiaries, Viper and Rattler, and the amounts outstanding under Viper’s and Rattler’s revolving credit facilities.
Our pro forma indebtedness as of December 31, 2020, assuming consummation of the pending merger had occurred on such date and QEP’s senior notes remain outstanding, would have been approximately $7.4 billion, representing an increase in comparison to our indebtedness on a recent historical basis. We believe that post-merger we will retain our investment grade credit ratings and retire the combined company’s pro forma debt at a faster rate than either company would have been able to do absent the pending merger. However, any increase in our indebtedness could have adverse effects on our financial condition and results of operations, including:
•increasing difficulty to satisfy our obligations with respect to our debt obligations, including any repurchase obligations that may arise thereunder;
•diverting a significant portion of our cash flows to service our indebtedness, which could reduce the funds available to us for operations and other purposes;
•increasing our vulnerability to general adverse economic and industry conditions;
•placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that we would be unable to pursue due to our indebtedness;
•limiting our ability to access the capital markets to raise capital on favorable terms;
•impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
•increasing our vulnerability to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
We believe that the combined company will have flexibility to repay, refinance, repurchase, redeem, exchange or otherwise terminate large portions of our outstanding debt obligations. However, there can be no guarantee that we would be able to execute such refinancings on favorable terms or at all, and a high level of indebtedness increases the risk that we may default on our debt obligations, including from the debt obligations of QEP. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. Our future performance depends on many factors independent of the pending merger, some of which are beyond our control, such as general economic conditions and oil and natural gas prices. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.
Lawsuits have been filed against QEP, us, Merger Sub and the members of the QEP board in connection with the merger and additional lawsuits may be filed in the future. An adverse ruling in any such lawsuit could result in an injunction preventing the completion of the merger and/or substantial costs to us and QEP.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements like the merger agreement. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources.
As of February 22, 2021, nine individual lawsuits have been filed by purported QEP stockholders in United States District Courts in connection with the proposed merger. All nine lawsuits name QEP and the members of the QEP board as defendants, and two of the nine lawsuits name us and Merger Sub as defendants. The complaints allege, among other things, that the registration statements relating to the merger on Form S-4 filed by us on January 22, 2021, as amended on Form S-4/A filed on February 3, 2021, and the Schedule 14A Definitive Proxy Statement filed by QEP on February 10, 2021 fail to provide certain allegedly material information concerning the proposed merger in violation of Sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder. In addition to these allegations, some of the complaints allege that the merger consideration to be received by the QEP stockholders in the merger is unfair because the value of the QEP common
stock is in excess of the value of the merger consideration, that the "no solicitation" clause in the merger agreement is improper and that the termination fee contemplated by the merger agreement is excessive.Some of the complaints also assert a breach of fiduciary duty claim under state law against individual QEP board members. Among other remedies, the plaintiffs seek to enjoin the completion of the proposed merger, a recission of the completed merger or rescissory damages, an accounting of damages suffered by the plaintiff, an award of plaintiff’s expenses and attorney’s fees, and other relief.
Each of us and QEP believes that the allegations in the complaints are without merit. Additional lawsuits arising out of the merger may also be filed in the future.
One of the conditions to the closing of the merger is that no injunction by any governmental entity having jurisdiction over us, QEP or Merger Sub has been entered and continues to be in effect and no law has been adopted, in either case that prohibits the closing of the merger. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the merger, that injunction may delay or prevent the merger from being completed within the expected timeframe or at all, which may adversely affect our business, financial position and results of operations.
Additionally, there can be no assurance that any of the defendants will be successful in the outcome of the lawsuits filed thus far or any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect our business, financial condition, results of operations and cash flows.
Risk Factors Relating to Diamondback Following the Completion of the Pending Merger
The integration of QEP into our business may not be as successful as anticipated, and we may not achieve the intended benefits or do so within the intended timeframe.
The pending merger involves numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with the acquired businesses, and uncertainties related to design, operation and integration of QEP’s internal control over financial reporting. Difficulties in integrating QEP into our business may result in us performing differently than expected, operational challenges, or the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:
•the inability to successfully integrate QEP into our business in a manner that permits us to achieve the full revenue and cost savings anticipated from the pending merger;
•complexities associated with managing the larger, more complex, integrated business;
•not realizing anticipated operating synergies;
•integrating personnel from the two companies and the loss of key employees;
•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the pending merger;
•integrating relationships with industry contacts and business partners;
•performance shortfalls as a result of the diversion of management’s attention caused by completing the pending merger and integrating QEP’s operations into our operations; and
•the disruption of, or the loss of momentum in, ongoing business or inconsistencies in standards, controls, procedures and policies.
Additionally, the success of the pending merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and QEP’s businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the pending merger may not be realized fully or at all, may take longer to realize than expected, or could have other adverse effects that we do not currently foresee.
Our results may suffer if we do not effectively manage our expanded operations following the pending merger.
The success of the pending merger will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and QEP’sbusinesses, including the need to integrate the operations and business of QEP into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors, industry contacts and business partners.
The anticipated benefits and cost savings of the pending merger may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. There could also be unknown liabilities and unforeseen expenses associated with the pending merger that were not discovered in the due diligence review conducted by each company prior to entering into the merger agreement.
The pending merger may not be accretive, and may be dilutive, to our earnings per share, which may negatively affect the market price of our common stock.
Because shares of our common stock will be issued in the pending merger, it is possible that, although we currently expect the merger to be accretive to earnings per share, the merger may be dilutive to our earnings per share, which could negatively affect the market price of our common stock.
In connection with the completion of the pending merger, based on the number of issued and outstanding shares of QEP common stock as of February 22, 2021 and the number of outstanding QEP equity awards currently estimated to be payable in our common stock following the merger, we will issue up to approximately 12.4 million shares of our common stock. The issuance of these new shares of our common stock could have the effect of depressing the market price of our common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of shares of our common stock to decline or increase at a reduced rate.
Furthermore, our current stockholders may not wish to continue to invest in the additional operations of the combined company, or for other reasons may wish to dispose of some or all of their interests in the combined company, and as a result may seek to sell their shares of our common stock following, or in anticipation of, completion of the pending merger. The merger agreement does not restrict the ability of former QEP stockholders to sell such shares of our common stock following completion of the pending merger. Therefore, these sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner.
If the pending merger is completed and our stockholders, including former QEP stockholders, sell substantial amounts of our common stock in the public market following the consummation of the pending merger, the market price of our common stock may decrease. These sales might also make it more difficult for us to raise capital by selling equity or equity-related securities at a time and price that it otherwise would deem appropriate.
The market price of our common stock will continue to fluctuate after the pending merger, and may decline if the benefits of the pending merger do not meet the expectations of financial analysts.
Upon completion of the pending merger, holders of QEP common stock who receive merger consideration will become holders of shares of our common stock. The market price of our common stock may fluctuate significantly following completion of the pending merger and holders of QEP common stock could lose some or all of the value of their investment in our common stock. In addition, the stock market has recently experienced significant price and volume fluctuations which could, if such fluctuations continue to occur, have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.
The market price of our common stock may be affected by factors different from those that historically have affected QEP common stock or our common stock.
Our business differs from that of QEP in certain respects, and, accordingly, our financial position or results of operations and/or cash flows after the pending merger is completed, as well as the market price of our common stock, may be affected by factors different from those currently affecting our financial position or results of operations and/or cash flows as an independent standalone company.
Following the completion of the pending merger, we may incorporate QEP’s hedging activities into our business and, as a result, may be exposed to additional commodity price risks arising from such hedges.
To mitigate its exposure to changes in commodity prices, QEP hedges oil and natural gas prices from time to time, primarily through the use of certain derivative instruments. If we assume QEP’s existing derivative instruments or if QEP enters into additional derivative instruments prior to the completion of the pending merger, we will bear the economic impact of the contracts following the completion of the pending merger. Actual crude oil and natural gas prices may differ from the combined company’s expectations and, as a result, such derivative instruments may have a negative impact on our business.
The combined company may record goodwill and other intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined company in the future.
The pending merger will be accounted for as an acquisition by us in accordance with GAAP. Under the acquisition method of accounting, the assets and liabilities of QEP and its subsidiaries will be recorded, as of completion of the pending merger, at their respective fair values and added to those of us. Our reported financial condition and results of operations for the periods after completion of the pending merger will reflect QEP balances and results after completion of the pending
merger but will not be restated retroactively to reflect the historical financial position or results of operations of QEP and its subsidiaries for periods prior to the completion of the pending merger.
Under the acquisition method of accounting, the total purchase price will be allocated to QEP’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the pending merger. The excess of the purchase price over those fair values will be recorded as goodwill. We expect that the pending merger may result in the creation of goodwill based upon the application of the acquisition method of accounting. To the extent goodwill or intangibles are recorded and the values become impaired, the combined company may be required to recognize material non-cash charges relating to such impairment. The combined company’s operating results may be significantly impacted from both the impairment and underlying trends in the business that triggered the impairment.
The combined company may not be able to retain customers or suppliers, and customers or suppliers may seek to modify contractual obligations with the combined company, either of which could have an adverse effect on the combined company’s business and operations. Third parties may terminate or alter existing contracts or relationships with us as a result of the pending merger.
As a result of the pending merger, the combined company may experience impacts on relationships with customers and suppliers that may harm the combined company’s business and results of operations. Certain customers or suppliers may seek to terminate or modify contractual obligations following the completion of the pending merger whether or not contractual rights are triggered as a result of the pending merger. There can be no guarantee that customers and suppliers will remain with or continue to have a relationship with the combined company or do so on the same or similar contractual terms following the closing of the pending merger. If any customers or suppliers seek to terminate or modify contractual obligations or discontinue their relationships with the combined company, then the combined company’s business and results of operations may be harmed. If the combined company’s suppliers were to seek to terminate or modify an arrangement with the combined company, then the combined company may be unable to procure necessary supplies or services from other suppliers in a timely and efficient manner and on acceptable terms, or at all.
QEP also has contracts with vendors, landlords, licensors and other business partners which may require QEP to obtain consent from these other parties in connection with the pending merger. If these consents cannot be obtained, the combined company may suffer a loss of potential future revenue, incur costs and/or lose rights that may be material to the business of the combined company. In addition, third parties with whom Diamondback or QEP currently have relationships may terminate or otherwise reduce the scope of their relationship with either party in anticipation of the closing of the pending merger. Any such disruptions could limit the combined company’s ability to achieve the anticipated benefits of the pending merger. The adverse effect of any such disruptions could also be exacerbated by a delay in the completion of the pending merger or by a termination of the merger agreement.
Declaration, payment and amounts of dividends, if any, distributed to our stockholders will be uncertain.
Although we have paid cash dividends on our common stock in the past, our board of directors may determine not to declare dividends in the future or may reduce the amount of dividends paid in the future. Any payment of future dividends will be at the discretion of our board of directors and will depend on our results of operations, financial condition, cash requirements, future prospects and other considerations that our board of directors deems relevant.
Risks Related to the Oil and Natural Gas Industry and Our Business
Our business and operations have been and will likely continue to be adversely affected by the ongoing COVID-19 pandemic.
The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economies, including contributing to the reduced global and domestic demand for oil and natural gas, which has had and will likely continue to have an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 continues to spread or the response to contain or mitigate the COVID-19 pandemic through the development and availability of effective treatments and vaccines, including the vaccines recently approved by the FDA for emergency use in the U.S., is unsuccessful, we could continue to experience material adverse effects on our business, financial condition and results of operations. Due to the rapid development and fluidity of this situation, we cannot make any prediction as to the ultimate material adverse impact of the COVID -19 pandemic on our business, financial condition and results of operations.
The sharp decline in oil and natural gas prices and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively impact, our exploration and production activities, which has adversely impacted our business, financial condition and results of operations. In addition, lower oil and natural gas prices may adversely affect the borrowing base under our revolving credit facility and estimates of our proved reserves.
In early March 2020, oil prices dropped sharply and then continued to decline reaching negative levels. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021.As a result, downward pressure on commodity prices has continued and could continue for the foreseeable future. We cannot predict if or when commodity prices will stabilize and at what levels.
As a result of the reduction in crude oil demand caused by factors discussed above, we lowered our 2020 capital budget and production guidance, curtailed near term production and reduced our rig count, all of which may be subject to further reductions or curtailments if the commodity markets and macroeconomic conditions worsen. Although we have restored our curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.
Based on the results of the quarterly ceiling test, we were required to record an impairment on our proved oil and natural gas interests for the year ended December 31, 2020. If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows will be adversely impacted.
Other significant factors that are likely to continue to affect commodity prices in future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global political and economic developments, including the Biden Administration’s energy and environmental policies and the impact of the ongoing COVID-19 pandemic on conditions in the U.S. oil and natural gas industry, all of which are beyond our control.
Our results of operations may be also adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.
We cannot predict the ultimate impact of these factors on our business, financial condition and results of operation.
Increased costs of capital could adversely affect our business.
Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.
Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including; the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer
product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2020, NYMEX WTI prices ranged from $(37.63) to $63.27 per Bbl and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2020, our total capital expenditures, including expenditures for drilling, infrastructure and additions to midstream assets, were approximately $1.9 billion. Our 2021 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $1.4 billion to $1.6 billion, representing a decrease of 50% from our 2020 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.
We intend to finance our future capital expenditures for our drilling operations with cash flow from operations, while future acquisitions may also be funded from operations as well as proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including; our proved reserves; the volume of oil and natural gas we are able to produce from existing wells; the prices at which our oil and natural gas are sold; our ability to acquire, locate and produce economically new reserves; and our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2021 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including; recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs, and potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If these acquisitions include geographic regions in which we do not currently operate, as in the case of the pending merger with QEP, we could be subject to unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, 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 identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.
Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.
Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 10,413 gross (6,863 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage. As of December 31, 2020, only 628 of our gross identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 2,708 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of 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 sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2020, we are the operator of, have participated in, or have acquired working interest in a total of 2,380 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where 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, which may cause volatility in our operating results.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2021, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.
We have entered into commodity price derivatives for a portion of our production. Although we have hedged a portion of our estimated 2021 and 2022 production, we may still be adversely affected by continuing and prolonged declines in the price of oil and may be exposed to other risks, including counterparty credit risk.
We use commodity price derivatives to reduce price volatility associated with certain of our oil and natural gas sales. To the extent that the prices of oil and natural gas remain at current levels or decline further, we may not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition may be negatively impacted.
At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. We do not require collateral from our counterparties.
For additional information regarding our outstanding derivative contracts as of December 31, 2020, see Note 15—Derivatives to our consolidated financial statements included elsewhere in this report.
If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.
We are a party to long-term crude oil agreements under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to such companies. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions beyond our control. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $56 million at December 31, 2020) and receivables from purchasers of our oil and natural gas production (approximately $281 million at December 31, 2020). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. For each of the years ended December 31, 2019 and 2018, three purchasers each accounted for more than 10% of our revenue. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.
Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.30, $13.54 and $12.62 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion for oil and natural gas properties for the years ended December 31, 2020, 2019 and 2018 was $1.2 billion, $1.4 billion and $595 million, respectively.
The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.
An impairment on proved oil and natural gas properties of $6.0 billion and $790 million was recorded for the years ended December 31, 2020 and 2019, respectively. No impairments on proved oil and natural gas properties were recorded for the year ended December 31, 2018. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.
Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.
The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 38% of our total estimated proved reserves as of December 31, 2020, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids and extreme weather conditions, such as the recent severe winter storms in the Permian Basin, and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
In addition to the geographic concentration of our producing properties described above, as of December 31, 2020, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. For each of the years ended December 31, 2019 and 2018, three purchasers each accounted for more than 10% of our revenue. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.
Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
We have incurred losses from operations during certain periods since our inception and may do so in the future.
Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of
multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. 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 often have limited or no production history and consequently we are less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Conservation measures and technological advances could reduce demand for oil and natural gas.
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 services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
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 transported from the wellhead to our tank batteries by our gathering system, which interconnects with third party pipelines. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers 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. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. 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. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. 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 adversely affect our financial condition and results of operations.
Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Further, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and
regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business—Regulation” for a detailed description of certain laws and regulations that affect us.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can 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 and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or 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 exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, which we refer to as Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, which we refer to as the CFTC, the SEC, and federal regulators of financial institutions, which we refer to as the Prudential Regulators, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we refer to as the Mandatory Clearing Rule, requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, a rule, which we refer to as the End User Exception, establishing an “end user” exception to the Mandatory Clearing Rule, a rule, which we refer to as the Margin Rule, setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the Non-Financial End User Exception, and a rule imposing position limits, which we refer to as the Position Limit Rule, and also an exception to the Position Limit Rule for swaps that constitute a “bona fide hedging transaction or position” within the definition of such term under the Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Position Limit Rule, which we refer to as the Bona Fide Hedging Exception.
We qualify for the End User Exception to the Mandatory Clearing Rule, we qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule, and each of our existing and anticipated hedging positions constitutes a “bona fide hedging transaction or position” under the Position Limit Rule and we intend to undertake the filing, recordkeeping and reporting necessary to utilize the Bona Fide Hedging Exception under the Position Limit Rule, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving the European Union financial authorities the power to write-down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), which we refer to collectively as Foreign Regulations, which may apply to our transactions with counterparties subject to such Foreign Regulations, which we refer to as Foreign Counterparties, and the U.S. adopted law and rules, which we call the U.S. Resolution Stay Rules, clarifying similar rights of U.S. banking authorities with respect to banking institutions subject to their regulation. The Dodd-Frank Act, the rules which have been adopted and not vacated, the Limit Rule and the U.S. Resolution Stay Rules could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulation, the U.S. Resolution Stay Rules and Foreign 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 contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
Recently enacted U.S. tax legislation as well as future U.S. tax legislation may adversely affect ourbusiness, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.
If third party pipelines or other facilities interconnected to Rattler LLC’s midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our midstream operations could be adversely affected.
Our subsidiary Rattler LLC’s midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. If any of these pipelines or facilitiesbecomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet thequality requirements of such pipelines or facilities, our midstream operations could be adversely affected.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We do not have employment agreements with our executives and may not be able to assure their retention. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.
Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and
other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including; unusual or unexpected geological formations; loss of drilling fluid circulation; title problems; facility or equipment malfunctions; unexpected operational events; shortages or delivery delays of equipment and services; compliance with environmental and other governmental requirements; and adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for
environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are part of our operations, we maintain insurance to protect against claims made for bodily injury and property damage, and that insurance includes coverage for clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have limited coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D 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. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
We may not be able to keep pace with technological developments in our industry.
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 certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
Increased costs of capital could adversely affect our business.
Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and cash flows.
The results of the 2020 U.S. presidential and congressional elections may create regulatory uncertainty for the oil and natural gas industry. Changes in environmental laws could increase our operating costs and adversely impact our business, financial condition and cash flows.
The results of the 2020 U.S. presidential election, as well as a closely divided Congress, may create regulatory uncertainty in the oil and natural gas industry. During his first weeks in office, President Biden has issued several executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and pause new oil and natural gas leasing on public lands. It remains unclear what additional actions President Biden will take and what support he will have for any potential legislative changes from Congress. Further, it is uncertain to what extent any new environmental laws or regulations, or any repeal of existing environmental laws or regulations, may affect our business or operations. However, such actions could significantly increase our operating costs or impair our ability to explore and develop other projects, which could adversely impact our business, financial condition and cash flows.
Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.
We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Risks Related to Our Indebtedness
References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified.
We have relied in the past, and we may rely from time to time in the future, on borrowings under our revolving credit facility to fund a portion of our capital expenditures. Unless we are able to repay borrowings under the revolving credit facility with cash flow from operations and proceeds from equity or debt offerings, implementing our capital programs may require an increase in our total leverage through additional debt issuances. In addition, a reduction in availability under our revolving credit facility and the inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.
We have historically relied on availability under our revolving credit facility to fund a portion of our capital expenditures. We expect that we will continue to fund a portion of our capital expenditures with borrowings under the revolving credit facility, cash flow from operations and the proceeds from debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from debt or equity offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. Instead, we may be required or choose to finance our capital expenditures through additional debt issuances, which would increase our total amount of debt outstanding. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could limit our ability to fund our drilling activities and acquisitions or otherwise finance the capital expenditures necessary to replace our reserves.
Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness.
As of December 31, 2020, we had total consolidated outstanding principal indebtedness of $5.8 billion, including $4.6 billion outstanding under our senior notes and $23 million outstanding under our revolving credit facility, and we had $1.98 billion available for borrowing under our revolving credit facility. As of December 31, 2020, Viper LLC, one of our subsidiaries, had $84 million in outstanding borrowings, and $496 million available for borrowing, under its revolving credit facility and $480 million outstanding under its 5.375% Senior Notes due 2027. As of December 31, 2020, Rattler LLC, one of our subsidiaries, had $79 million in outstanding borrowings, and $521 million available for borrowing, under its revolving credit facility and $500 million outstanding under its 5.625% Senior Notes due 2025.
We may in the future incur significant additional indebtedness under our revolving credit facility or otherwise in order to make acquisitions, to develop our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following: our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our debt instruments, including any repurchase obligations that may arise thereunder; a significant portion of our cash flows could be used to service our indebtedness, which could reduce the funds available to us for operations and other purposes; our high level of debt could increase our vulnerability to general adverse economic and industry conditions; the covenants contained in the agreements governing certain of our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; our high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry; our high level of debt could limit our ability to access the capital markets to raise capital on favorable terms; our high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidies face.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create
liens; sell or transfer assets; issue preferred stock; merge or consolidate with another entity; pay dividends or make other distributions; create unrestricted subsidiaries; and engage in transactions with affiliates.
Under our revolving credit facility we are allowed, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under our revolving credit facility, we designated Viper, Viper’s general partner, Viper’s subsidiary, Rattler, Rattler’s general partner and Rattler’s subsidiaries as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the revolving credit facility, including the related guaranty. Further Viper, Viper’s general partner, Viper’s subsidiaries, Rattler, Rattler’s general partner and Rattler’s subsidiaries are designated as unrestricted subsidiaries under the indentures governing our outstanding senior notes.
We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our and our subsidiaries’ debt instruments. As an example, our revolving credit facility requires us to maintain a total net debt to capitalization ratio. The requirement that we and our subsidiaries comply with these provisions may materially adversely affect our and our subsidiaries ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
A breach of any of these restrictive covenants could result in default under the applicable debt instrument. If default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.
Our indebtedness is structurally subordinated to the indebtedness and other liabilities of our subsidiaries, and our obligations are not obligations of any of our subsidiaries.
Our senior indebtedness obligations are obligations exclusively of Diamondback Energy, Inc. and Diamondback O&G LLC, and not of any of our other subsidiaries. None of our subsidiaries is a guarantor of our senior indebtedness. Any assets of our subsidiaries will not be directly available to satisfy the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes. Except to the extent we are a creditor with recognized claims against our subsidiaries, all claims of creditors of our subsidiaries will have priority over our equity interests in such subsidiaries (and therefore the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes) with respect to the assets of such subsidiaries. Even if we are recognized as a creditor of one or more of our subsidiaries, our claims would still be effectively subordinated to any security interests in the assets of any such subsidiary and to any indebtedness or other liabilities of any such subsidiary senior to our claims. Consequently, our senior indebtedness will be structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries and any subsidiaries that we may in the future acquire or establish. For additional information regarding our subsidiaries outstanding debt as of December 31, 2020, see Note 11—Debt to our consolidated financial statements included elsewhere in this report.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. The indenture governing the 2025 Senior Notes restricts our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
We depend on our subsidiaries for dividends, distributions and other payments.
We depend on our subsidiaries for dividends, distributions and other payments. We are a legal entity separate and distinct from our operating subsidiaries. There are statutory and regulatory limitations on the payment of dividends or distributions by certain of our subsidiaries to us. If our subsidiaries are unable to make dividend or distribution payments to us and sufficient cash or liquidity is not otherwise available, we may not be able to make dividend payments to our stockholders or principal and interest payments on our outstanding indebtedness.
We and our subsidiaries may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our and our subsidiaries’ revolving credit facilities and the indentures restrict, but in each case do not completely prohibit, us from doing so. Further, the indentures governing our and our subsidiaries’ notes allow us to issue additional notes, incur certain other additional debt and to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Borrowings under our, Viper LLC’s and Rattler LLC’s revolving credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our and our subsidiaries’ revolving credit facilities. The terms of our and our subsidiaries’ revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate tied to LIBOR. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. We use interest rate swaps to reduce interest rate exposure with respect to our floating rate debt. Our weighted average interest rate on borrowings under our revolving credit facility was 2.02% during the year ended December 31, 2020. Viper LLC’s weighted average interest rate on borrowings from its revolving credit facility was 2.20% during the year ended December 31, 2020. Rattler LLC’s weighted average interest rate on borrowings from its revolving credit facility was 2.10% during the year ended December 31, 2020. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established or if LIBOR will continue to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere.
Risks Related to Our Common Stock
The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
Subject to the limitations of applicable law, our certificate of incorporation, among other things:
things; permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.
We have engaged in the past and may in the future engage in transactions with our affiliates and expect to do so in the future.affiliates. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.
In the past, we have engaged in transactions with affiliated companies and may do so again in the future. These transactions, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests.
If the price of our common stock fluctuates significantly, your investment could lose value.
Although our common stock is listed on the Nasdaq Global Select Global Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may 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 common stock could fluctuate widely in response to several factors, including:
including; our quarterly or annual operating results;
changes in our earnings estimates;
investment recommendations by securities analysts following our business or our industry;
additions or departures of key personnel;
changes in the business, earnings estimates or market perceptions of our competitors;
our failure to achieve operating results consistent with securities analysts’ projections;
changes in industry, general market or economic conditions; and
announcements of legislative or regulatory changes.
The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.
The declaration of dividends onand any repurchases of our common stock isare each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
On February 13, 2018, we initiated payment of quarterly cash dividends on our common stock payable beginning with the first quarter of 2018. The decision to pay any future dividends, however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the
record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.
In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program is at the discretion of our board of directors and may be suspended from time to time, modified, extended or discontinued by our board of directors at any time. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.
A change of control could limit our use of net operating losses.
As of December 31, 2020, we had a net operating loss, or NOL, carry forward of approximately $2.3 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by an interest rate periodically promulgated by the IRS referred to as the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in ourthe ownership of our stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.
As of December 31, 2018, we had a net operating loss, or NOL, carry forward of approximately $567.8 million for federal income tax purposes, including $58.6 million acquired as part of the Energen acquisition. These acquired NOLs as well as $2.8 million in tax credits acquired from Energen are subject to an annual limitation under Section 382 of the Code.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrade our stock or if our operating results do not meet their expectations, our stock price could decline.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.
The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
including; provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;
limitations on the ability of our stockholders to call a special meeting and act by written consent;
the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and
the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.
These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
DueWe are a party to various legal proceedings, disputes and claims arising in the naturecourse of our business, we are,including those that arise from timeinterpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to time, involved in routine litigation or subjectoil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to disputes or claims related tothird parties and no longer part of our business activities.current operations. While the ultimate outcome of the pending litigation,proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, in the opinion of our management,we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
For additional information regarding contingencies, see Note 17—Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Annual Report.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Price RangeListing and Holders of Common StockRecord
Our common stock is listed on the Nasdaq Global Select Global Market under the symbol “FANG”.
The following table sets forth the range of high and low sales prices of our common stock and dividends payable per share of our common stock for the periods presented:
|
| | | | | | | | | | | |
| High | | Low | | Cash Dividends per Share of Common Stock |
2018 | | | | | |
1st Quarter | $ | 134.60 |
| | $ | 105.66 |
| | $ | 0.125 |
|
2nd Quarter | $ | 138.14 |
| | $ | 107.78 |
| | $ | 0.125 |
|
3rd Quarter | $ | 138.25 |
| | $ | 111.31 |
| | $ | 0.125 |
|
4th Quarter(2) | $ | 140.78 |
| | $ | 85.19 |
| | $ | 0.125 |
|
2017 | | | | | |
1st Quarter | $ | 114.00 |
| | $ | 96.05 |
| | $ | — |
|
2nd Quarter | $ | 108.17 |
| | $ | 83.22 |
| | $ | — |
|
3rd Quarter | $ | 98.36 |
| | $ | 82.77 |
| | $ | — |
|
4th Quarter | $ | 127.45 |
| | $ | 95.69 |
| | $ | — |
|
| |
(1) | The Q4 2018 distribution is payable on February 28, 2918 to unitholders of record at the close of business on February 21, 2019. |
Holders of Record
There were 202,564 holders of record of our common stock on February 15, 2019.19, 2021.
Dividend Policy
We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility restrict the payment of cash dividends on our common stock. See Item 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–Credit Facility.”
On February 13, 2018, we announced the initiation of an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly which began with the first quarter of 2018. Beginning with the first quarter of 2019, the annual cash dividend was set at $0.75 per share of our common stock. Then, beginning with the fourth quarter of 2019, the annual cash dividend was increased to $1.50 per share for our common stock and, beginning with the fourth quarter of 2020, the annual cash dividend was further increased to $1.60 per share of our common stock. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
RecentUnregistered Sales of UnregisteredEquity Securities
On October 31, 2018,As previously disclosed in our Current Report on Form 8-K filed with the SEC on December 21, 2020, we issuedentered into a definitive purchase and sale agreement, dated as of December 18, 2020, with Guidon and certain of Guidon’s affiliates to acquire approximately 2.632,500 net acres in the Northern Midland Basin and certain related oil and gas assets. Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to Ajax and certain other holders as part ofadjustment. The shares to be issued in the consideration for the Ajax acquisition. These shares werePending Guidon Acquisition will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. In connectionWe have agreed to file with the SEC, and use our reasonable best efforts to cause to be declared effective, a shelf registration statement registering for resale these shares within 60 days following the closing of the Ajax acquisitionPending Guidon Acquisition, which is expected to occur on October 31, 2018, we entered into a registration rights agreement with Ajax and certain other holdersFebruary 26, 2021.
Repurchases of Equity Securities
None.
Our common stock repurchase activity for the three months ended December 31, 2020 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Period | | Total Number of Shares Purchased | | Average Price Paid Per Share(1) | | Total Number of Shares Purchased as Part of Publicly Announced Plan | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(2) |
| | ($ in millions, except per share amounts, shares in thousands) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
October 1, 2020 - October 31, 2020 | | — | | $ | — | | | — | | $ | 1,304 | |
November 1, 2020 - November 30, 2020 | | — | | $ | — | | | — | | $ | 1,304 | |
December 1, 2020 - December 31, 2020 | | — | | $ | — | | | — | | $ | — | |
Total | | — | | $ | — | | | — | | |
(1)The average price paid per share is net of any commissions paid to repurchase stock.
(2)In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.
ITEM 6. SELECTED FINANCIAL DATA
This section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report on Form 10-K.[Reserved.]
Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2018, 2017 and 2016 and the balance sheet data as of December 31, 2018 and 2017 are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2015 and 2014 and the balance sheet data as of December 31, 2016, 2015 and 2014 are derived from our audited financial statements not included in this Annual Report on Form 10-K.
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands, except per share amounts) | 2018(1) | | 2017 | | 2016 | | 2015 | | 2014 |
Statements of Operations Data: | | | | | | | | | |
Total revenues | $ | 2,176,256 |
| | $ | 1,205,111 |
| | $ | 527,107 |
| | $ | 446,733 |
| | $ | 495,718 |
|
Total costs and expenses | 1,165,468 |
| | 600,091 |
| | 595,724 |
| | 1,187,002 |
| | 283,048 |
|
Income (loss) from operations | 1,010,788 |
| | 605,020 |
| | (68,617 | ) | | (740,269 | ) | | 212,670 |
|
Other income (expense) | 102,469 |
| | (107,831 | ) | | (96,099 | ) | | (8,831 | ) | | 92,286 |
|
Income (loss) before income taxes | 1,113,257 |
| | 497,189 |
| | (164,716 | ) | | (749,100 | ) | | 304,956 |
|
Provision for (benefit from) income taxes | 168,362 |
| | (19,568 | ) | | 192 |
| | (201,310 | ) | | 108,985 |
|
Net income (loss) | 944,895 |
| | 516,757 |
| | (164,908 | ) | | (547,790 | ) | | 195,971 |
|
Less: Net income attributable to non-controlling interest | 99,223 |
| | 34,496 |
| | 126 |
| | 2,838 |
| | 2,216 |
|
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 845,672 |
| | $ | 482,261 |
| | $ | (165,034 | ) | | $ | (550,628 | ) | | $ | 193,755 |
|
Earnings per common share | | | | | | | | | |
Basic | $ | 8.09 |
| | $ | 4.95 |
| | $ | (2.20 | ) | | $ | (8.74 | ) | | $ | 3.67 |
|
Diluted | $ | 8.06 |
| | $ | 4.94 |
| | $ | (2.20 | ) | | $ | (8.74 | ) | | $ | 3.64 |
|
Weighted average common shares outstanding | | | | | | | | | |
Basic | 104,622 |
| | 97,458 |
| | 75,077 |
| | 63,019 |
| | 52,826 |
|
Diluted | 104,929 |
| | 97,688 |
| | 75,077 |
| | 63,019 |
| | 53,297 |
|
Cash dividends declared per common share | $ | 0.500 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| |
(1) | Our results of operations for 2018 include those of Energen and its subsidiaries acquired by us in the merger from the period of November 29, 2018, the closing date of the merger, through December 31, 2018. |
|
| | | | | | | | | | | | | | | | | | | |
| As of December 31, |
(In thousands) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet Data: | | | | | | | | | |
Cash and cash equivalents | $ | 214,516 |
| | $ | 112,446 |
| | $ | 1,666,574 |
| | $ | 20,115 |
| | $ | 30,183 |
|
Net property and equipment | 20,371,975 |
| | 7,343,617 |
| | 3,390,857 |
| | 2,597,625 |
| | 2,791,807 |
|
Total assets | 21,595,687 |
| | 7,770,985 |
| | 5,349,680 |
| | 2,750,719 |
| | 3,095,481 |
|
Current liabilities | 1,019,612 |
| | 577,428 |
| | 209,342 |
| | 141,421 |
| | 266,729 |
|
Long-term debt | 4,464,338 |
| | 1,477,347 |
| | 1,105,912 |
| | 487,807 |
| | 673,500 |
|
Total stockholders’/ members’ equity(1) | 13,699,287 |
| | 5,254,860 |
| | 3,697,462 |
| | 1,875,972 |
| | 1,751,011 |
|
Total equity | 14,166,262 |
| | 5,581,737 |
| | 4,018,292 |
| | 2,108,973 |
| | 1,985,213 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Other Financial Data: | | | | | | | | | |
Net cash provided by operating activities | $ | 1,564,505 |
| | $ | 888,625 |
| | $ | 332,080 |
| | $ | 416,501 |
| | $ | 356,389 |
|
Net cash used in investing activities | (3,503,043 | ) | | (3,132,282 | ) | | (1,310,242 | ) | | (895,050 | ) | | (1,481,997 | ) |
Net cash provided by financing activities | 2,040,608 |
| | 689,529 |
| | 2,624,621 |
| | 468,481 |
| | 1,140,236 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Consolidated Adjusted EBITDA(2) | $ | 1,539,031 |
| | $ | 928,039 |
| | $ | 387,535 |
| | $ | 449,245 |
| | $ | 398,334 |
|
| |
(1) | For the years ended December 31, 2018, 2017, 2016, 2015 and 2014, total stockholders’ equity excludes $467.0 million, $326.9 million, $320.8 million $233.0 million and $234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP. |
| |
(2) | Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Consolidated Adjusted EBITDA and a reconciliation of Consolidated Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below. |
Non-GAAP financial measure and reconciliation
Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external usersTable of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Consolidated Adjusted EBITDA as net income (loss) plus non-cash (gain) loss on derivative instruments, net, net interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, loss on revaluation of investment, loss on extinguishment of debt, merger and integration expense, income tax (benefit) provision and non-controlling interest in net (income) loss. Consolidated Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. Management believes Consolidated Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We add the items listed above to net income (loss) in arriving at Consolidated Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Consolidated Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Consolidated Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Consolidated Adjusted EBITDA. Our computations of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our revolving credit facility or any of our other contracts.Contents
The following presents a reconciliation of the non-GAAP financial measure of Consolidated Adjusted EBITDA to the GAAP financial measure of net income (loss):
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(In thousands) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Net income (loss) | $ | 944,895 |
| | $ | 516,757 |
| | $ | (164,908 | ) | | $ | (547,790 | ) | | $ | 195,971 |
|
Non-cash loss (gain) on derivative instruments, net | (221,732 | ) | | 84,240 |
| | 26,522 |
| | 112,918 |
| | (117,109 | ) |
Interest expense, net | 87,276 |
| | 40,554 |
| | 40,684 |
| | 41,510 |
| | 34,515 |
|
Depreciation, depletion and amortization | 623,039 |
| | 326,759 |
| | 178,015 |
| | 217,697 |
| | 170,005 |
|
Impairment of oil and natural gas properties | — |
| | — |
| | 245,536 |
| | 814,798 |
| | — |
|
Non-cash equity-based compensation expense | 36,798 |
| | 34,178 |
| | 33,532 |
| | 24,572 |
| | 14,253 |
|
Capitalized equity-based compensation expense | (10,034 | ) | | (8,641 | ) | | (7,079 | ) | | (6,043 | ) | | (4,437 | ) |
Asset retirement obligation accretion expense | 2,132 |
| | 1,391 |
| | 1,064 |
| | 833 |
| | 467 |
|
Loss on revaluation of investment | 550 |
| | — |
| | — |
| | — |
| | — |
|
Loss on extinguishment of debt | — |
| | — |
| | 33,134 |
| | — |
| | — |
|
Merger and integration expense | 36,831 |
| | — |
| | — |
| | — |
| | — |
|
Income tax (benefit) provision | 168,362 |
| | (19,568 | ) | | 192 |
| | (201,310 | ) | | 108,985 |
|
Non-controlling interest in net (income) loss | (129,086 | ) | | (47,631 | ) | | 843 |
| | (7,940 | ) | | (4,316 | ) |
Consolidated Adjusted EBITDA | $ | 1,539,031 |
| | $ | 928,039 |
| | $ | 387,535 |
| | $ | 449,245 |
| | $ | 398,334 |
|
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual Report on Form 10–K.Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
Overview
We are an independent oil and natural gas company focused onoperate in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. OurTexas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.
Upstream Operations
In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all
As of our revenues are generated through the sale of oil, natural gas liquids and natural gas production.
The following table sets forth our production data for the periods indicated:
|
| | | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
Oil (MBbls) | 72 | % | | 74 | % | | 73 | % |
Natural gas (MMcf) | 12 | % | | 12 | % | | 11 | % |
Natural gas liquids (MBbls) | 16 | % | | 14 | % | | 16 | % |
| 100 | % | | 100 | % | | 100 | % |
On December 31, 2018, our acreage position in the Permian Basin was2020, we had approximately 604,367 gross (461,218 net)378,678 net acres, which primarily consisted primarily of approximately 231,100 gross (194,661 net)194,591 net acres in the Midland Basin and approximately 232,143 gross (170,205 net)152,587 net acres in the Delaware Basin. As of December 31, 2020, we had an estimated 10,413 gross horizontal locations that we believe to be economic at $60.00 per Bbl WTI.
2018 was another transformational year for us. We successfully closed three acquisitionsIn addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 787,264 gross acres and 24,350 net royalty acres in the fourth quarterPermian Basin and Eagle Ford Shale. Approximately 52% of 2018, includingthese net royalty acres are operated by us.
Midstream Operations
In our acquisitionmidstream operations segment, Rattler’s crude oil infrastructure assets consist of Energen Corporation, or Energen,gathering pipelines and metering facilities, which acquisitions, on a combined basis, almost doubledcollectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our core acreage position. DuringReWard, Spanish Trail, Pecos and Fivestones areas within the same period, oil prices declined dramatically,Permian Basin. Rattler’s natural gas gathering and we quickly addressedcompression system consists of gathering pipelines, compression and metering facilities, which collectively service the issue by announcing a reduction in activity levels in late 2018production from our Pecos area assets within the Permian Basin. Rattler’s water sourcing and acting on that plan immediately in 2019. At current commodity prices, we expectdistribution assets consists of water wells, frac pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian Basin aquifers to grow production by over 27% year over year within cash flow in 2019, while increasing our dividend by 50% beginning with the first quarter of 2019. By remaining focused on corporate returns and prudent capital allocation, we believe that in the current commodity price environment we are positioned to generate significant free cash flow while continuing to grow production at industry leading rates in 2020 and beyond. We are operating 21 rigs now and currently intend to operate between 18 and 22 rigs in 2019. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion planssites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 517 miles and consists of gathering pipelines along with produced water disposal, or PWD, wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.
We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in response2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to market conditions. provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications.
20182020 Transactions and Recent Developments
COVID-19 and Collapse in Commodity Prices
On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a
widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.
In early March 2020, oil prices dropped sharply and continued to decline reaching negative levels. During 2020, the posted price for the WTI price for crude oil ranged from $(37.63) to $63.27 per barrel, or Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu. On January 29, 2021, the NYMEX WTI price for crude oil was $52.20 per Bbl and the NYMEX Henry Hub price of natural gas was $2.56 per MMBtu. In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021.We cannot predict if or when commodity prices will stabilize and at what levels.
As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance, curtailed near term production and reduced rig count, all of which may be subject to further reductions or curtailment if the commodity markets and macroeconomic conditions worsen.Although we have restored curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.
In addition, as a result of the sharp decline in commodity prices in early March 2020, and the continued depressed oil pricing throughout the second and third quarters of 2020, we recorded $6.0 billion of aggregate non-cash ceiling test impairments for the year ended December 31, 2020. These impairment charges adversely affected our results of operations but did not reduce our cash flows. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Our production, proved reserves and cash flows will also be adversely impacted. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.
Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic conditions will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.
Pending Merger with Energen CorporationQEP Resources, Inc.
On December 20, 2020, we, QEP and the Merger Sub, entered into the merger agreement under which the Merger Sub will be merged with and into QEP, with QEP surviving as our wholly owned subsidiary. If the pending merger is completed, each QEP stockholder will receive, in exchange for each share of QEP common stock held by such stockholder immediately prior to the closing of the pending merger, 0.050 of a share of our common stock. The completion of the pending merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including the receipt of the required approvals from QEP’s stockholders. The pending merger is expected to close shortly following the special meeting of the QEP stockholders, which is scheduled for March 16, 2021, subject to QEP stockholder approval and other customary closing conditions. See “Items 1 and 2. Business and Properties—Overview—Pending Merger with QEP Resources, Inc.” for additional information regarding the pending merger.
We expect that the pending merger will:
•add material Tier-1 Midland Basin inventory;
•be accretive on all relevant 2021 per share metrics including cash flow per share, free cash flow per share and leverage, before accounting for synergies;
•lower 2021 reinvestment ratio and enhance ability to generate free cash flow, de-lever and return capital to our stockholders; and
•realize significant, tangible annual synergies of $60 to $80 million comprised of general and administrative expense savings, cost of capital and interest expense savings, improved capital efficiency from high-graded development of
combined acreage, physical adjacencies to increase lateral lengths and significant adjacent Permian Basin midstream assets.
In addition, we expect to maintain our investment grade credit ratings following the completion of the pending merger.
Pending Guidon Acquisition
On November 29, 2018,December 18, 2020, we completed our acquisitionentered into a definitive purchase and sale agreement with Guidon and certain of EnergenGuidon’s affiliates to acquire approximately 32,500 net acres in an all-stock transaction,the Northern Midland Basin and certain related oil and natural gas assets, which we refer to as the merger. We consolidate our results of operations with those of Energen and its subsidiaries acquired by us in the merger beginning with November 29, 2019, the closing date of the merger. We accountedPending Guidon Acquisition. Consideration for the merger as a business combination.
The additionPending Guidon Acquisition consists of Energen’s assets increased our assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from third quarter 2018 Tier One acreage of approximately 174,000 net acres, (ii) over 7,200 estimated total net horizontal Permian locations, an increase of over 120% from third quarter 2018 estimated net locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each after giving effect to our recently completed Ajax acquisition and ExL acquisition discussed below.
Under the terms of the merger agreement, we assumed Energen’s outstanding debt, which at the effective time of the merger was approximately $1.1 billion. This amount consisted of $559.0 million of borrowings under Energen’s existing credit facility, $400.0 million aggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028, which we collectively refer to as the Energen Notes. In connection with the closing of the Merger, we repaid the outstanding borrowings of $559.0 million under the Energen credit facility using cash on hand and borrowings under our revolving credit facility.
Ajax Resources, LLC
On October 31, 2018, we acquired certain leasehold interests and related assets of Ajax Resources, LLC, which we refer to as Ajax, which included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0$375 million in cash subject to certain adjustments, and approximately 2.610.6 million shares of our common stock, which we refersubject to as the Ajax acquisition. The Ajax acquisition was effective as of July 1, 2018.adjustment. The cash portion of this transaction wasis expected to be funded through a combination of cash on hand proceedsand borrowings under our credit facility. The Pending Guidon Acquisition is expected to close on February 26, 2021.
Fourth Quarter 2020 Dividend Declaration and Increase
On February 18, 2021, our board of directors declared a cash dividend for the fourth quarter of 2020 of $0.40 per share of common stock, payable on March 11, 2021 to our stockholders of record at the close of business on March 4, 2021, representing a 6.7% increase per share from the salepreviously paid quarterly dividend.
Implementation of mineral interestsViper’s Common Unit Repurchase Program
On November 6, 2020, the board of directors of Viper’s general partner approved an expansion of Viper’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Viper Energy Partners LP,repurchased approximately $24 million of its common units under its repurchase program. As of December 31, 2020, $76 million remained available for use to repurchase common units under Viper’s common unit repurchase program.
Implementation of Rattler’s Common Unit Repurchase Program
On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Rattler repurchased approximately $15 million of its common stock under its repurchase program. As of December 31, 2020, $85 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.
May 2020 Notes Offering
On May 26, 2020, we completed a notes offering of $500 million in aggregate principal amount of our 4.750% Senior Notes due 2025, which we refer to as Viper or the Partnership, described below, borrowings under our revolving credit facilityMay 2020 Notes. We received net proceeds of approximately $496 million from the offering of the May 2020 Notes which we used to, among other things, make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. For additional information regarding this notes offering, see “—Liquidity and proceeds from our September 2018 senior note offering. See “—NewCapital Resources—Indebtedness—The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35% Medium-term Notes” below.
In connection with the closing of the Ajax acquisition on October 31, 2018, we entered into a registration rights agreement with Ajax and certain other holders of our common stock pursuant toRattler Notes Offering
On July 14, 2020, Rattler completed an offering, which we filed a shelf registration statement with the SEC to facilitate the resale of common stock issued in the Ajax acquisition. The shelf registration statement became automatically effective on November 30, 2018. Pursuant to this registration rights agreement, we also agreed to provide certain demand and piggyback registration rights to such holders.
On December 11, 2018, we entered into an ATM Equity Offering SM Sales Agreement with Ajax, certain other holders of our common stock and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as sales agent, in connection with potential sales from time to time during the term of the sales agreement by Ajax of up to approximately 2.0 million shares of our common stock under the above-referenced shelf registration statement.
ExL Petroleum Management, LLC and EnergyQuest II LLC Acquisition
On October 31, 2018, we acquired certain leasehold interests and related assets of ExL Petroleum Management, LLC, ExL Petroleum Operating, Inc. and EnergyQuest II LLC, which included an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments. These acquisitions which we collectively refer to as the ExL acquisition, were effective asRattler Notes Offering, of August 1, 2018, and were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under our revolving credit facility.
Drop-down Transaction
On August 15, 2018, we sold to the Partnership mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas,its 5.625% senior notes due 2025 in the Permian Basin, approximately 80%aggregate principal amount of which are operated by us, for $175.0$500 million, which we refer to as the Drop-down Transaction.
Alliance with Obsidian Resources, L.L.C.
We entered into a participation and development agreement, which we refer to as the DrillCo agreement, dated September 10, 2018, with Obsidian Resources, L.L.C., which we refer to as CEMOF, to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by us. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while our interest will increase to 85%.
Transportation Contracts
In 2018, we entered into 100,000 BOD/d volume commitments with each of the EPIC Pipeline project and the Gray Oak Pipeline project, with 50% of the volumes covered via take or pay contracts and 50% covered via acreage dedications. In connection with such commitments, in February 2019 we closed on our acquisition of 10% equity interests in each of the EPIC and the Gray Oak Pipeline projects. The EPIC and Gray Oak Pipeline projects are each anticipated to be operational in the second half of 2019. These long-haul crude oil pipelines, which will terminate in the refinery-dense, export-focused Texas Gulf Coast market, will allow us to access premium Texas Gulf Coast pricing as opposed to discounted local pricing at Midland, Texas.
New Senior Notes
On January 29, 2018, we issued $300.0 million aggregate principal amount of new 2025 notes as additional notes under our existing indenture, dated as of December 20, 2016, as supplemented, among us, subsidiary guarantors party thereto and Wells Fargo, as trustee, under which we previously issued $500.0 million aggregate principal amount of our existing 5.375% Senior Notes due 2025. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
On September 25, 2018, we issued $750.0 million aggregate principal amount of new 4.750% senior notes due 2024, or the new 2024 notes. The new 2024 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2024 notes. We used a portion of the net proceeds from the issuance of the new 2024 notes to repay a portion of the outstanding borrowings our revolving credit facility and we used the balance for general corporate purposes, including the funding of a portion of the cash consideration for the Ajax acquisition.
Recapitalization, Tax Status Election and Related Transactions by Viper
In March 2018, Viper announced that the Board of Directors of its general partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or the Operating Company, (iii) amended and restated its existing registration rights agreement with us and (iv) entered into an exchange agreement with us, Viper’s general partner, or the General Partner, and the Operating Company. Simultaneously with the effectiveness of these agreements, we delivered and assigned to Viper the 73,150,000 common units we owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or the Recapitalization Agreement. Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and we owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’s July 2018 offering of units, Viper owned approximately 41% of the outstanding units issued by the Operating Company and we owned the remaining approximately 59%. The Operating Company units and Viper’s Class B units owned by us are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Viper Class B unit, together, will be exchangeable for one Viper common unit).
On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to Viper in respect of its general partner interest and (ii) we made a cash capital contribution of $1.0 million to Viper in respect of the Class B units. We, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, we also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and we continue to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding
the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018.
Viper’s July 2018 Equity Offering
In July 2018, Viper completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, we owned approximately 59% of Viper’s total units then outstanding. ViperRattler Notes. Rattler received net proceeds from this offering of approximately $303.1$490 million after deducting underwriting discountsfrom the Rattler Notes Offering and commissions and estimated offering expenses. Viper usedloaned the netgross proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceedsRattler Notes Offering to repay a portion of the $361.5 million then outstandingRattler LLC to pay down borrowings under its revolving credit facility. For additional information regarding the Rattler Notes Offering, see “—Liquidity and Capital Resources—Indebtedness—Rattler’s Notes” below.
Operational Update
We areOur development program is focused entirely within the Permian Basin, where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Springs formations in the Delaware Basin.
As of December 31, 2020, we were operating 21eight drilling rigs now and currently intend to operate between 18eight and 2212 drilling rigs in 20192021 on average across our asset basecurrent acreage position in the Midland and Delaware Basins.
In the Midland Basin, we continuecontinued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations.
In the Delaware Basin, we have now drilled and completed multiplea significant number of wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2019,2021, we expect to focus development on these areas.
In the fourth quarter of 2020, we executed on our business strategy, providing a foundation for continued solid operational performance in 2021. We are starting to see the benefits from our strategy to cut activity and high-grade development focusing on our most productive areas asin terms of capital efficiency and early-time well as our Northern Delaware Basin acreage acquiredperformance. While the impact of the recent winter storms in the Energen transaction.
WePermian Basin on the first quarter 2021 production is expected to be significant (ranging from four to five days of total net production lost), we expect to overcome this adverse impact for the full year 2021. Well costs and cash operating costs remain near all-time lows, providing for increased returns to our stockholders as commodity prices have risen in recent months. In 2021, we intend to continue to focus on low cost operations and best in class execution.execution and currently plan to hold our fourth quarter 2020 production flat while generating free cash flow used to pay dividends and pay down debt. To combat risingpotential fluctuation in service costs, we have lookedworked to lock in pricing for dedicated activity levelsimplement new and more efficient drilling and completions methodologies and will continue to seek opportunities to control additional well cost where possible. Our 20192021 drilling and completion budget accounts for capital costs that we believe will cover potential increases in our service costsexpect to occur during the year.
In 2021, we remain focused on navigating our industry challenges by staying disciplined, improving our industry-leading cost structure, maintaining production and increasing environmental transparency.
Environmental Responsibility Initiatives and Highlights
In February 2021, we announced significant enhancements to our commitment to environmental, social responsibility and governance, or ESG, performance and disclosure, including Scope 1 and methane emission intensity reduction targets. Our goals include the reduction of our Scope 1 greenhouse gas intensity by at least 50% and methane intensity by at least 70%, in each case by 2024 from the 2019 levels. To further underscore our commitment to carbon neutrality, we are also implementing our “Net Zero Now” initiative under which, effective January 1, 2021, every hydrocarbon molecule we produce is anticipated to be produced with zero Scope 1 emissions.To the extent our greenhouse gas and methane intensity targets do not eliminate our carbon footprint, we intend to purchase carbon credits to offset the remaining emissions. We also plan to increase the weighting of ESG metrics in our annual short-term incentive compensation plan to motivate our executives to advance our environmental responsibility goals.
With respect to flaring, we flared 0.9% of our gross natural gas production in the fourth quarter of 2020.For the full year ended 2020, we flared 2.0% of our gross natural gas production, down 64% from 2019.
2021 Capital Budget
We have currently budgeted a 20192021 total capital spend of $2.7$1.4 billion to $3.0$1.6 billion, consisting of $2.3$1.2 billion to $2.55$1.4 billion for horizontal drilling and completions including non-operated activity, $400.0$60 million to $450.0$80 million for midstream and infrastructure investments, excluding equityjoint venture investments, in long-haul pipelines orand $70 million to $90 million for infrastructure and other expenditures, excluding the cost of any leasehold and mineral rightsinterest acquisitions. We expect to drill and complete 290215 to 320235 gross horizontal wells in 2019.2021. Should commodity prices weaken, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to grow oil production within our 2021 budget, pay down indebtedness and return cash to our stockholders.
Operating Results Overview
The following table summarizes our average daily production for the periods presented:
|
| | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
Oil (Bbls)/d | 94,156 | | 58,678 | | 31,590 |
Natural gas (Mcf)/d | 94,983 | | 56,602 | | 29,313 |
Natural gas liquids (Bbls)/d | 20,453 | | 11,112 | | 6,556 |
Total average production per day | 130,439 | | 79,224 | | 43,031 |
Our average daily production for the year ended December 31, 2018 as compared to the year ended December 31, 2017 increased by 51,215 BOE/d, or 65%.
During the year ended December 31, 2018, we drilled 189 gross (168 net) horizontal wells and completed 176 gross (155 net) operated horizontal wells.
Reserves and pricing
Ryder Scott prepared estimates of our proved reserves at December 31, 2018, 2017 and 2016 (which include estimated proved reserves attributable to Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative
transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
|
| | | | | | | | |
| 2018 | | 2017 | | 2016 |
Estimated Net Proved Reserves: | | | | | |
Oil (MBbls) | 626,936 |
| | 233,181 |
| | 139,174 |
|
Natural gas (MMcf) | 1,048,649 |
| | 285,369 |
| | 174,896 |
|
Natural gas liquids (MBbls) | 190,291 |
| | 54,609 |
| | 37,134 |
|
Total (MBOE) | 992,001 |
| | 335,352 |
| | 205,458 |
|
|
| | | | | | | | | | | |
| Unweighted Arithmetic Average |
| First-Day-of-the-Month Prices |
| 2018 | | 2017 | | 2016 |
Oil (per Bbl) | $ | 59.63 |
| | $ | 48.03 |
| | $ | 39.94 |
|
Natural gas (per Mcf) | $ | 1.47 |
| | $ | 2.06 |
| | $ | 1.36 |
|
Natural gas liquids (per Bbl) | $ | 24.43 |
| | $ | 20.79 |
| | $ | 12.91 |
|
Sources of our revenue
Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.
The following table presents the sources of our revenues for the years presented:
|
| | | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
Revenues: | | | | | |
Oil sales | 88 | % | | 88 | % | | 89 | % |
Natural gas sales | 3 | % | | 4 | % | | 4 | % |
Natural gas liquid sales | 9 | % | | 8 | % | | 7 | % |
| 100 | % | | 100 | % | | 100 | % |
Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2018, WTI posted prices ranged from $44.48 to $77.41 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On December 28, 2018, the WTI posted price for crude oil was $45.15 per Bbl and the Henry Hub spot market price of natural gas was $3.25 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.
Principal components of our cost structure
Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.
Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.
General and administrative expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.
Midstream services expense. These are costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
Impairment of oil and natural gas properties. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.
Other income (expense)
Interest income (expense). We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. This amount reflects interest paid to our lender plus the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees net of interest received on our cash and cash equivalents.
Gain (loss) on derivative instruments, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of the change in the fair value of open non-hedge derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivative instruments.
Deferred tax assets (liabilities). We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
Results of Operations
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
Revenues (in millions): | | | | | |
Oil sales | $ | 2,410 | | | $ | 3,554 | | | |
Natural gas sales | 107 | | | 66 | | | |
Natural gas liquid sales | 239 | | | 267 | | | |
Total oil, natural gas and natural gas liquid revenues | $ | 2,756 | | | $ | 3,887 | | | |
| | | | | |
Production Data (in thousands): | | | | | |
Oil (MBbls) | 66,182 | | | 68,518 | | | |
Natural gas (MMcf) | 130,549 | | | 97,613 | | | |
Natural gas liquids (MBbls) | 21,981 | | | 18,498 | | | |
Combined volumes (MBOE) | 109,921 | | | 103,285 | | | |
| | | | | |
Daily oil volumes (BO/d) | 180,825 | | | 187,721 | | | |
Daily combined volumes (BOE/d) | 300,331 | | | 282,972 | | | |
| | | | | |
Average Prices: | | | | | |
Oil ($ per Bbl) | $ | 36.41 | | | $ | 51.87 | | | |
Natural gas ($ per Mcf) | $ | 0.82 | | | $ | 0.68 | | | |
Natural gas liquids ($ per Bbl) | $ | 10.87 | | | $ | 14.42 | | | |
Combined ($ per BOE) | $ | 25.07 | | | $ | 37.63 | | | |
| | | | | |
Oil, hedged ($ per Bbl)(1) | $ | 40.34 | | | $ | 51.96 | | | |
Natural gas, hedged ($ per MMbtu)(1) | $ | 0.67 | | | $ | 0.86 | | | |
Natural gas liquids, hedged ($ per Bbl)(1) | $ | 10.83 | | | $ | 15.20 | | | |
Average price, hedged ($ per BOE)(1) | $ | 27.26 | | | $ | 38.00 | | | |
(1)Hedged prices reflect the effect of operationsour commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for 2018 include thosematured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of Energencommodity derivative contracts.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural gas and its subsidiaries acquired by us in the mergernatural gas liquids production. The following tables set forth our production data for the period November 29, 2018, the closing date of the merger, throughyears ended December 31, 2018.2020 and 2019:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
Oil (MBbls) | 60 | % | | 66 | % | | |
Natural gas (MMcf) | 20 | % | | 16 | % | | |
Natural gas liquids (MBbls) | 20 | % | | 18 | % | | |
| 100 | % | | 100 | % | | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
| (in thousands) |
Revenues: | | | | | |
Oil, natural gas and natural gas liquids | $ | 2,129,780 |
| | $ | 1,186,275 |
| | $ | 527,107 |
|
Lease bonus | 2,920 |
| | 11,764 |
| | — |
|
Midstream services | 34,254 |
| | 7,072 |
| | — |
|
Other operating income | 9,302 |
| | — |
| | — |
|
Total revenues | 2,176,256 |
| | 1,205,111 |
| | 527,107 |
|
Operating expenses: | | | | | |
Lease operating expenses | 204,975 |
| | 126,524 |
| | 82,428 |
|
Production and ad valorem taxes | 132,661 |
| | 73,505 |
| | 34,456 |
|
Gathering and transportation | 26,113 |
| | 12,834 |
| | 11,606 |
|
Midstream services | 71,878 |
| | 10,409 |
| | — |
|
Depreciation, depletion and amortization | 623,039 |
| | 326,759 |
| | 178,015 |
|
Impairment of oil and natural gas properties | — |
| | — |
| | 245,536 |
|
General and administrative expenses | 64,554 |
| | 48,669 |
| | 42,619 |
|
Asset retirement obligation accretion | 2,132 |
| | 1,391 |
| | 1,064 |
|
Merger & integration expense | 36,831 |
| | — |
| | — |
|
Other operating expense | 3,285 |
| | — |
| | — |
|
Total expenses | 1,165,468 |
| | 600,091 |
| | 595,724 |
|
Income (loss) from operations | 1,010,788 |
| | 605,020 |
| | (68,617 | ) |
Interest expense, net | (87,276 | ) | | (40,554 | ) | | (40,684 | ) |
Other income, net | 88,996 |
| | 10,235 |
| | 3,064 |
|
Gain (loss) on derivative instruments, net | 101,299 |
| | (77,512 | ) | | (25,345 | ) |
Loss on revaluation of investment | (550 | ) | | — |
| | — |
|
Loss on extinguishment of debt | — |
| | — |
| | (33,134 | ) |
Total other income (expense), net | 102,469 |
| | (107,831 | ) | | (96,099 | ) |
Income (loss) before income taxes | 1,113,257 |
| | 497,189 |
| | (164,716 | ) |
Provision for (benefit from) income taxes | 168,362 |
| | (19,568 | ) | | 192 |
|
Net income (loss) | 944,895 |
| | 516,757 |
| | (164,908 | ) |
Net income attributable to non-controlling interest | 99,223 |
| | 34,496 |
| | 126 |
|
Net income (loss) attributable to Diamondback Energy, Inc. | $ | 845,672 |
| | $ | 482,261 |
| | $ | (165,034 | ) |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
Production Data: | | | | | |
Oil (MBbls) | 34,367 |
| | 21,418 |
| | 11,562 |
|
Natural gas (MMcf) | 34,669 |
| | 20,660 |
| | 10,728 |
|
Natural gas liquids (MBbls) | 7,465 |
| | 4,056 |
| | 2,399 |
|
Combined volumes (MBOE) | 47,610 |
| | 28,917 |
| | 15,749 |
|
Daily combined volumes (BOE/d) | 130,439 |
| | 79,224 |
| | 43,031 |
|
| | | | | |
Average Prices: | | | | | |
Oil (per Bbl) | $ | 54.66 |
| | $ | 48.75 |
| | $ | 40.70 |
|
Natural gas (per Mcf) | 1.76 |
| | 2.53 |
| | 2.10 |
|
Natural gas liquids (per Bbl) | 25.47 |
| | 22.20 |
| | 14.20 |
|
Combined (per BOE) | 44.73 |
| | 41.02 |
| | 33.47 |
|
Oil, hedged ($ per Bbl)(1) | 51.20 |
| | 48.94 |
| | 40.80 |
|
Natural gas, hedged ($ per MMbtu)(1) | 1.72 |
| | 2.65 |
| | 2.06 |
|
Natural gas liquids, hedged ($ per Bbl)(1) | 25.46 |
| | — |
| | — |
|
Average price, hedged ($ per BOE)(1) | 42.20 |
| | 41.26 |
| | 33.54 |
|
| | | | | |
Average Costs per BOE: | | | | | |
Lease operating expense | $ | 4.31 |
| | $ | 4.38 |
| | $ | 5.23 |
|
Production and ad valorem taxes | 2.79 |
| | 2.54 |
| | 2.19 |
|
Gathering and transportation expense | 0.55 |
| | 0.44 |
| | 0.74 |
|
General and administrative - cash component | 0.79 |
| | 0.80 |
| | 1.03 |
|
Total operating expense - cash | $ | 8.44 |
| | $ | 8.16 |
| | $ | 9.19 |
|
| | | | | |
General and administrative - non-cash component | $ | 0.57 |
| | $ | 0.88 |
| | $ | 1.68 |
|
Depreciation, depletion and amortization | 13.09 |
| | 11.30 |
| | 11.30 |
|
Interest expense, net | 1.83 |
| | 1.40 |
| | 2.58 |
|
Merger and integration expense | 0.77 |
| | — |
| | — |
|
Total expenses | $ | 16.26 |
| | $ | 13.58 |
| | $ | 15.56 |
|
| | | | | |
Average realized oil price ($/Bbl) | $ | 54.66 |
| | $ | 48.75 |
| | $ | 40.70 |
|
Average NYMEX ($/Bbl) | $ | 65.23 |
| | $ | 50.80 |
| | $ | 43.29 |
|
Differential to NYMEX | $ | (10.57 | ) | | $ | (2.05 | ) | | $ | (2.59 | ) |
Average realized oil price to NYMEX | 84 | % | | 96 | % | | 94 | % |
| | | | | |
Average realized natural gas price ($/Mcf) | $ | 1.76 |
| | $ | 2.53 |
| | $ | 2.10 |
|
Average NYMEX ($/Mcf) | $ | 3.17 |
| | $ | 2.99 |
| | $ | 2.52 |
|
Differential to NYMEX | $ | (1.41 | ) | | $ | (0.46 | ) | | $ | (0.42 | ) |
Average realized natural gas price to NYMEX | 56 | % | | 85 | % | | 83 | % |
| | | | | |
Average realized natural gas liquids price ($/Bbl) | $ | 25.47 |
| | $ | 22.20 |
| | $ | 14.20 |
|
Average NYMEX oil price ($/Bbl) | $ | 65.23 |
| | $ | 50.80 |
| | $ | 43.29 |
|
Average realized natural gas liquids price to NYMEX oil price | 39 | % | | 44 | % | | 33 | % |
| |
(1) | Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
Comparison of the Years Ended December 31, 20182020 and 20172019
Oil, Natural Gas Liquids and Natural Gas Liquids Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $943.5 million, or 80%, to $2.2 billion for the year ended December 31, 2018 from $1.2 billion for the year ended December 31, 2017. Our revenues are a function of oil, natural gas liquids and natural gas liquids production volumes sold and average sales prices received for those volumes.
The net dollar effect of the change in prices are shown below:
| | | | | | | | | | | | | | | | | |
| Change in prices | | Production volumes(1) | | Total net dollar effect of change |
| | | | | (in millions) |
Effect of changes in price: | | | | | |
Oil | $ | (15.46) | | | 66,182 | | | $ | (1,023) | |
Natural gas | $ | 0.14 | | | 130,549 | | | $ | 18 | |
Natural gas liquids | $ | (3.55) | | | 21,981 | | | $ | (77) | |
Total revenues due to change in price | | | | | $ | (1,082) | |
| | | | | |
| Change in production volumes(1) | | Prior period average prices | | Total net dollar effect of change |
| | | | | (in millions) |
Effect of changes in production volumes: | | | | | |
Oil | (2,336) | | | $ | 51.87 | | | $ | (121) | |
Natural gas | 32,936 | | | $ | 0.68 | | | $ | 22 | |
Natural gas liquids | 3,483 | | | $ | 14.42 | | | $ | 50 | |
Total change in revenues | | | | | $ | (49) | |
| | | | | $ | (1,131) | |
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.
Our oil, natural gas and natural gas liquids revenues decreased by approximately $1.1 billion, or 29%, to $2.8 billion for the year ended December 31, 2020 from $3.9 billion for the year ended December 31, 2019, largely attributable to lower oil average sales prices resulting from the impact of the COVID-19 pandemic and other volatility in global commodity prices as discussed in “—COVID-19 and collapse in Commodity Prices” above.
Average daily production sold increased by 51,21517,359 BOE/d to 130,439300,331 BOE/d during the year ended December 31, 20182020 from 79,224282,972 BOE/d during the year ended December 31, 2017. The total2019, primarily due to an increase in revenue of approximately $943.5 million is attributable to higher oil, natural gas liquids and natural gas production, which was partially offset by temporarily curtailing a portion of our oil production volumes during 2020 in response to the sudden drop in demand and higher average sales prices for oil stemming from the yearCOVID-19 pandemic.
Midstream Services Revenue. The following table shows midstream services revenue for the years ended December 31, 2018 as compared to the year ended December 31, 2017. The increases in production volumes were due to a combination of increased drilling activity2020 and growth through acquisitions. Our production increased by 12,949 MBbls of oil, 14,009 MMcf of natural gas and 3,409 MBbls of natural gas liquids for the year ended December 31, 2018 as compared to the year ended December 31, 2017.2019:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
| (in millions) |
Midstream services | $ | 50 | | | $ | 64 | | | |
The net dollar effect of the increases in prices of approximately $201.2 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $742.3 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
|
| | | | | | | | | | | |
| Change in prices | | Production volumes(1) | | Total net dollar effect of change |
| | | | | (in thousands) |
Effect of changes in price: | | | | | |
Oil | $ | 5.92 |
| | 34,367 |
| | $ | 203,383 |
|
Natural gas | $ | (0.77 | ) | | 34,669 |
| | $ | (26,567 | ) |
Natural gas liquids | $ | 3.26 |
| | 7,465 |
| | $ | 24,362 |
|
Total revenues due to change in price | | | | | $ | 201,178 |
|
| | | | | |
| Change in production volumes(1) | | Prior period average prices | | Total net dollar effect of change |
| | | | | (in thousands) |
Effect of changes in production volumes: | | | | | |
Oil | 12,949 |
| | $ | 48.75 |
| | $ | 631,225 |
|
Natural gas | 14,009 |
| | $ | 2.53 |
| | $ | 35,403 |
|
Natural gas liquids | 3,409 |
| | $ | 22.20 |
| | $ | 75,699 |
|
Total change in revenues | | | | | $ | 742,327 |
|
| | | | | $ | 943,505 |
|
| |
(1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. |
Lease Bonus Revenue. Lease bonus revenue was $2.9 million for the year ended December 31, 2018, $0.9 million of which was attributable to lease bonus payments to extend the term of two leases, reflecting an average bonus of $5,939 per acre and the remaining $2.0 million was attributable to lease bonus payments on five new leases, reflecting an average bonus of $11,649 per acre. Lease bonus revenue was $11.8 million for the year ended December 31, 2017, $2.8 million of which was attributable to lease bonus payments to extend the term of seven leases, reflecting an average bonus of $3,442 per acre and the remaining $9.1 million was attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre.
Midstream Services Revenue. Midstream services revenue was $34.3 million for the year ended December 31, 2018, an increase of $27.2 million as compared to $7.1 million for the year ended December 31, 2017. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.
Lease Operating Expenses. Lease operating expenses were $205.0 million ($4.31 per BOE) for the year ended December 31, 2018, an increase of $78.5 million from $126.5 million ($4.38 per BOE) for the year ended December 31, 2017. The increase in lease operating expense was a result of an increase in our producing well count. The decrease in lease operating expense per BOE was a result of lease operating expenses increasing at a lower percentage than the increase in production volumes.
Production and Ad Valorem Taxes. Production and ad valorem taxes were $132.7Midstream services revenue decreased by $14 million for the year ended December 31, 2018, an increase of $59.2 million, or 80%, from $73.5 million for the year ended December 31, 2017. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. During the year ended December 31, 2018, production and ad valorem taxes per BOE increased by $0.252020 as compared to the year ended December 31, 2017,2019 primarily due to increased commodity pricesa reduction in sourced water volumes due to the lower level of drilling and production volumes.completion activity in 2020.
Midstream Services Expense. Midstream services expense was $71.9 millionLease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
(in millions, except per BOE amounts) | Amount | Per BOE | | Amount | Per BOE | | | |
Lease operating expenses | $ | 425 | | $ | 3.87 | | | $ | 490 | | $ | 4.74 | | | | |
| | | | | | | | |
| | | | | | | | |
Lease operating expenses for the year ended December 31, 2018, an increase of $61.5 million2020 as compared to $10.4the year ended December 31, 2019 decreased by $65 million, or $0.87 per BOE. Lease operating expenses decreased due to a reduction in work over and well maintenance activity through overall efficiencies gained, as well as improvements in infrastructure which reduced power generation costs and trucking fees. In addition to these efficiencies we have seen a reduction in service pricing in 2020, driven by the reduction in current industry activity levels. We expect service pricing may increase in future periods, particularly if current industry activity levels increase.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
(in millions, except per BOE amounts) | Amount | Per BOE | | Amount | Per BOE | | | |
Production taxes | $ | 135 | | $ | 1.23 | | | $ | 184 | | $ | 1.78 | | | | |
Ad valorem taxes | 60 | | 0.54 | | | 64 | | 0.62 | | | | |
Total production and ad valorem expense | $ | 195 | | $ | 1.77 | | | $ | 248 | | $ | 2.40 | | | | |
| | | | | | | | |
Production taxes as a % of oil, natural gas, and natural gas liquids revenue | 4.9 | % | | | 4.7 | % | | | | |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes for the year ended December 31, 2017. The increase was primarily2020 as compared to the year ended December 31, 2019 decreased by $49 million, or $0.55 per BOE, due to additional build outcurrent year commodity prices. Production taxes as a percentage of systemsproduction revenues remained consistent for the year ended December 31, 2020 compared to the year ended December 31, 2019.
Gathering and increased throughput relatedTransportation Expense. The following table shows gathering and transportation expense for the year ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | | |
| 2020 | | 2019 | | | |
(in millions, except per BOE amounts) | Amount | Per BOE | | Amount | Per BOE | | | |
| | | | |
Gathering and transportation expense | $ | 140 | | $ | 1.27 | | | $ | 88 | | $ | 0.86 | | | | |
For the year ended December 31, 2020, the per BOE increases for gathering and transportation expenses are primarily attributable to increasedrecording minimum volume commitment fees in 2020, as well as an increase in fees for our gas production and an overall change in our product mix, with gas and natural gas liquids production becoming a greater percentage of overall production.
Midstream Services Expense. The following table shows midstream services expense for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
| (in millions) |
Midstream services expense | $ | 105 | | | $ | 91 | | | |
Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization Midstream services expense increased $296.3 million, or 91%, from $326.8 million for the year ended December 31, 20172020 as compared to $623.0 million for the year ended December 31, 2018.2019 increased by $14 million primarily due to increased volume and build out of the Rattler systems.
Depreciation, Depletion and Amortization.The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | |
| Year Ended December 31, |
(in millions, except BOE amounts) | 2020 | | 2019 | | |
| | | | | |
Depletion of proved oil and natural gas properties | $ | 1,242 | | | $ | 1,398 | | | |
Depreciation of midstream assets | 44 | | | 33 | | | |
Depreciation of other property and equipment | 18 | | | 16 | | | |
Depreciation, depletion and amortization expense | $ | 1,304 | | | $ | 1,447 | | | |
Oil and natural gas properties depletion per BOE | $ | 11.30 | | | $ | 13.54 | | | |
|
| | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 |
| (in thousands, except BOE amounts) |
Depletion of proved oil and natural gas properties | $ | 594,750 |
| | $ | 321,870 |
|
Depreciation of midstream assets | 18,803 |
| | 3,451 |
|
Depreciation of other property and equipment | 9,486 |
| | 1,438 |
|
Depreciation, depletion and amortization expense | $ | 623,039 |
| | $ | 326,759 |
|
Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 12.62 |
| | $ | 11.11 |
|
The increasedecrease in depletion of proved oil and natural gas properties of $272.9$156 million for the year ended December 31, 20182020 as compared to the year ended December 31, 20172019 resulted primarily from higher production levelsa reduction in the average depletion rate for our oil and an increasenatural gas properties in 2020, which stemmed from a decrease in the net book value of our properties due to the full cost ceiling impairments recorded in the first three quarters of 2020 as well as lower production levels in 2020 as compared to 2019.
Impairment of Oil and Natural Gas Properties. As a result of the decline in commodity prices during 2020 and 2019, we recorded non-cash ceiling test impairments for the years ended December 31, 2020 and 2019 of $6.0 billion and $790 million, respectively, which is included in accumulated depletion, depreciation, amortization and impairment on newour consolidated balance sheet. The impairment charges affected our results of operations but did not reduce cash flow. In addition to commodity prices, our production rates, levels of proved reserves, added.future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will continue to have material write-downs in subsequent quarters.
General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
(in millions, except per BOE amounts) | Amount | Per BOE | | Amount | Per BOE | | | |
General and administrative expenses | $ | 51 | | $ | 0.46 | | | $ | 56 | | $ | 0.54 | | | | |
Non-cash stock-based compensation | 37 | | 0.34 | | | 48 | | 0.46 | | | | |
Total general and administrative expenses | $ | 88 | | $ | 0.80 | | | $ | 104 | | $ | 1.00 | | | | |
General and administrative expenses for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $16 million primarily due to a decrease in non-cash stock-based compensation.
Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2020 and 2019:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
| (in millions) |
Interest expense, net | $ | 197 | | | $ | 172 | | | |
Net interest expense increased $15.9 million from $48.7by $25 million for the year ended December 31, 20172020 as compared to $64.6 million for the year ended December 31, 2018. The2019. This increase was primarily due to an increase in employee count, including as a resultborrowings resulting from the issuance of our recent merger with Energen.the May 2020 Notes and the Rattler Notes. See Note 11—Debt for further details regarding outstanding borrowings and interest expense.
Net Interest Expense. Net interest expense for
Derivatives. The following table shows the year ended December 31, 2018 was $87.3 million as compared to $40.6 million for the year ended December 31, 2017, an increase of $46.7 million. This increase was due primarily to a higher interest rate and increased average borrowings during the year ended December 31, 2018 as compared to the year ended December 31, 2017.
Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gainnet gain (loss) on derivative instruments net.” Forand the year ended December 31, 2018, we had anet cash lossreceived (paid) on settlementsettlements of derivative instruments of $120.4 million as compared to a cash gain on settlement of derivative instruments of $6.7 million for the year ended December 31, 2017. For the year ended December 31, 2018, we had a positive change in the fair value of open derivative instruments of $221.7 million as compared to a negative change of $84.2 million for the year ended December 31, 2017. Our net gain on derivative instruments for the yearyears ended December 31, 2018 was due2020 and 2019:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 |
| (in millions) |
Gain (loss) on derivative instruments, net | $ | (81) | | | $ | (108) | |
Net cash received (paid) on settlements | $ | 250 | | | $ | 80 | |
Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the assumptionextent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.
Net cash received (paid) on settlements of Energen’s hedgesderivative instruments for the years ended December 31, 2020 and lower2019 include cash received on contracts terminated prior to their contractual maturity of $17 million related to commodity prices.contracts and $43 million related to interest rate swap contracts, respectively.
Provision for (Benefit from) Income Taxes. We recorded anThe following table shows the provision for (benefit from) income tax provision of $168.4 milliontaxes for the yearyears ended December 31, 2018 as compared to an income tax benefit of $19.6 million for the year ended December 31, 2017. Our effective tax rate was 15.1% for the year ended December 31, 2018 as compared to (3.9)% for the year ended December 31, 2017. 2020 and 2019:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
| (in millions) |
Provision for (benefit from) income taxes | $ | (1,104) | | | $ | 47 | | | |
The change in our income tax provision was primarily due to the pre-tax loss for the year ended December 31, 20182020 as compared to the year ended December 31, 2017 is primarily due to the to the increase in pre-tax book income for the year ended December 31, 2018, partially offset by2019, and the tax effect reflected in the consolidated tax provisionimpact of the tax status change for Viper in the year ended December 31, 2018, therecording a valuation allowance on Viper’s deferred tax benefits resulting from the change in the valuation allowance for the year ended December 31, 2017, and the reduction of the federal statutory tax rate enactedassets during the year ended December 31, 2017.2020.
Comparison of the Years Ended December 31, 2017 and 2016
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $659.2 million, or 125%, to $1.2 billion for the year ended December 31, 2017 from $527.1 million for the year ended December 31, 2016. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 36,193 BOE/d to 79,224 BOE/d during the year ended December 31, 2017 from 43,031 BOE/d during the year ended December 31, 2016. The total increase in revenue of approximately $659.2 million is attributable to higher oil, natural gas liquids and natural gas production volumes and higher average sales prices for the year ended December 31, 2017 as compared to the year ended December 31, 2016. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 9,856 MBbls of oil, 1,656 MBbls of natural gas liquids and 9,931 MMcf of natural gas for the year ended December 31, 2017 as compared to the year ended December 31, 2016.
The net dollar effect of the increases in prices of approximately $213.7 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $445.4 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
|
| | | | | | | | | | | |
| Change in prices | | Production volumes(1) | | Total net dollar effect of change |
| | | | | (in thousands) |
Effect of changes in price: | | | | | |
Oil | $ | 8.05 |
| | 21,418 |
| | $ | 172,403 |
|
Natural gas | $ | 0.43 |
| | 20,660 |
| | $ | 8,884 |
|
Natural gas liquids | $ | 8.00 |
| | 4,056 |
| | $ | 32,446 |
|
Total revenues due to change in price | | | | | $ | 213,733 |
|
| | | | | |
| Change in production volumes(1) | | Prior period average prices | | Total net dollar effect of change |
| | | | | (in thousands) |
Effect of changes in production volumes: | | | | | |
Oil | 9,856 |
| | $ | 40.70 |
| | $ | 401,080 |
|
Natural gas | 9,931 |
| | $ | 2.10 |
| | $ | 20,834 |
|
Natural gas liquids | 1,656 |
| | $ | 14.20 |
| | $ | 23,521 |
|
Total revenues due to change in production volumes | | | | | $ | 445,435 |
|
Total change in revenues | | | | | $ | 659,168 |
|
| |
(1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. |
Lease Bonus Revenue. Lease bonus revenue was $11.8 million for the year ended December 31, 2017, $2.8 million of which was attributable to lease bonus payments to extend the term of seven leases, reflecting an average bonus of $3,442 per acre and the remaining $9.1 million was attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre. We had no lease bonus revenue for the year ended December 31, 2016.
Midstream Services Revenue. Midstream services revenue was $7.1 million for the year ended December 31, 2017. We began generating midstream services revenue during the first quarter of 2017 and, prior to that period, had no midstream services revenue. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.
Lease Operating Expenses. Lease operating expenses were $126.5 million ($4.38 per BOE) for the year ended December 31, 2017, an increase of $44.1 million from $82.4 million ($5.23 per BOE) for the year ended December 31, 2016. The increase in lease operating expense was due to an increase of 234 producing wells compared to 2016. This increase was offset by higher production volumes which resulted in a decrease in lease operating expense per BOE.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased to $73.5 million for the year ended December 31, 2017 from $34.5 million for the year ended December 31, 2016. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. The increase in production and ad valorem taxes during the year ended December 31, 2017 as compared to 2016 was primarily due to an increase in our production taxes as a result of increased commodity prices and volumes.
Midstream Services Expense. Midstream services expense was $10.4 million for the year ended December 31, 2017. Prior to the first quarter of 2017, we had no midstream services expense. Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $148.7 million, or 84%, from $178.0 million for the year ended December 31, 2016 to $326.8 million for the year ended December 31, 2017.
The following table provides components of our depreciation, depletion and amortization expense for the periods presented:
|
| | | | | | | |
| Year Ended December 31, |
| 2017 | | 2016 |
| (in thousands, except BOE amounts) |
Depletion of proved oil and natural gas properties | $ | 321,870 |
| | $ | 176,369 |
|
Depreciation of midstream assets | 3,451 |
| | 252 |
|
Depreciation of other property and equipment | 1,438 |
| | 1,394 |
|
Depreciation, depletion and amortization expense | $ | 326,759 |
| | $ | 178,015 |
|
Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 11.11 |
| | $ | 11.23 |
|
The increase in depletion of proved oil and natural gas properties of $145.5 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016 resulted primarily from higher production levels and an increase in net book value on new reserves added.
Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2016, we recorded an impairment of oil and gas properties of $245.5 million as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil and natural gas reserves. We did not record an impairment of oil and natural gas properties during the year ended December 31, 2017.
General and Administrative Expenses. General and administrative expenses increased $6.1 million from $42.6 million for the year ended December 31, 2016 to $48.7 million for the year ended December 31, 2017. The increase was due to an increase in salaries and benefits expense as a result of an increase in workforce.
Net Interest Expense. Net interest expense for the year ended December 31, 2017 was $40.6 million as compared to $40.7 million for the year ended December 31, 2016, a decrease of $0.1 million. This decrease was due primarily to the issuance in October 2016 of new senior notes due 2024 with a lower interest rate than the senior notes which we redeemed in the fourth quarter of 2016 partially offset by the interest on the additional senior notes due in 2025 that we issued in December 2016.
Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2017 and 2016, we had a cash gain on settlement of derivative instruments of $6.7 million and $1.2 million, respectively. For the year ended December 31, 2017 and 2016, we had a negative change in the fair value of open derivative instruments of $84.2 million and $26.5 million, respectively.
Provision for (Benefit from) Income Taxes. We recorded an income tax benefit of $19.6 million for the year ended December 31, 2017 as compared to an income tax provision of $0.2 million for the year ended December 31, 2016. Our effective tax rate was (3.9)% for the year ended December 31, 2017 as compared to (0.1)% for the year ended December 31, 2016. The change in our income tax provision for the year ended December 31, 2017 as compared to the year ended December 31, 2016 is primarily due to the reduction in our valuation allowance against deferred tax assets, as well as the favorable impact of the reduction in the federal statutory tax rate enacted in December 2017. While we generated positive pre-tax income from continuing operations in 2017, our 2017 effective tax rate was negative due to the income tax benefit generated by these items.
Liquidity and Capital Resources
Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and proceeds from the issuance of the senior notes and cash flows from operations.notes. Our primary useuses of capital hashave been for the acquisition, development and exploration of oil and natural gas properties.
As we pursue reservesour business and production growth,financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.
Liquidity and Cash Flow
Our cash flows for the years ended December 31, 2018, 20172020 and 20162019 are presented below:
| | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | |
| (in millions) |
Net cash provided by (used in) operating activities | $ | 2,118 | | | $ | 2,739 | | | |
Net cash provided by (used in) investing activities | (2,101) | | | (3,888) | | | |
Net cash provided by (used in) financing activities | (37) | | | 1,062 | | | |
Net change in cash | $ | (20) | | | $ | (87) | | | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
| (in thousands) |
Net cash provided by operating activities | $ | 1,564,505 |
| | $ | 888,625 |
| | $ | 332,080 |
|
Net cash used in investing activities | (3,503,043 | ) | | (3,132,282 | ) | | (1,310,242 | ) |
Net cash provided by financing activities | 2,040,608 |
| | 689,529 |
| | 2,624,621 |
|
Net change in cash | $ | 102,070 |
| | $ | (1,554,128 | ) | | $ | 1,646,459 |
|
Operating Activities
Net cash provided by operating activities was $1.6 billion for the year ended December 31, 2018 as compared to $888.6 million for the year ended December 31, 2017. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in average prices and production growth during the year ended December 31, 2018.
Net cash provided by operating activities was $888.6 million for the year ended December 31, 2017 as compared to $332.1 million for the year ended December 31, 2016. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in average prices and production growth during the year ended December 31, 2017.
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “–Sources of our revenue” and Item 1A. “Risk Factors” above.
our derivative contracts.
Investing Activities
The purchase and development of oil and natural gas properties and related assets, and contributions to our equity method investments accounted for the majority of our $2.1 billion and $3.9 billion in cash outlays for investing activities. We used cash for investing activities of $3.5 billion, $3.1 billion and $1.3 billion during the years ended December 31, 2018, 20172020 and 2016,2019, respectively.
Contributions to equity method investments decreased to $102 million for the year ended December 31, 2020 as compared to $485 million for the year ended December 31, 2019 as construction of both the EPIC Pipeline and Gray Oak Pipeline, which required substantial capital in 2019, was completed during April 2020. As of December 31, 2020, Rattler’s anticipated future capital commitments for its equity method investments total $72 million in the aggregate. For additional information regarding our equity method investments, see Note 10—Equity Method Investments included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Capital Expenditure Activities
Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 |
| (in millions) |
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2) | $ | 1,611 | | | $ | 2,557 | |
Infrastructure additions to oil and natural gas properties | 108 | | | 120 | |
Additions to midstream assets | 140 | | | 244 | |
Total | $ | 1,859 | | | $ | 2,921 | |
(1) During the year ended December 31, 2020, in conjunction with our development program, we drilled 208 gross (195 net) operated horizontal wells, of which 75 gross (70 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 171 gross (159 net) operated horizontal wells to production, of which 78 gross (74 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.
(2) During the year ended December 31, 2019, in conjunction with our development program, we drilled 330 gross (296 net) operated horizontal wells, of which 159 gross (142 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 317 gross (289 net) operated horizontal wells to production, of which 139 gross (126 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.
Financing Activities
During the year ended December 31, 2018, we spent (a) $1.5 billion2020, the amount used in financing activities was primarily attributable to $348 million of repayments, net of borrowings, on capital expendituresour credit facilities, $239 million in conjunction withaggregate repayments on the Energen Notes and Viper Notes, $236 million in dividends paid to stockholders, $98 million of share repurchases as part of our drillingstock repurchase program, and $93 million in which we drilled 189 gross (168 net) horizontal wellsdistributions to non-controlling interest. These cash outlays were partially offset by net proceeds of $997 million from the issuance of the May 2020 Notes and completed 176 gross (155 net) operated horizontal wells, (b) $204.2 million on additions to midstream assets, (c) $440.3 million for the acquisition of mineral interests, (d) $1.4 billion on leasehold acquisitions, (e) $6.8 million for the purchase of other property and equipment and (f) $110.7 million on investment in real estate.Rattler Notes during 2020.
During the year ended December 31, 2017, we spent (a) $792.6 million on capital expenditures in conjunction with our drilling program, in which we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated wells, (b) $68.1 million on additions to midstream assets, (c) $407.5 million for the acquisition of mineral interests, (d) $1,960.6 million on leasehold acquisitions, (e) $50.3 million for the acquisition of midstream assets and (f) $22.8 million for the purchase of other property and equipment.
During the year ended December 31, 2016, we spent (a) $364.3 million on capital expenditures in conjunction with our drilling program, in which we drilled 73 gross (61 net) horizontal wells and two gross (one net) vertical wells and participated in the drilling of 19 gross (five net) non-operated wells, (b) $611.3 million on leasehold acquisitions, (c) $205.7 million on royalty interest acquisitions, (d) $9.9 million for the purchase of other property and equipment and (e) $121.4 million was placed in escrow as a deposit under the purchase agreement for oil and natural gas assets located in Pecos and Reeves counties in Texas.
Our investing activities for the years ended December 31, 2018, 2017 and 2016 are summarized in the following table:
|
| | | | | | | | | | | |
| Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
| (in thousands) |
Drilling, completion and infrastructure | $ | (1,460,509 | ) | | $ | (792,599 | ) | | $ | (363,087 | ) |
Additions to midstream assets | (204,222 | ) | | (68,139 | ) | | (1,188 | ) |
Acquisition of leasehold interests | (1,370,951 | ) | | (1,960,591 | ) | | (611,280 | ) |
Acquisition of mineral interests | (440,303 | ) | | (407,450 | ) | | (205,721 | ) |
Acquisition of midstream assets | — |
| | (50,279 | ) | | — |
|
Purchase of other property, equipment and land | (6,840 | ) | | (22,779 | ) | | (9,891 | ) |
Investment in real estate | (110,685 | ) | | — |
| | — |
|
Proceeds from sale of assets | 80,098 |
| | 65,656 |
| | 4,661 |
|
Funds held in escrow | 10,989 |
| | 104,087 |
| | (121,391 | ) |
Equity investments | (612 | ) | | (188 | ) | | (2,345 | ) |
Purchase of other investments | (8 | ) | | — |
| | — |
|
Net cash used in investing activities | $ | (3,503,043 | ) | | $ | (3,132,282 | ) | | $ | (1,310,242 | ) |
Financing Activities
Net cash provided by financing activities for the years ended December 31, 2018, 2017 and 2016 was $2.0 billion, $689.5 million and $2.6 billion, respectively.
During the year ended December 31, 2018,2019, the amount provided by financing activities was primarily attributable to the issuance of $1.1 billion of new senior notes, $1.4 billion of borrowings, net of repayments under our credit facility, $559.0$341 million of repayments under Energen’s credit facility and an aggregate of $305.8 million ofin net proceeds from Viper’s public offerings,offering completed on March 1, 2019, $720 million in net proceeds from the Rattler Offering, $39 million in proceeds from joint ventures and $2.2 billion in proceeds from the December 2019 Notes, net of repayments, partially offset by $98.3$1.4 billion of repayments, net of borrowings, under our credit facility, $44 million of premium on debt extinguishment, $122 million of distributions to our non-controlling interest, $13 million of share
repurchases for tax withholdings, $593 million of share repurchases as part of our stock repurchase program and $37.3$112 million of dividends to stockholders.
During the year ended December 31, 2017, the amount provided by financing activities was primarily attributable to proceeds from Viper’s January and July 2017 equity offerings of $370.3 million as well as borrowings net of repayments of $370.0 million, partially offset by distributions to non-controlling interests of $41.4 million.Indebtedness
During the year ended December 31, 2016, the amount provided by financing activities was primarily attributable to the aggregate proceeds of $2.1 billion from our January, July and December 2016 equity offerings partially offset by repayments of net borrowings of $75.0 million under our credit facility.
2024 Senior Notes
On October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the existing 2024 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2024 indenture. On September 25, 2018, we issued $750.0 million aggregate principal amount of new 4.750% senior notes due 2024, which we refer to as the new 2024 notes and, together with the existing 2024 notes, as the 2024 senior notes, as additional notes under, and subject to the terms of, the 2024 Indenture. We received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2024 notes. We used a portion of the net proceeds from the issuance of the new 2024 notes to repay a portion of the outstanding borrowings our revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the Ajax acquisition.
The 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017, and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2024 senior notes; provided, however, that the 2024 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream Operating LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.
For additional information regarding the 2024 senior notes, see Note 9—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
2025 Senior Notes
On December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2025 indenture. On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025 notes and, together with the existing 2025 notes, as additional notes under the 2025 indenture. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream Operating LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.
For additional information regarding the 2025 senior notes, see Note 9—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Energen Notes
At the effective time of the merger, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530.0 million in notes, which we refer to as the Energen Notes, issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee, which we refer to as the Energen Indenture. The Energen Notes consist of: (a) $400.0 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (b) $100.0 million of 7.125% notes due on February 15, 2028, (c) $20.0 million of 7.320% notes due on July 28, 2022, and (d) $10.0 million of 7.35% notes due on July 28, 2027.
The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as our wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen, including any unsecured guaranties by Energen of our indebtedness, and are effectively subordinated to Energen’s senior secured indebtedness, including Energen’s secured guaranty of all borrowings and other obligations under our revolving credit facility, to the extent of the value of the collateral securing such indebtedness.
For additional information regarding the Energen Notes, See Note 9—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Second Amended and Restated Credit Facility
Our credit agreement dated November 1, 2013, as amended and restated, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger, provides for a revolving credit facility inAt December 31, 2020, the maximum credit amount of $5.0available under our credit agreement was $2.0 billion subject to a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing basethe maturity date is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we and Wells Fargo each may request up to two interim redeterminations of the borrowing base during any 12-month period.1, 2022. As of December 31, 2018, the borrowing base was set at $2.65 billion,2020, we had elected a commitment amountapproximately $23 million of $2.0 billion and we hadoutstanding borrowings of $1.5 billion outstanding under theour revolving credit facility, of which approximately $559.0 million was used to by us to repay in full allwe believe provides ample availability for future borrowings, under Energen’s credit facility outstanding prior toincluding funding for the effective timecash portion of the merger.
Diamondback O&G LLC isGuidon acquisition in the borrower under our credit agreement.first quarter of 2021. As of December 31, 2018, the credit agreement is guaranteed by us, Diamondback E&P LLC, Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC) and Energen Corporation and its subsidiaries and will also be guaranteed by any2020, there was an aggregate of our future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR,$3 million in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment,under our credit agreement, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. We are obligated to payreduce available borrowings on a quarterly commitment fee ranging from 0.375% to 0.500% per yeardollar for dollar basis. The weighted average interest rate on the unused portion of the borrowing base, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) atwas 2.02% for the maturity date of November 1, 2022.
year ended December 31, 2020.
The credit agreement contains various affirmative, negative anda financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
|
| |
Financial Covenant | Required Ratio |
Ratio of total net debt to EBITDAX, ascovenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement | Not greater than 4.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt in the formcredit agreement) of senior or senior subordinated notes if no default would result from the incurrence of suchmore than 65%. Our non-guarantor restricted subsidiaries may incur debt after giving effect thereto and if,for borrowed money in connection with any such issuance, the borrowing base is reduced by 25% of the statedan aggregate principal amount up to 15% of eachconsolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such issuance.liens does not exceed 15% of consolidated net tangible assets.
As of
At December 31, 2018,2020, we were in compliance with all financial maintenance covenants under our revolvingthe credit facility.agreement, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms
The May 2020 Notes and provisionsTender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35%
Medium-term Notes
On May 26, 2020, we completed a registered offering of $500 million in aggregate principal amount of our revolving credit facility generally may be amended with4.750% Senior Notes due 2025. Interest on the consentMay 2020 Notes accrues from May 26, 2020, and is payable in cash semi-annually on May 31 and November 30 of each year, beginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. We received net proceeds of approximately $496 million from the offering.
We used the net proceeds, among other things, to make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. As of December 31, 2020, $191 million in aggregate principal amount of Energen’s 4.625% senior notes remained outstanding.
During the third quarter of 2020, we repurchased all $10 million in principal amount of Energen’s outstanding 7.350% medium-term notes due on July 28, 2027 at a price of 120% of the lenders holding a majorityaggregate principal amount.
For additional information, see Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Energen Notes
On November 29, 2018, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes, which we refer to as the Energen Notes. As of December 31, 2020, the aggregate principal amount of the outstanding loans or commitmentsEnergen Notes had been reduced to lend.$311 million consisting of: (a) $191 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (b) $100 million of 7.125% notes due on February 15, 2028, and (c) $20 million of 7.32% notes due on July 28, 2022.
For additional information regarding the Energen Notes, See Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report. Viper’s Facility-Wells Fargo BankCredit Agreement
On July 8, 2014, The Viper entered into a secured revolving credit agreement or revolving credit facility, with Wells Fargo, as administrative agent, certain other lenders, and the Operating Company, as guarantor. On May 8, 2018, the Operating Company
assumed all liabilities as borrower under the credit agreement and Viper became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, Viper, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on Viper’sViper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $555.0$580 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition,November 1st, and was reaffirmed at $580 million by the Operating Company and Wells Fargo each may request up to three interim redeterminations
lenders during the borrowing base during any 12-month period.regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of December 31, 2018, the borrowing base was set at $555.0 million, and2020, Viper LLC had $411.0$84 million of outstanding borrowings and $144.0$496 million available for future borrowings under itsthe Viper credit agreement. During the year ended December 31, 2020, the weighted average interest rate on Viper’s revolving credit facility.facility was 2.20%.
As of December 31, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect.
Viper’s Notes
On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million. Viper received net proceeds of approximately $490 million from the notes offering and loaned the gross proceeds to Viper LLC to pay down borrowings under the Viper credit agreement. Interest on the Viper notes accrues at a rate of 5.375% per annum, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper notes will mature on November 1, 2027.
During the year ended December 31, 2020, Viper repurchased $20 million of outstanding principal of the Viper notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt, and $480 million in aggregate principal amount remained outstanding at December 31, 2020.
See additional discussion in Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Rattler’s Credit Agreement
In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, as administrative agent, and a syndicate of banks, as lenders party thereto, which we refer to as the Rattler credit agreement.
The outstanding borrowings under Viper’sRattler credit agreement bear interest atprovides for a per annum rate elected by the Operating Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR,revolving credit facility in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount of $600 million and has a maturity date of May 28, 2024. As of December 31, 2020, Rattler LLC had $79 million of outstanding borrowings and $521 million available for future borrowings under the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% perRattler credit agreement. During the year ended December 31, 2020, the weighted average interest rate on the unused portionRattler LLC revolving credit facility was 2.10%.
As of December 31, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the commitment, which fee is also dependentRattler credit agreement.
Rattler’s Notes
On July 14, 2020, Rattler completed an offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, or the Rattler Notes Offering. Interest on the amountRattler notes is payable on January 15 and July 15 of loanseach year, beginning on January 15, 2021. The Rattler notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Rattler Notes Offering. Rattler loaned the gross proceeds to Rattler LLC under the terms of a subordinated promissory note, dated as of July 14, 2020. The promissory note requires Rattler LLC to repay the intercompany loan to Rattler on the same terms and lettersin the same amounts as the Rattler notes and has the same maturity date, interest rate, change of credit outstanding in relation tocontrol repurchase and redemption provisions. Rattler LLC used the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of Viper and the Operating Company.
The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below:
|
| |
Financial Covenant | Required Ratio |
Ratio of total net debt to EBITDAX, as defined in the credit agreement | Not greater than 4.0 to 1.0 |
Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of upRattler Notes Offering to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may requirerepay a portion of the outstanding principal of the loan to be repaid.
The lenders may accelerate all of the indebtednessborrowings under the revolvingRattler credit facility uponagreement.
For additional information regarding our indebtedness, see Note 11—Debt included in notes to the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative andconsolidated financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.statements included elsewhere in this Annual Report.
Capital Requirements and Sources of Liquidity
Our board of directors approved a 20192021 capital budget for drilling, midstream and infrastructure of $2.7$1.4 billion to $3.0$1.6 billion, representing an increasea decrease of 85% over50% from our 20182020 capital budget. We estimate that, of these expenditures, approximately:
•$2.31.2 billion to $2.55$1.4 billion will be spent on drilling and completing 290215 to 320235 gross (255(197 to 280215 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9,40010,100 feet;
•$400.060 million to $450.0$80 million will be spent on midstream infrastructure;infrastructure, excluding joint venture investments; and
•$175.070 million to $200.0$90 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.
During the year ended December 31, 2018, our aggregate capital expenditures for drilling and infrastructure were $1.5 billion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
During the year ended December 31, 2018,2020, we spent $1.6 billion on drilling and completion, $140 million on midstream, $108 million on infrastructure and $58 million on non-operated properties, for total capital expenditures of $1.9 billion.
In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. We repurchased approximately $1.4 billion in cash on acquisitions$98 million of leasehold interests and mineral acres.our common stock under this program during the year ended December 31, 2020, prior to the program’s expiration.
The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 21 horizontaleight drilling rigs and eightnine completion crews and currently intend to operate between 18 and 22 drilling rigs in 2019 across our asset base in the Midland and Delaware Basins.crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.
Based upon current oil and natural gas priceprices and production expectations for 2019,2021, we believe that our cash flowflows from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2019.2021. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 20192021 capital expenditure budget does not allocate any funds for leasehold interest and mineral interestproperty acquisitions.
We monitor and adjust our projected capital expenditures in response to success or lackthe results of success inour drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.
Guarantor Financial Information
As of December 31, 2020, Diamondback O&G LLC is the sole guarantor under the December 2019 Notes Indenture governing the December 2019 Notes, the May 2020 Notes and the 2025 Indenture governing the 2025 Senior Notes.
Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the December 2019 Notes Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback O&G LLC (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback O&G LLC ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.
Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes and the 2025 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.
The rights of holders of the Senior Notes against Diamondback O&G LLC may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback O&G LLC’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback O&G LLC. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback O&G LLC, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.
| | | | | | | |
| December 31, 2020 | | |
Summarized Balance Sheets: | (in millions) |
Assets: | | | |
Current assets | $ | 308 | | | |
| | | |
Property and equipment, net | $ | 6,934 | | | |
Other noncurrent assets | $ | 6 | | | |
Liabilities: | | | |
Current liabilities | $ | 355 | | | |
Intercompany accounts payable, non-guarantor subsidiary | $ | 335 | | | |
Long-term debt | $ | 4,293 | | | |
Other noncurrent liabilities | $ | 886 | | | |
| | | | | |
| Year Ended December 31, 2020 |
Summarized Statement of Operations: | (in millions) |
Revenues | $ | 1,618 | |
Income (loss) from operations | $ | (3,466) | |
Net income (loss) | $ | (2,344) | |
Contractual Obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2018:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Payments Due by Period |
| 2021 | | 2022-2023 | | 2024-2025 | | Thereafter | | Total |
| (in millions) |
Secured revolving credit facility(1) | $ | — | | | $ | 23 | | | $ | — | | | $ | — | | | $ | 23 | |
Senior notes | 191 | | | 20 | | | 2,300 | | | 2,100 | | | 4,611 | |
Interest expense related to the senior notes(2) | 181 | | | 342 | | | 279 | | | 212 | | | 1,014 | |
DrillCo Agreement | — | | | — | | | — | | | 79 | | | 79 | |
Viper's secured revolving credit facility(1) | — | | | 84 | | | — | | | — | | | 84 | |
Viper's senior notes | — | | | — | | | — | | | 480 | | | 480 | |
Interest expense related to Viper's senior notes | 26 | | | 52 | | | 52 | | | 52 | | | 182 | |
Rattler's secured revolving credit facility(1) | — | | | — | | | 79 | | | — | | | 79 | |
Rattler's senior notes | — | | | — | | | 500 | | | — | | | 500 | |
Interest expense related to Rattler's senior notes | 28 | | | 56 | | | 55 | | | — | | | 139 | |
Asset retirement obligations(3) | 1 | | | — | | | — | | | 108 | | | 109 | |
Drilling commitments(4) | 29 | | | — | | | — | | | — | | | 29 | |
Sand supply agreements | 18 | | | 36 | | | 36 | | | 5 | | | 95 | |
Transportation commitments | 60 | | | 111 | | | 95 | | | 133 | | | 399 | |
Equity method investment capital contributions(5) | 57 | | | 15 | | | — | | | — | | | 72 | |
Produced water disposal commitments | 5 | | | 9 | | | 9 | | | 33 | | | 56 | |
Operating lease obligations(6) | 6 | | | 3 | | | — | | | — | | | 9 | |
| $ | 602 | | | $ | 751 | | | $ | 3,405 | | | $ | 3,202 | | | $ | 7,960 | |
|
| | | | | | | | | | | | | | | | | | | |
| Payments Due by Period |
| 2019 | | 2020-2021 | | 2022-2023 | | Thereafter | | Total |
| (in thousands) |
Secured revolving credit facility(1) | $ | — |
| | $ | — |
| | $ | 1,489,500 |
| | $ | — |
| | $ | 1,489,500 |
|
Interest expense related to the secured revolving credit facility | 1,914 |
| | 3,829 |
| | 1,594 |
| | — |
| | 7,337 |
|
Senior notes | — |
| | — |
| | — |
| | 2,050,000 |
| | 2,050,000 |
|
Interest expense related to the senior notes(2) | 102,375 |
| | 204,750 |
| | 204,750 |
| | 212,805 |
| | 724,680 |
|
Viper's secured revolving credit facility(1) | — |
| | — |
| | 411,000 |
| | — |
| | 411,000 |
|
Interest and commitment fees under Viper's credit agreement(3) | 540 |
| | 1,080 |
| | 450 |
| | — |
| | 2,070 |
|
Asset retirement obligations (4) | 60 |
| | — |
| | — |
| | 136,181 |
| | 136,241 |
|
Drilling commitments(5) | 18,976 |
| | 414 |
| | — |
| | — |
| | 19,390 |
|
Sand supply agreements | 9,000 |
| | 18,000 |
| | 11,250 |
| | — |
| | 38,250 |
|
Operating lease obligations(6) | 9,019 |
| | 5,279 |
| | 583 |
| | — |
| | 14,881 |
|
| $ | 141,884 |
|
| $ | 233,352 |
|
| $ | 2,119,127 |
|
| $ | 2,398,986 |
| | $ | 4,893,349 |
|
| |
(1) | Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. |
| |
(2) | Interest represents the scheduled cash payments on the senior notes and Energen Notes. |
| |
(3) | Includes only the minimum amount of interest and commitment fees due which, as of December 31, 2018, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement. |
(1)Includes the outstanding principal amount under the revolving credit facilities, the table does not include commitment fees, interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.
69(2)Interest represents the scheduled cash payments on the senior notes and Energen Notes.
future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 9—Asset Retirement Obligations in the notes to the consolidated financial statements included elsewhere in this Annual Report.
| |
(4) | Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 7—Asset Retirement Obligations of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K. |
| |
(5) | Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2018. |
| |
(6) | Operating lease obligations represent future commitments for building, equipment and vehicle leases. |
(4)Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2020.
(5)Timing of when capital commitments will be requested can vary.
(6)Operating lease obligations represent future commitments for building, equipment and vehicle leases.
The table above does not include estimated deficiency fees related to certain volume commitments as they are based off future volume deliveries and differences from market pricing which we cannot predict.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2—Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K.
Use of Estimates
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. ActualCritical accounting policies cover accounting estimates that are inherently uncertain because the future resolution of such matters is unknown and actual results could differ from those estimates.
We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates.
Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include (i) the method of accounting for our oil and natural gas properties, (ii) estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, (iii) impairments of the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation,(iv) fair value estimates of commodity derivatives and (v) estimates of income taxes.
Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments.
Method of accounting for oil and natural gas properties
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties.
Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. If our production remains at approximately the same level from year to year, depletion expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Revenue recognition
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in our contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.
Oil sales
Our oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, we or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in our consolidated statements of operations.
Natural gas and natural gas liquids sales
Under our natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of natural gas liquids and residue gas. In these scenarios, we evaluate whether it is the principal or the agent in the transaction. For those contracts where we have concluded it is the principal and the ultimate third party is its customer, we recognize revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in our consolidated statements of operations.
In certain natural gas processing agreements, we may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, we deliver product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in our consolidated statements of operations.
Midstream Revenue
Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream Operating LLC, or Rattler provides to exploration and production operations. The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in our operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of our facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.
Transaction price allocated to remaining performance obligations
Our upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligation under any of our product sales contracts.
The majority of our midstream revenue agreements have a term greater than one year, and as such Rattler has utilized the practical expedient in ASC 606, which states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The remainder of our midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. Rattler has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.
Contract balances
Under our product sales contracts, we have the right to invoice our customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.
Prior-period performance obligations
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. We believe that the pricing provisions of our oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.
Impairment
We useUnder the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Costs
associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. The inclusion of our unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.
Under this method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedownwrite-down is required.
Asset retirement obligations
We measure the future cost to retire Impairments of our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded inevaluated oil and natural gas properties.properties are not reversible.
Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.
Derivatives
From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We recognize allexercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties’ creditworthiness.
We have not designated our derivative instruments as eitherhedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value.value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. Nonevalues of our derivatives were designated as hedging instruments during the years ended December 31, 2018, 2017 and 2016. Forcommodity derivative instruments not designated as hedginghave a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments changesin earnings in the fair value of these instruments are recognizedperiod in earnings during the period of change.which they occur.
Accounting for Equity-Based Compensation
We grant various types of equity-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 11–Equity-Based Compensation of the Notes to the Consolidated Financial Statements included elsewhere in the Form 10-K. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.
Income Taxes
The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the
period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
Investments
Viper has an equity interest inThe accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a limited partnership that is so minor that Viper has no influence over the limited partnership’s operatingsignificant amount of judgment by management. These assumptions and financial policies. This interest was acquired during the year ended December 31, 2014judgments are reviewed and was accounted for under the cost method. Effective January 1, 2018, Viper adopted Accounting Standards Update 2016-01 which requires Viperadjusted as facts and circumstances change. Material changes to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the year ended December 31, 2018, Viper recorded a loss of $0.6 million. Viper’s investment balance as of December 31, 2018 was $14.5 million, which is included in other assetsour income tax accruals may occur in the accompanyingfuture based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
See Note 2—Summary of Significant Accounting Policies of the notes to the consolidated balance sheets.financial statements included elsewhere in this Annual Report for a full discussion of our significant accounting policies.
Funds Held in Escrow
The funds held in escrow represent amounts in deposit to fund acquisitions. During the year ended December 31, 2018, we did not have any funds held in escrow. During the year ended December 31, 2017, there was $6.3 million in deposit to fund other acquisitions which closed in the first quarter of 2018.
Recent Accounting Pronouncements
Recently Adopted Pronouncements
In May 2014, the FinancialFor information regarding recent accounting pronouncements, See Note 2—Summary of Significant Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This standardPolicies included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. We adopted this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. We utilized a bottom-up approach to analyze the impact of the new standard by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts and the impact of adopting this standards update on our total revenues, operating income and our consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.
In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. We adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.
In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changesnotes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. We enter into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles and compressors. We have completed the process of reviewing and determining the contracts to whichconsolidated financial statements included elsewhere in this new guidance applies. Upon adoption, on January 1, 2019, we recognized approximately $13.6 million of right-of-use assets, of which the total amount relates to our operating leases.
In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. We adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on our financial position, results of operations or liquidity.
Annual Report.
In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The adoption of this update did not have an impact on our financial position, results of operations or liquidity.
In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We adopted this standard as of January 1, 2019. The primary impact of adopting this standard is the recognition of assets and liabilities on the balance sheet for current operating leases.
In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. We adopted this update effective January 1, 2019. The adoption of this standard did not have an effect on our financial position, results of operations or liquidity.
In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update applies to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. We adopted this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard did not have an effect on the presentation on the Statement of Cash Flows.
In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. We adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.
In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update applies to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. We adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on our financial position, results of operations or liquidity.
In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. We adopted this standard effective January 1, 2019. The adoption of this standard did not have a material impact on our financial position, results of operations or liquidity.
In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. We adopted this standard effective January 1, 2019. The adoption of this update did not have a material impact on our financial position, results of operations or liquidity.
Accounting Pronouncements Not Yet Adopted
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope
that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have a material impact on our consolidated financial statements since we do not have a history of credit losses.
In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. We are currently evaluating the impact of the adoption of this update, but do not believe it will have a material impact on our financial position, results of operations or liquidity.
In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We believe the adoption of this update will not have an impact on our financial position, results of operations or liquidity.
In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have an impact on our financial statements since we do not have a history of credit losses.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years ended December 31, 2018, 2017 and 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.
Off-balanceOff-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2018.2020. Please read Note 17—Commitments and Contingencies included in Notesnotes to the Consolidated Financial Statementsconsolidated financial statements included elsewhere in this Form 10-K for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.
We use price swap derivatives, including swaps, basis swaps, swaptions, roll hedges and three-waycostless collars, to reduce price volatility associated with certain of our oil and natural gas sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX WTI
(Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub.
At December 31, 2018,2020, we had a net asset derivative position of $215.3 million as compared to a net liability derivative position of $106.1$255 million at December 31, 2017, related to our commodity price swap, price basis swap derivatives and three-way collars.risk derivatives. Utilizing actual derivative contractual volumes under our fixedcommodity price swaps and fixed price basis swapsderivatives as of December 31, 2018,2020, a 10% increase in forward curves associated with the underlying commodity would have decreasedincreased the net assetliability position to $157.8$284 million, an increase of $57.6$29 million, while a 10% decrease in forward curves associated with the underlying commodity would have increaseddecreased the net assetliability derivative position to $272.9$226 million, a decrease of $57.6$29 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.
In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.
For additional information on our open commodity derivative instruments at December 31, 2020, see Note 15—Derivatives.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $95.5 million at December 31, 2018) anddue to the concentration of receivables from the sale of our oil and natural gas production (approximately $296.5$281 million at December 31, 2018)2020), and to a lesser extent, receivables resulting from joint interest receivables (approximately $56 million at December 31, 2020).
We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us ordue to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. For each of the years ended December 31, 2019 and 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (26%); Koch Supply & Trading LP (15%); and Occidental Energy Marketing Inc (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%).revenue. No other customer accounted for more than 10% of our revenue during these periods. Our allowances for credit losses were insignificant at December 31, 2020.
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2018, we had four customers that represented approximately 82%
The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse macroeconomic conditions may enhance our customer credit risk.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25%0.125% to 1.25%1.0% per annum in the case of the alternative base rate and from 1.25%1.125% to 2.25%2.0% per annum in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. Historically, we have used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility.
AsThe following table summarizes the Company’s interest rate swaps as of December 31, 2018, we had $1.5 billion borrowings outstanding under2020:
| | | | | | | | | | | | | | |
Type | Effective Date | Contractual Termination Date | Notional Amount (in millions) | Interest Rate |
Interest Rate Swap | December 31, 2024 | December 31, 2054 | $ | 250 | | 1.692 | % |
Interest Rate Swap | December 31, 2024 | December 31, 2054 | $ | 250 | | 1.8361 | % |
Interest Rate Swap | December 31, 2024 | December 31, 2054 | $ | 250 | | 1.852 | % |
Interest Rate Swap | December 31, 2024 | December 31, 2054 | $ | 250 | | 1.722 | % |
| | | | |
| | | | |
| | | | |
For additional information on our revolving credit facility. Our weighted averagevariable interest rate on borrowings under our revolving credit facility was 4.10% ondebt at December 31, 2018. An increase or decrease2020, see Note 11—Debt. See Note 18—Subsequent Events for discussion of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $14.9 million based on the $1.5 billion outstanding in the aggregate under our revolving credit facility as of such date.derivative transactions which occurred subsequent to December 31, 2020.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page F-1 of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures
Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of December 31, 2018,2020, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2018,2020, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting
As noted under “Management’s Report on Internal Control over Financial Reporting,” management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting didThere have not include the internal controls of the entities acquired in the merger with Energen on November 29, 2018. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Energen’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were nobeen any changes in our internal control over financial reporting that occurred during the fourth quarter of 2018ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal controlcontrols over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2018. Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Energen on November 29, 2018. Energen’s total assets and total operating revenue represented approximately 47% of the Company’s consolidated total assets at December 31, 2018 and 4.7% of the Company’s consolidated total operating revenue for the year ended December 31, 2018.2020.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2018.2020. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2018,2020, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Diamondback Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2018,2020, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,2020, based on the criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2018,2020, and our report dated February 22, 201925, 2021 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of Energen Corporation, a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 47.0 and 4.7 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2018. As indicated in Management’s Report, Energen Corporation was acquired during 2018. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Energen Corporation.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 22, 2019
25, 2021
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.2020.
We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section at http://ir.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.
ITEM 11. EXECUTIVE COMPENSATION
Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.2020.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.2020.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.2020.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.2020.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
| | | | | | | |
(a) | Documents included in this report: |
| 1. Financial Statements | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| 2. Financial Statement Schedules |
| Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes. | |
|
| | | | | | | |
3. Exhibits |
Exhibit Number | | Description |
2.1# | | |
2.1# | | PurchaseAgreement and Sale Agreement,Plan of Merger, dated as of December 13, 2016,20, 2020, by and among Brigham Resources Operating, LLC and Brigham Resources Midstream, LLC, as sellers, and Diamondback E&P LLC and Diamondback Energy, Inc., as buyersBohemia Merger Sub, Inc. and QEP Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 14, 2016)21, 2020). |
2.2#3.1 | | |
3.1 | | |
3.2 | | |
3.3 | | |
3.4 | | |
4.1 | | |
4.14.2 | | |
4.24.3 | | Indenture, dated as of October 28, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 4.750 % Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 2, 2016). |
4.3 | | First Supplemental Indenture for the 4.750% Senior Notes due 2024, dated as of September 25, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 1, 2018). |
4.4* | | |
4.5* | | Third Supplemental Indenture for the 4.750% Senior Notes due 2024, dated as of January 28, 2019, among Energen Corporation, Energen Resources Corporation, and EGN Services, Inc., each a direct or indirect subsidiary of the Company, the Company, the other guarantors under the indenture and Wells Fargo Bank, National Association, as trustee. |
4.6 | | Indenture, dated as of December 20, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 5.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 21, 2016). |
4.74.4 | | First Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on January 30, 2018). |
4.8* | | |
4.5 | | Second Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of October 12, 2018, among Sidewinder Merger Sub Inc., a subsidiary of the Company, the Company, the other guarantors and Wells Fargo Bank, National Association, as trustee.trustee (incorporated by reference to Exhibit 4.8 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019). |
4.9*4.6 | | Third Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of January 28, 2019, among Energen Corporation, Energen Resources Corporation, and EGN Services, Inc., each a direct or indirect subsidiary of the Company, the Company, the other guarantors under the indenture and Wells Fargo Bank, National Association, as trustee.trustee (incorporated by reference to Exhibit 4.9 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019). |
4.104.7 | | Registration Rights Agreement,Indenture, dated as of February 28, 2017, amongDecember 5, 2019, between Diamondback Energy, Inc., Brigham Resources, LLC, Brigham Resources Operating, LLC and Brigham Resources Upstream Holdings, LP.Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001.35700, filed by the Company with the SEC on March 6, 2017). |
4.11 | | |
|
| | | | | | | |
3. Exhibits |
Exhibit Number | | Description |
4.124.8 | | Registration Rights Agreement,First Supplemental Indenture, dated September 25, 2018,as of December 5, 2019, among Diamondback Energy, Inc., Diamondback O&G LLC and Wells Fargo Bank, National Association, as trustee (including the guarantors party theretoform of 2024 Notes, 2026 Notes and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Goldman Sachs & Co. LLC2029 Notes) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 1, 2018)December 5, 2019). |
4.134.9 | | Second Supplemental Indenture, dated as of May 26, 2020, among Diamondback Energy, Inc., Diamondback O&G LLC and Wells Fargo Bank, National Association, as trustee (including the form of Notes) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on May 26, 2020). |
4.10 | | Indenture, dated as of October 16, 2019, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor, and Wells Fargo Bank, National Association, as trustee (including the form of Viper Energy Partners LP’s 5.375% Senior Notes due 2027) (incorporated by reference to Exhibit 4.1 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019). |
4.11 | | Consent Letter, dated August 28, 2019, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File 001-35700) filed on September 4, 2019). |
4.12 | | |
4.13 | | Indenture, dated as of July 14, 2020, among Rattler Midstream LP, as issuer, Rattler Midstream Operating LLC, Tall City Towers LLC, Rattler Ajax Processing LLC, and Rattler OMOG LLC, as guarantors, and Wells Fargo Bank, National Association, as trustee (including the form of Rattler Midstream LP’s 5.625% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-38919, filed by Rattler Midstream LP with the SEC on July 14, 2020). |
| | |
| | |
4.14 | | |
10.1 | | |
10.2+ | | |
10.3+ | | |
10.4+* | | |
10.5+* | | |
10.6+ | | |
10.7+ | | |
10.8+ | | |
10.9+ | | |
10.10+ | | |
10.11+ | | |
10.12+10.7+ | | |
10.13+10.8+ | | |
10.9+ | | |
10.10+ | | |
10.14 | | |
| | |
10.11+* | | |
| | |
10.12 | | Second Amended and Restated Credit Agreement, dated as of November 1, 2103,2013, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013). |
| | | | | | | | |
10.153. Exhibits |
Exhibit Number | | Description |
10.13 | | First Amendment, dated June 9, 2014, to the Second Amended and Restated Credit Agreement, originally dated November 1, 2013, by and among the Company, as parent guarantor, Diamondback O&G LLC, as borrower, each of the guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 7, 2014). |
10.1610.14 | | Second Amendment to the Second Amended and Restated Credit Agreement, dated as of November 13, 2014, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, the guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 18, 2014). |
|
10.15 | | |
3. Exhibits |
Exhibit Number | | Description |
10.17 | | Third Amendment, dated as of June 21, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 27, 2016). |
10.1810.16 | | Fourth Amendment, dated as of December 15, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 20, 2016). |
10.1910.17 | | Fifth Amendment, dated as of November 28, 2017, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 4, 2017). |
10.2010.18 | | Eighth Amendment to the Second Amended and Restated Credit Agreement, dated as of October 26, 2018, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 1, 2018). |
10.2110.19 | | Ninth Amendment to Second Amended and Restated Credit Agreement and Fourth Amendment to Amended and Restated Guaranty and Collateral Agreement, dated as of November 29, 2018, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 6, 2018). |
10.2210.20 | | ContributionTenth Amendment to Second Amended and Restated Credit Agreement, dated as of March 25, 2019, between Diamondback, as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K (File No. 00 1-35700), filed by the Company with the SEC on March 29, 2019). |
10.21 | | Eleventh Amendment to Second Amended and amongRestated Credit Agreement, dated as of June 28, 2019, between Diamondback Energy, Inc., Viperas parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Partners LLC, Viper Energy Partners GP LLCInc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and Viper Energy Partners LP, dated as of June 17, 2014the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by Viper Energy Partners LPthe Company with the SEC on May 7, 2014)July 3, 2019). |
10.2310.22 | | Amended and Restated Credit Agreement, dated as of July 20, 2018, by and among, Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File 001-36505) filed by Viper Energy Partners LP on July 26, 2018). |
10.2410.23 | | ATM Equity OfferingSM SalesSecond Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated December 11, 2018, byas of September 24, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and among Diamondback Energy, Inc., Ajax Resources, LLC, F&A Wylie Investments, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as sales agentthe lender party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Form 8-K (File 001-36505) filed on September 30, 2019). |
| | | | | | | | |
3. Exhibits |
Exhibit Number | | Description |
10.24 | | Third Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of October 8, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Form 8-K (File 001-36505) filed on October 10, 2019). |
10.25 | | Fourth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 29, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on December 5, 2019). |
10.26 | | Fifth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 11, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2020). |
10.27 | | Sixth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 6, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on November 12, 2020). |
10.28 | | Credit Agreement, dated May 28, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.2 to Rattler Midstream LP’s Form 8-K, File No. 001-35700,001-38919, filed by the CompanyRattler Midstream LP with the SEC on December 12, 2018)May 29, 2019). |
10.25+10.29 | | First Amendment to the Credit Agreement, dated as of October 23, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of Rattler Midstream LP’s Form 8-K (File 001-38919) filed on October 28, 2019). |
10.30 | | Second Amendment, dated as of November 2, 2020, to the Credit Agreement, dated May 28, 2019, as amended on October 23, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto. (incorporated by reference to Exhibit 10.3 of the Partnership’s Quarterly Report on Form 10-Q (File 001-38919) filed on November 5, 2020). |
| | |
10.31+ | | |
10.26+10.32+ | | |
10.27+10.33+ | | |
10.28+10.34+ | | |
10.29+10.35+ | | |
10.30+ | | |
21.1* | | |
23.1* | | |
|
| | |
3. Exhibits21.1* | | |
Exhibit Number23.1* | | Description |
23.2* | | |
23.3* | | |
31.1* | | |
31.2* | | |
| | | | | | | | |
3. Exhibits |
Exhibit Number | | Description |
32.1** | | |
32.2** | | |
99.1* | | |
99.2* | | Report of Ryder Scott Company, L.P., dated January 18, 2019,7, 2021, with respect to an estimate of the proved reserves, future production and income attributable to certain royalty interests of Viper Energy Partners LP, a subsidiary of Diamondback Energy, Inc., as of December 31, 2018.2020. |
101.INS*101 | | XBRL Instance Document.The following financial information from the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to Consolidated Financial Statements. |
101.SCH*104 | | Cover Page Interactive Data File (formatted as Inline XBRL Taxonomy Extension Schema Document. |
101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase. |
101.DEF* | | XBRL Taxonomy Extension Definition Linkbase Document. |
101.LAB* | | XBRL Taxonomy Extension Labels Linkbase Document. |
101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document.and contained in Exhibit 101). |
|
| | | | |
* | Filed herewith. |
** | The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |
+ | Management contract, compensatory plan or arrangement. |
# | The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request. |
ITEM 16. FORM 10-K SUMMARY
NoneNone.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | | | | | | | | | | |
| | | |
| | | DIAMONDBACK ENERGY, INC. |
| | |
Date: | February 22, 201925, 2021 | | |
| | | /s/ Travis D. Stice |
| | | Travis D. Stice |
| | | Chief Executive Officer |
| | | (Principal Executive Officer) |
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
| | | | | | | | | | | | | | |
Signature | | Title | | Date |
| | | |
/s/ Steven E. West | | Chairman of the Board and Director | | February 25, 2021 |
Steven E. West | | | | |
| | | | |
Signature | | Title | | Date |
| | | |
/s/ Steven E. West | | Chairman of the Board and Director | | February 22, 2019 |
Steven E. West | | | | |
| | | | |
/s/ Travis D. Stice | | Chief Executive Officer and Director | | February 22, 201925, 2021 |
Travis D. Stice | | (Principal Executive Officer) | | |
| | | | |
/s/ Vincent K. Brooks | | Director | | February 25, 2021 |
Vincent K. Brooks | | | | |
| | | | |
/s/ Michael P. Cross | | Director | | February 22, 201925, 2021 |
Michael P. Cross | | | | |
| | | | |
/s/ Michael L. Hollis | | President, Chief Operating Officer and Director | | February 22, 2019 |
Michael L. Hollis | | | | |
| | | | |
/s/ David L. Houston | | Director | | February 22, 201925, 2021 |
David L. Houston | | | | |
| | | | |
/s/ Stephanie K. Mains | | Director | | February 25, 2021 |
Stephanie K. Mains | | | | |
| | | | |
/s/ Mark L. Plaumann | | Director | | February 22, 201925, 2021 |
Mark L. Plaumann | | | | |
| | | | |
/s/ Melanie M. Trent | | Director | | February 22, 201925, 2021 |
Melanie M. Trent | | | | |
| | | | |
/s/ Kaes Van’t Hof | | Chief Financial Officer and Executive Vice President—Business Development | | February 25, 2021 |
Kaes Van’t Hof | | (Principal Financial Officer) | | |
| | | | |
/s/ Teresa L. Dick | | Chief FinancialAccounting Officer, SeniorExecutive Vice President and Assistant Secretary | | February 22, 201925, 2021 |
Teresa L. Dick | | (Principal Financial and Accounting Officer) | | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Diamondback Energy, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (collectively the “Company”) as of December 31, 20182020 and 2017,2019, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2018,2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2020, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018,2020, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”), and our report dated February 22, 201925, 2021 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of proved reserves as it relates to the calculation and recognition of depletion expense and the evaluation of impairment
As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues to record depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation and management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Company’s accounting records and the management review controls on information provided to the reservoir engineering specialists and the management review controls on the final proved reserve report prepared by the Company’s specialists.
•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:
–Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
–Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
–Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
–Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of land and division order records;
–Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s or the operator’s intent to develop the proved undeveloped properties;
–Evaluated the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties; and
–Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2009.
Oklahoma City, Oklahoma
February 22, 201925, 2021
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
| | | December 31, | | December 31, |
| 2018 | | 2017 | | 2020 | | 2019 |
| (In thousands, except share amounts) | | (In millions, except par value and share amounts) |
Assets | | | | Assets | |
Current assets: | | | | Current assets: | |
Cash and cash equivalents | $ | 214,516 |
| | $ | 112,446 |
| Cash and cash equivalents | $ | 104 | | | $ | 123 | |
Restricted cash | | Restricted cash | 4 | | | 5 | |
Accounts receivable: | | | | Accounts receivable: | |
Joint interest and other, net | 95,536 |
| | 73,038 |
| Joint interest and other, net | 56 | | | 186 | |
Oil and natural gas sales | 296,525 |
| | 158,575 |
| |
Oil and natural gas sales, net | | Oil and natural gas sales, net | 281 | | | 429 | |
| Inventories | 37,570 |
| | 9,108 |
| Inventories | 33 | | | 37 | |
| Derivative instruments | 230,527 |
| | 531 |
| Derivative instruments | 1 | | | 46 | |
Prepaid expenses and other | 50,347 |
| | 4,903 |
| |
Income tax receivable | | Income tax receivable | 100 | | | 19 | |
Prepaid expenses and other current assets | | Prepaid expenses and other current assets | 23 | | | 24 | |
Total current assets | 925,021 |
| | 358,601 |
| Total current assets | 602 | | | 869 | |
Property and equipment: | | | | Property and equipment: | | | |
Oil and natural gas properties, full cost method of accounting ($9,669,977 and $4,105,865 excluded from amortization at December 31, 2018 and 2017, respectively) | 22,299,182 |
| | 9,232,694 |
| |
Oil and natural gas properties, full cost method of accounting ($7,493 million and $9,207 million excluded from amortization at December 31, 2020 and December 31, 2019, respectively) | | Oil and natural gas properties, full cost method of accounting ($7,493 million and $9,207 million excluded from amortization at December 31, 2020 and December 31, 2019, respectively) | 27,377 | | | 25,782 | |
Midstream assets | 700,295 |
| | 191,519 |
| Midstream assets | 1,013 | | | 931 | |
Other property, equipment and land | 146,963 |
| | 80,776 |
| Other property, equipment and land | 138 | | | 125 | |
Accumulated depletion, depreciation, amortization and impairment | (2,774,465 | ) | | (2,161,372 | ) | Accumulated depletion, depreciation, amortization and impairment | (12,314) | | | (5,003) | |
Net property and equipment | 20,371,975 |
| | 7,343,617 |
| |
Property and equipment, net | | Property and equipment, net | 16,214 | | | 21,835 | |
Funds held in escrow | — |
| | 6,304 |
| Funds held in escrow | 51 | | | 0 | |
Deferred tax asset | 96,670 |
| | — |
| |
Equity method investments | | Equity method investments | 533 | | | 479 | |
Derivative instruments | | Derivative instruments | 0 | | | 7 | |
Deferred income taxes, net | | Deferred income taxes, net | 73 | | | 142 | |
Investment in real estate, net | 115,625 |
| | — |
| Investment in real estate, net | 101 | | | 109 | |
Other assets | 86,396 |
| | 62,463 |
| Other assets | 45 | | | 90 | |
Total assets | $ | 21,595,687 |
| | $ | 7,770,985 |
| Total assets | $ | 17,619 | | | $ | 23,531 | |
Liabilities and Stockholders’ Equity | | | | Liabilities and Stockholders’ Equity | | | |
Current liabilities: | | | | Current liabilities: | |
Accounts payable-trade | $ | 127,979 |
| | $ | 94,590 |
| |
Accounts payable - trade | | Accounts payable - trade | $ | 71 | | | $ | 179 | |
| Accrued capital expenditures | 495,089 |
| | 221,256 |
| Accrued capital expenditures | 186 | | | 475 | |
Current maturities of long-term debt | | Current maturities of long-term debt | 191 | | | 0 | |
Other accrued liabilities | 253,272 |
| | 92,512 |
| Other accrued liabilities | 302 | | | 304 | |
Revenues and royalties payable | 143,272 |
| | 68,703 |
| Revenues and royalties payable | 237 | | | 278 | |
Derivative instruments | — |
| | 100,367 |
| Derivative instruments | 249 | | | 27 | |
| Total current liabilities | 1,019,612 |
| | 577,428 |
| Total current liabilities | 1,236 | | | 1,263 | |
Long-term debt | 4,464,338 |
| | 1,477,347 |
| Long-term debt | 5,624 | | | 5,371 | |
Derivative instruments | 15,192 |
| | 6,303 |
| Derivative instruments | 57 | | | 0 | |
Asset retirement obligations | 136,181 |
| | 20,122 |
| Asset retirement obligations | 108 | | | 94 | |
Deferred income taxes | 1,784,532 |
| | 108,048 |
| Deferred income taxes | 783 | | | 1,886 | |
Other long-term liabilities | 9,570 |
| | — |
| Other long-term liabilities | 7 | | | 11 | |
Total liabilities | 7,429,425 |
| | 2,189,248 |
| Total liabilities | 7,815 | | | 8,625 | |
Commitments and contingencies (Note 17) |
|
| |
|
| Commitments and contingencies (Note 17) | 0 | | 0 |
Stockholders’ equity: | | | | Stockholders’ equity: | |
Common stock, $0.01 par value, 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018; 200,000,000 shares authorized, 98,167,289 issued and outstanding at December 31, 2017 | 1,643 |
| | 982 |
| |
Common stock, $0.01 par value, 200,000,000 shares authorized, 158,088,182 and 159,002,338 issued and outstanding at December 31, 2020 and December 31, 2019, respectively | | Common stock, $0.01 par value, 200,000,000 shares authorized, 158,088,182 and 159,002,338 issued and outstanding at December 31, 2020 and December 31, 2019, respectively | 2 | | | 2 | |
Additional paid-in capital | 12,935,885 |
| | 5,291,011 |
| Additional paid-in capital | 12,656 | | | 12,357 | |
Retained earnings (accumulated deficit) | 761,833 |
| | (37,133 | ) | Retained earnings (accumulated deficit) | (3,864) | | | 890 | |
Accumulated other comprehensive income | (74 | ) | | — |
| |
| Total Diamondback Energy, Inc. stockholders’ equity | 13,699,287 |
| | 5,254,860 |
| Total Diamondback Energy, Inc. stockholders’ equity | 8,794 | | | 13,249 | |
Non-controlling interest | 466,975 |
|
| 326,877 |
| Non-controlling interest | 1,010 | | | 1,657 | |
Total equity | 14,166,262 |
| | 5,581,737 |
| Total equity | 9,804 | | | 14,906 | |
Total liabilities and equity | $ | 21,595,687 |
| | $ | 7,770,985 |
| Total liabilities and equity | $ | 17,619 | | | $ | 23,531 | |
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.