SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|☒||ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the fiscal year ended December 31, 2020
|☐||TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934|
Commission File Number 001-35700
Diamondback Energy, Inc.
(Exact Name of Registrant As Specified in Its Charter)
|(State or Other Jurisdiction of Incorporation or Organization)|
(I.R.S. Employer Identification Number)
|500 West Texas|
|(Address of principal executive offices)|
(Registrant Telephone Number, Including Area Code): (432) 221-7400
|Securities registered pursuant to Section 12(b) of the Act:|
|Title of Each Class||Trading Symbol(s)||Name of Each Exchange on Which Registered|
|Common Stock, par value $0.01 per share||FANG||The Nasdaq Stock Market LLC|
|(NASDAQ Global Select Market)|
|Securities registered pursuant to Section 12(g) of the Act: None|
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act:
|Large Accelerated Filer||☒||Accelerated Filer||☐|
|Non-Accelerated Filer||☐||Smaller Reporting Company||☐|
|Emerging Growth Company||☐|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the eﬀectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2020 was approximately $6.6 billion.
As of February 19, 2021, 158,015,647 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2021 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
DIAMONDBACK ENERGY, INC.
FOR THE YEAR ENDED DECEMBER 31, 2020
TABLE OF CONTENTS
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K, which we refer to as this Annual Report or this report:
|3-D seismic||Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.|
|Basin||A large depression on the earth’s surface in which sediments accumulate.|
|Bbl or barrel||One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.|
|BOE||One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.|
|BOE/d||Barrels of oil equivalent per day.|
Brent sweet light crude oil.
|British Thermal Unit or BTU||The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.|
|Completion||The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.|
|Condensate||Liquid hydrocarbons associated with the production that is primarily natural gas.|
|Crude oil||Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.|
|Developed acreage||Acreage assignable to productive wells.|
|Development costs||Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.|
|Differential||An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.|
|Dry hole or dry well||A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.|
|Estimated Ultimate Recovery or EUR||Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.|
|Exploitation||A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.|
|Field||An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.|
|Finding and development costs||Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.|
|Fracturing||The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.|
|Gross acres or gross wells||The total acres or wells, as the case may be, in which a working interest is owned.|
|Horizontal drilling||A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.|
|Horizontal wells||Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.|
|MBbls||One thousand barrels of crude oil or other liquid hydrocarbons.|
|MBOE||One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.|
|Mcf||One thousand cubic feet of natural gas.|
|Mcf/d||One thousand cubic feet of natural gas per day.|
|Mineral interests||The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.|
|MMBtu||One million British Thermal Units.|
|MMcf||Million cubic feet of natural gas.|
|Net acres or net wells||The sum of the fractional working interest owned in gross acres.|
|Net revenue interest||An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.|
|Net royalty acres||Gross acreage multiplied by the average royalty interest.|
|Oil and natural gas properties||Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.|
|Operator||The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.|
|Play||A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.|
|Plugging and abandonment||Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.|
|Productive well||A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.|
|Prospect||A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.|
|Proved developed reserves||Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.|
|Proved reserves||The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.|
|Proved undeveloped reserves||Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.|
|Recompletion||The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.|
|Reserves||Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).|
|Reservoir||A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.|
|Resource play||A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.|
|Royalty interest||An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.|
|Spacing||The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.|
|Tight formation||A formation with low permeability that produces natural gas with very low flow rates for long periods of time.|
|Undeveloped acreage||Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.|
|Working interest||An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.|
|WTI||West Texas Intermediate.|
GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this Annual Report.
|ASU||Accounting Standards Update.|
|Company||Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.|
Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173).
U.S. Environmental Protection Agency.
|The Company’s Equity Incentive Plan.|
The Securities Exchange Act of 1934, as amended.
Financial Accounting Standards Board.
Federal Energy Regulatory Commission.
Accounting principles generally accepted in the United States.
|2025 Indenture||The indenture relating to the 2025 Senior Notes, dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.|
|2025 Senior Notes|
The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
|December 2019 Notes Indenture||The indenture relating to the December 2019 Notes dated as of December 5, 2019, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.|
|December 2019 Notes|
The Company’s 2.875% senior unsecured notes due 2024 in the aggregate principal amount of $1.0 billion, the Company’s 3.250% senior unsecured notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% senior unsecured notes due 2029 in the aggregate principal amount of $1.2 billion.
|May 2020 Notes|
The Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued on May 26, 2020 under the December 2019 Notes Indenture (defined above) and the related second supplemental indenture.
|NYMEX||New York Mercantile Exchange.|
Rattler Midstream LP, a Delaware limited partnership.
Rattler’s general partner
Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly owned subsidiary of the Company.
Rattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler.
Rattler Midstream LP Long-Term Incentive Plan.
Rattler’s initial public offering.
Ryder Scott Company, L.P.
Securities and Exchange Commission.
|SEC Prices||Unweighted arithmetic average oil and natural gas prices as of the first day of the month for the most recent 12 months as of the balance sheet date.|
The Securities Act of 1933, as amended.
|Senior Notes||The 2025 Senior Notes, the December 2019 Notes and the May 2020 Notes.|
|Viper||Viper Energy Partners LP, a Delaware limited partnership.|
|Viper’s general partner||Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.|
|Viper LLC||Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.|
Wells Fargo Bank, National Association.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in this Annual Report are “forward-looking statements” as defined by the SEC. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include statements about:
•the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Counties, or OPEC, members and other oil exporting nations;
•the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic, any government responses thereto and logistical challenges and the supply chain disruptions during the ongoing COVID-10 pandemic;
•any impact of the ongoing COVID-19 pandemic on the health and safety of our employees;
•logistical challenges and the supply chain disruptions;
•changes in general economic, business or industry conditions;
•conditions in the capital, financial and credit markets and our ability to obtain capital needed for development and exploration operations on favorable terms or at all;
•conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;
•U.S. and global economic conditions and political and economic developments, including the effects of the recent U.S. presidential and congressional elections on energy and environmental policies;
•our ability to execute our business and financial strategies;
•exploration and development drilling prospects, inventories, projects and programs;
•levels of production;
•the impact of reduced drilling activity on our exploration and development drilling prospects, inventories, projects and programs;
•regional supply and demand factors, delays, curtailments delays or interruptions of production, and any governmental order, rule of regulation that may impose production limits;
•our ability to replace our oil and natural gas reserves;
•our ability to identify, complete and effectively integrate acquisitions of properties or businesses, including our pending merger with QEP Resources, Inc., or QEP, and the Pending Guidon Acquisition (defined below);
•competition in the oil and natural gas industry;
•title defects in our oil and natural gas properties;
•uncertainties with respect to identified drilling locations and estimates of reserves;
•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;
•the impact of severe weather conditions, including the recent winter storms in the Permian Basin, on our production;
•restrictions on the use of water;
•the availability of transportation, pipeline and storage facilities;
•our ability to comply with applicable government laws and regulations and to obtain permits and governmental approvals;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;
•our environmental initiatives and targets;
•future operating results;
•future dividends to our stockholders;
•impact of any impairment charges;
•lease operating expenses, general and administrative costs and finding and development costs;
•civil unrest, terrorist attacks and cyber threats;
•the effects of litigation relating to our pending merger with QEP and any future litigation;
•our ability to keep up with technological advancements;
•capital expenditure plans;
•other plans, objectives, expectations and intentions; and
•certain other factors discussed elsewhere in this report.
All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.
Except as noted, in this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,” or “the Company”. This Annual Report includes certain terms commonly used in the oil and natural gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”
ITEMS 1 and 2. BUSINESS AND PROPERTIES
We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators. We report operations in two operating segments: (i) the upstream segment and (ii) the midstream operations segment, which includes midstream services and real estate operations.
Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. These formations are characterized by a high concentration of oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.
At December 31, 2020, our total acreage position in the Permian Basin was approximately 449,642 gross (378,678 net) acres, which consisted primarily of approximately 215,956 gross (194,591 net) acres in the Midland Basin and approximately 192,697 gross (152,587 net) acres in the Delaware Basin.
In addition, our publicly traded subsidiary Viper Energy Partners LP, which we refer to as Viper, owns mineral interests in the Permian Basin and Eagle Ford Shale. We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as Viper’s general partner, and we own approximately 58% of the limited partner interest in Viper.
Further, our publicly traded subsidiary Rattler Midstream Partners LP, which we refer to as Rattler, is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. We own Rattler Midstream GP LLC, the general partner of Rattler, which we refer to as Rattler’s general partner, and we own approximately 72% of the limited partner interest in Rattler.
As of December 31, 2020, our estimated proved oil and natural gas reserves were 1,316,441 MBOE (which includes estimated reserves of 99,392 MBOE attributable to the mineral interests owned by Viper). Of these reserves, approximately 62% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 628 gross (559 net) horizontal well locations in which we have a working interest, and 38 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2020, our estimated proved reserves were approximately 58% oil, 22% natural gas liquids and 20% natural gas.
Pending Merger with QEP Resources, Inc.
On December 20, 2020, we, QEP Resources, Inc., or QEP, and Bohemia Merger Sub, Inc., our wholly owned subsidiary, or the Merger Sub, entered into an Agreement and Plan of Merger, which is referred to as the merger agreement, under which Merger Sub will be merged with and into QEP, with QEP surviving as our wholly owned subsidiary, which we refer to as the pending merger. If the pending merger is completed, each QEP stockholder will receive, in exchange for each share of QEP common stock held 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 (a) the receipt of the required approvals from QEP’s stockholders, (b) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, or the HSR Act, (c) the absence of any governmental order or law that makes consummation of the pending merger illegal or otherwise prohibited, (d) the effectiveness of the registration statement on Form S-4 relating to the shares of our common stock to be issued in connection with the pending merger, which registration statement was declared effective by the SEC on February 10, 2021, and (e) the authorization for listing of such common stock on the Nasdaq Global Select Market. The obligation of each party to consummate the pending merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions), the other party having performed in all material respects its obligations
Pending Guidon Acquisition
On December 18, 2020, we and Diamondback E&P LLC, our wholly owned subsidiary, entered into a definitive, purchase and sale agreement with Guidon Operating LLC, or Guidon, and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets, which we refer to as the Pending Guidon Acquisition. Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment. The Pending Guidon Acquisition is expected to close on February 26, 2021.
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 then continued to decline reaching negative levels. During 2020, the average NYMEX WTI futures contract price for crude oil and condensate was $39.34 per barrel and the average Henry Hub futures contract price for natural gas was $2.13 per million British thermal units (MMBtu), representing decreases of 31% and 16%, respectively, from the comparable average futures prices during 2019. These decreases were the result of multiple factors affecting 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 budget 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. For additional details, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”
Given the dynamic nature of the events described above, we cannot reasonably estimate the period of time that the ongoing COVID-19 pandemic, the depressed commodity prices, the reduced demand for oil 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.
Our Business Strategy
Our business strategy is to continue to profitably grow our business through the following:
•Grow production and reserves by developing our oil-rich resource base. We intend to drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital.
•Leverage our experience operating in the Permian Basin. Our executive team, which has an average of over 25 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous
drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.
•Enhance returns through our low cost development strategy and focus on continuous improvement in operational, capital allocation and cost efficiencies. Our acreage position is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 98% of our acreage. This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 84% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.
•Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. Most recently, in December 2020, we entered into the merger agreement with QEP to acquire QEP in an all-stock transaction valued at approximately $2.2 billion, including QEP’s net debt of $1.6 billion as of September 30, 2020. The pending merger, upon closing, will add material Tier-1 Midland Basin inventory. In December 2020, we also entered into a definitive purchase and sale agreement with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets.
•Maintain financial flexibility. We seek to maintain a conservative financial position. As of December 31, 2020, our borrowing base was set at $2.0 billion and we had $1.98 billion available for borrowing. As of December 31, 2020, Viper LLC had $84 million in outstanding borrowings, and $496 million available for borrowing, under its revolving credit facility. As of December 31, 2020, Rattler LLC had $79 million in outstanding borrowings, and $521 million available for borrowing, under its revolving credit facility.
We believe that the following strengths will help us achieve our business goals:
•Oil rich resource base in one of North America’s leading resource plays. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Permian Basin. Our production for the year ended December 31, 2020 was approximately 60% oil, 20% natural gas liquids and 20% natural gas. As of December 31, 2020, our estimated net proved reserves were comprised of approximately 58% oil, 22% natural gas liquids and 20% natural gas.
•Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. 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 on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 8,200 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. In addition, we have approximately 3,610 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions.
•Experienced, incentivized and proven management team. Our executive team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells in addition to horizontal well reservoir and geologic expertise, which is of strategic importance as we expand our horizontal drilling activity.
•Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longest operating hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks in the Permian Basin as compared to emerging hydrocarbon basins.
•High degree of operational control. We are the operator of approximately 98% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.
•Access to midstream infrastructure and gathering and transportation pipelines. Through our publicly traded subsidiary Rattler, we have secured access to midstream infrastructure and crude oil gathering and transportation pipelines tailored to our expected production growth ramp in order to allow us the operational flexibility to execute on our growth plan. Rattler is the primary provider of midstream services to us with an acreage dedication that spans a total of approximately 395,000 gross acres across all of Rattler’s service lines and over the core of the Midland and Delaware Basins.
Location and Land
The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. As of December 31, 2020, our total acreage position in the Permian Basin was approximately 449,642 gross (378,678 net) acres, which consisted primarily of approximately 215,956 gross (194,591 net) acres in the Midland Basin and approximately 192,697 gross (152,587 net) acres in the Delaware Basin. We are the operator of approximately 98% of this Permian Basin acreage. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 787,264 gross acres and 24,350 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 52% of these net royalty acres are operated by us.
We have been developing multiple pay intervals in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. We believe our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. The following table presents horizontal producing wells in which we have a working interest in as of December 31, 2020:
|Basin||Number of Horizontal Wells|
(1) Of these 2,380 total horizontal producing wells, we are the operator of 1,694 wells and have a non-operated working interest in 686 additional wells.
The following table presents the average number of days in which we were able to drill our horizontal wells to total depth specified below during the year ended December 31, 2020:
|Average Days to Total Depth|
|7,500 foot lateral||12 |
|10,000 foot lateral||13 |
|13,000 foot lateral||17 |
|7,500 foot lateral||16 |
|10,000 foot lateral||18 |
|13,000 foot lateral||26 |
Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.
Further, our subsidiary Rattler is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. As of December 31, 2020, Rattler owned and operated 927 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our seven core Midland and Delaware Basin development areas. To facilitate the transportation of water and hydrocarbon volumes away from the producing wellhead to ensuring the efficient operations of a crude oil or natural gas well, Rattler’s midstream infrastructure includes a network of gathering pipelines that collect and transport crude oil, natural gas and produced water from our operations in the Midland and Delaware Basins.
As of December 31, 2020, Rattler also owned (i) a 10% equity interest in EPIC Crude Holdings LP, which owns and operates a long-haul crude oil pipeline from the Permian Basin and the Eagle Ford Shale to Corpus Christi, Texas that is capable of transporting approximately 600,000 Bbl/d, which began full operations in April 2020 and is referred to as the EPIC pipeline, (ii) a 10% equity interest in Gray Oak Pipeline, LLC, which owns and operates a long-haul crude oil pipeline that is capable of transporting 900,000 Bbl/d from the Permian Basin and the Eagle Ford Shale to points alongside the Texas Gulf Coast, including a marine terminal connection in Corpus Christi, Texas, which began full operations in April 2020 and is referred to as the Gray Oak pipeline, (iii) a 4% equity interest in Wink to Webster Pipeline LLC, which is developing a crude oil pipeline that upon full commercial operations expected in the fourth quarter of 2021 will be capable of transporting approximately 1,500,000 Bbl/d from origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations, (iv) a 60% equity interest in OMOG JV LLC, which operates approximately 235 miles of crude oil gathering and regional transportation pipelines and approximately 200,000 barrels of crude oil storage in Midland, Martin, Andrews and Ector Counties, Texas and (v) a 50% equity interest in Amarillo Rattler LLC, which owns and operates the Yellow Rose gas gathering and processing system with estimated total capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. For additional information regarding our equity method investments as of December 31, 2020, see Note 10—Equity Method Investments to our consolidated financial statements included elsewhere in this Annual Report.
Rattler also owns and operates certain real estate assets in Midland, Texas including the Fasken Center which has over 421,000 net rentable square feet within its two office towers.
Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, Wolfcamp, Strawn, Atoka and Barnett formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.
The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.
By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Permian Spraberry, Dean and Wolfcamp formations, which we collectively refer to as the Wolfberry play. Since then we and most other operators are almost exclusively drilling horizontal wells in the development of unconventional reservoirs in the Permian Basin. As of December 31, 2020, we held working interests in 4,326 gross (3,401 net) producing wells and only royalty interests in 4,553 additional wells.
The Greater Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence of the Marathon Uplift and Ancestral Rockies. It is one of the most productive sedimentary basins in the U.S., with established oil and natural gas production from several stacked reservoirs of varying age ranges, most notably Permian aged sediments. In particular, the Permian aged Wolfcamp, Spraberry and Bone Spring Formations have been heavily targeted for several decades. First, through vertical comingling of these zones and, more recently, through horizontal exploitation of each individual horizon. Prior to deposition of the Wolfcamp, Spraberry and Bone Spring Formations, the area of the present-day Permian Basin was a continuous sedimentary feature called the Tabosa Basin. During this time, Ordovician, Silurian, Devonian and Mississippian sediments were laid down in a primarily open marine, shelf setting. However, some time frames saw more restrictive settings that were conducive to the deposition of organically rich mudstone such as the Devonian Woodford and Mississippian Barnett/Meramec. These formations are important sources and, more recently, reservoirs within the present-day Greater Permian Basin.
The Spraberry and Bone Spring Formations were deposited as siliciclastic and carbonate turbidites and debris flows along with pelagic mudstones in a deep-water, basinal environment, while the Wolfcamp reservoirs consist of debris-flow, grain-flow and fine-grained pelagic sediments, which were also deposited in a basinal setting. The best carbonate reservoirs within the Wolfcamp, Spraberry and Bone Spring are generally found in close proximity to the Central Basin Platform, while mudstone reservoirs thicken basin-ward, away from the Central Basin Platform. The mudstone within these reservoirs is organically rich, which when buried to sufficient depth for thermal maturation, became the source of the hydrocarbons found both within the mudstones themselves and in the interbedded conventional clastic and carbonate reservoirs. Due to this complexity, the Wolfcamp, Spraberry and Bone Spring intervals are a hybrid reservoir system that contains characteristics of both unconventional and conventional reservoirs.
We have successfully developed several hybrid reservoir intervals within the Clearfork, Spraberry/Bone Spring, Wolfcamp and Barnett/Meramec formations since we began horizontal drilling in 2012. The mudstones and some clastics exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage of hydrocarbons in these targets.
We possess, or are in the process of acquiring, 3-D seismic data over substantially all of our major asset areas. Our extensive geophysical database currently includes approximately 3,610 square miles of 3-D data. This data will continue to be utilized in the development of our horizontal drilling program and identification of additional resources to be exploited.
During the year ended December 31, 2020, net production from our acreage was 109,921 MBOE, or an average of 300,331 BOE/d, of which approximately 60% was oil, 20% was natural gas liquids and 20% was natural gas.
Recent and Future Activity
During 2021, we expect to complete an estimated 215 to 235 gross (197 to 215 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2021 for drilling and infrastructure will be between $1.4 billion and $1.6 billion, consisting of $1.2 billion to $1.4 billion for horizontal drilling and completions including non-operated activity, $60 million to $80 million for midstream investments, excluding joint venture investments, and $70 million to $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, 2020, we drilled 208 gross (195 net) and completed 171 gross (159 net) operated horizontal wells. During the year ended December 31, 2020, our capital expenditures for drilling, completing and equipping wells were $1.6 billion. In addition, we spent $248 million for oil and natural gas midstream and infrastructure.
We were operating eight drilling rigs at December 31, 2020 and currently intend to operate between eight and 12 rigs on average in 2021. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions.
Based on our evaluation of applicable geologic and engineering data, we currently have approximately 10,413 gross (6,863 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $60.00 per Bbl WTI. With our current development plan, we expect to continue our strong PUD conversion ratio in 2021 by converting an estimated 30% of our PUDs to a proved developed category and developing approximately 80% of the consolidated 2020 year-end PUD reserves by the end of 2023.
Oil and Natural Gas Data
Evaluation and Review of Reserves
Our historical reserve estimates as of December 31, 2020, 2019 and 2018 were prepared by Ryder Scott with respect to our assets and those of Viper. Ryder Scott is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.
Under SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2020 were estimated using a deterministic method.
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Approximately 90% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.
To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.
The process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, we maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve reports to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical
information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.
Our Executive Vice President–Chief Engineer is primarily responsible for overseeing the preparation of all our reserve estimates. Our Executive Vice President–Chief Engineer is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 20 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.
The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
•review and verification of historical production data, which data is based on actual production as reported by us;
•preparation of reserve estimates by our Executive Vice President–Chief Engineer or under his direct supervision;
•review by our Executive Vice President–Chief Engineer of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
•direct reporting responsibilities by our Executive Vice President–Chief Engineer to our Chief Executive Officer;
•verification of property ownership by our land department; and
•no employee’s compensation is tied to the amount of reserves booked.
The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2020, 2019 and 2018 (including those attributable to Viper), based on the reserve reports prepared by Ryder Scott in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States. As of December 31, 2020, none of our total proved reserves were classified as proved developed non-producing.
|As of December 31,|
|Estimated Proved Developed Reserves:|
|Oil (MBbls)||443,464 ||457,083 ||403,051 |
|Natural gas (MMcf)||1,085,035 ||824,760 ||705,084 |
|Natural gas liquids (MBbls)||192,495 ||165,173 ||125,509 |
|Total (MBOE)||816,798 ||759,716 ||646,074 |
|Estimated Proved Undeveloped Reserves:|
|Oil (MBbls)||315,937 ||253,820 ||223,885 |
|Natural gas (MMcf)||522,029 ||294,051 ||343,565 |
|Natural gas liquids (MBbls)||96,701 ||65,030 ||64,782 |
|Total (MBOE)||499,643 ||367,859 ||345,928 |
|Estimated Net Proved Reserves:|
|Oil (MBbls)||759,401 ||710,903 ||626,936 |
|Natural gas (MMcf)||1,607,064 ||1,118,811 ||1,048,649 |
|Natural gas liquids (MBbls)||289,196 ||230,203 ||190,291 |
|1,316,441 ||1,127,575 ||992,001 |
|Percent proved developed||62%||67%||65%|(1)Estimates of reserves as of December 31, 2020, 2019 and 2018 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 ended December 31, 2020, 2019 and 2018, respectively, in accordance with SEC guidelines. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties, all of which are located within the continental United States. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. See “Item 1A. Risk Factors” for a discussion of risks and uncertainties associated with our estimates of proved reserves and related factors, and see Note 20—Supplemental Information on Oil and Natural Gas Operations for further discussion of our reserve estimates and pricing.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2020, our proved undeveloped reserves totaled 315,937 MBbls of oil, 522,029 MMcf of natural gas and 96,701 MBbls of natural gas liquids, for a total of 499,643 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
The following table includes the changes in PUD reserves for 2020 (MBOE):
|Beginning proved undeveloped reserves at December 31, 2019||367,859 |
|Undeveloped reserves transferred to developed||(89,133)|
|Extensions and discoveries||235,709 |
|Ending proved undeveloped reserves at December 31, 2020||499,643 |
The increase in proved undeveloped reserves was primarily attributable to extensions of 220,023 MBOE from 277 gross (236 net) wells in which we have a working interest and 15,686 MBOE from 299 gross wells in which Viper owns royalty interests. Of the 277 gross working interest wells, 98 were in the Delaware Basin. Transfers of 89,133 MBOE from undeveloped to developed reserves were the result of drilling or participating in 102 gross (94 net) horizontal wells in which we have a working interest and 82 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 78 of the 82 gross Viper wells. Downward revisions of 15,742 MBOE were the result of (i) negative revisions of 4,226 MBOE due to lower product pricing, which were partially offset by positive revisions of 1,494 MBoe associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 2,732 MBOE, and (ii) PUD downgrades of 26,329 MBOE are primarily from changes in the corporate development plan. These negative revisions were offset with positive revisions of 13,319 MBOE associated with less gas flaring and a corresponding increase in shrunk gas and natural gas liquid recoveries.
Costs incurred relating to the development of PUDs were approximately $381 million during 2020. Estimated future development costs relating to the development of PUDs are projected to be approximately $676 million in 2021, $764 million in 2022, $859 million in 2023 and $531 million in 2024. Since our formation in 2011, our average drilling costs and drilling times have been reduced, and we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.
As of December 31, 2020, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.
We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. 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 on our acreage based on our evaluation of applicable geologic and engineering data. The following table presents the number of identified economic potential horizontal drilling locations by basin:
|Number of Identified Economic Potential Horizontal Drilling Locations|
|Total Midland Basin||6,115|
2nd Bone Springs(4)
3rd Bone Springs(4)
|Total Delaware Basin||4,298|
(1)Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties.
(2)Our current location count is based on 660 foot spacing in Midland, Martin and northeast Andrews counties, depending on the prospect area and 880 foot spacing in all other counties.
(3)Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties.
(4)Our current location count is based on 880 foot to 1,320 foot spacing.
(5)Our current location count is based on 880 foot to 1,056 foot spacing.
Oil and Natural Gas Production Prices and Production Costs
Production and Price History
The following tables set forth information regarding our net production of oil, natural gas and natural gas liquids by basin for each of the periods indicated:
|Midland Basin||Delaware Basin|
|Year Ended December 31, 2020|
|Oil (MBbls)||38,313 ||27,703 ||166 ||66,182 |
|Natural gas (MMcf)||68,529 ||61,606 ||414 ||130,549 |
|Natural gas liquids (MBbls)||12,597 ||9,295 ||89 ||21,981 |
|Total (MBoe)||62,332 ||47,266 ||324 ||109,921 |
|Year Ended December 31, 2019|
|Oil (MBbls)||41,156 ||25,951 ||1,411 ||68,518 |
|Natural gas (MMcf)||48,109 ||48,447 ||1,057 ||97,613 |
|Natural gas liquids (MBbls)||10,485 ||7,826 ||187 ||18,498 |
|Total (MBoe)||59,659 ||41,852 ||1,774 ||103,285 |
|Year Ended December 31, 2018|
|Oil (MBbls)||24,698 ||9,288 ||381 ||34,367 |
|Natural gas (MMcf)||21,674 ||12,416 ||579 ||34,669 |
|Natural gas liquids (MBbls)||5,493 ||1,866 ||106 ||7,465 |
|Total (MBoe)||33,803 ||13,223 ||584 ||47,610 |
(1)Production data for the years ended December 31, 2020 and 2019 includes the Central Basin Platform, the Eagle Ford Shale and the Rockies.
(2)Production data for the year ended December 31, 2018 includes the Eagle Ford Shale.
The following table sets forth certain price and cost information for each of the periods indicated:
|Year Ended December 31,|
|Oil ($ per Bbl)||$||36.41 ||$||51.87 ||$||54.66 |
|Natural gas ($ per Mcf)||$||0.82 ||$||0.68 ||$||1.76 |
|Natural gas liquids ($ per Bbl)||$||10.87 ||$||14.42 ||$||25.47 |
|Combined ($ per BOE)||$||25.07 ||$||37.63 ||$||44.73 |
Oil, hedged ($ per Bbl)(1)
|$||40.34 ||$||51.96 ||$||51.20 |
Natural gas, hedged ($ per MMbtu)(1)
|$||0.67 ||$||0.86 ||$||1.72 |
Natural gas liquids, hedged ($ per Bbl)(1)
|$||10.83 ||$||15.20 ||$||25.46 |
Average price, hedged ($ per BOE)(1)
|$||27.26 ||$||38.00 ||$||42.20 |
|Average Costs per BOE:|
|Lease operating expenses||$||3.87 ||$||4.74 ||$||4.31 |
|Production and ad valorem taxes||1.77 ||2.40 ||2.79 |
|Gathering and transportation expense||1.27 ||0.86 ||0.55 |
|General and administrative - cash component||0.46 ||0.54 ||0.79 |
|Total operating expense - cash||$||7.37 ||$||8.54 ||$||8.44 |
|General and administrative - non-cash component||$||0.34 ||$||0.46 ||$||0.57 |
|Depletion||11.30 ||13.54 ||12.50 |
|Interest expense, net||1.79 ||1.66 ||1.83 |
|Merger and integration expense||— ||— ||0.77 |
|Total expenses||$||13.43 ||$||15.66 ||$||15.67 |
(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and includes gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting.
Wells Drilled and Completed in 2020
The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2020:
|Year Ended December 31, 2020|
|Midland Basin||133 ||125 ||93 ||85 |
|Delaware Basin||75 ||70 ||78 ||74 |
|Total||208 ||195 ||171 ||159 |
As of December 31, 2020, we operated the following wells:
|Vertical Wells||Horizontal Wells||Total|
|Midland Basin||1,745 ||1,641 ||1,102 ||1,008 ||2,847 ||2,649 |
|Delaware Basin||25 ||22 ||592 ||557 ||617 ||579 |
|Total||1,770 ||1,663 ||1,694 ||1,565 ||3,464 ||3,228 |
As of December 31, 2020, we owned an average unweighted 79% working interest in 4,326 gross (3,401 net) productive wells and an average 1.8% royalty interest in 4,553 additional wells. Through our subsidiary Viper, we own an average 3.8% net revenue interest in 7,167 gross productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
The following table sets forth information regarding productive wells by basin as of December 31, 2020:
|Gross Wells||Net Wells|
|Oil||Natural Gas||Total||Oil||Natural Gas||Total|
|Midland Basin||5,397 ||29 ||5,426 ||2,740 ||10 ||2,750 |
|Delaware Basin||1,904 ||158 ||2,062 ||630 ||19 ||649 |
|Other||1,316 ||75 ||1,391 ||2 ||— ||2 |
|Total productive wells||8,617 ||262 ||8,879 ||3,372 ||29 ||3,401 |
The following tables set forth information with respect to the number of wells completed during the periods indicated by basin. Each of these wells was drilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
|Year Ended December 31, 2020|
|Midland Basin||Delaware Basin||Total|
|Productive||87 ||81 ||26 ||25 ||113 ||106 |
|Dry||— ||— ||— ||— ||— ||— |
|Productive||46 ||44 ||49 ||45 ||95 ||89 |
|Dry||— ||— ||— ||— ||— ||— |
|Productive||133 ||125 ||75 ||70 ||208 ||195 |
|Dry||— ||— ||— ||— ||— ||— |
|Year Ended December 31, 2019|
|Midland Basin||Delaware Basin||Total|
|Productive||75 ||68 ||31 ||28 ||106 ||96 |
|Dry||— ||— ||— ||— ||— ||— |
|Productive||96 ||86 ||128 ||114 ||224 ||200 |
|Dry||— ||— ||— ||— ||— ||— |
|Productive||171 ||154 ||159 ||142 ||330 ||296 |
|Dry||— ||— ||— ||— ||— ||— |
|Year Ended December 31, 2018|
|Midland Basin||Delaware Basin||Total|
|Productive||67 ||58 ||21 ||20 ||88 ||78 |
|Dry||— ||— ||— ||— ||— ||— |
|Productive||50 ||43 ||38 ||35 ||88 ||78 |
|Dry||— ||— ||— ||— ||— ||— |
|Productive||117 ||101 ||59 ||55 ||176 ||156 |
|Dry||— ||— ||— ||— ||— ||— |
As of December 31, 2020, we had 20 gross (19 net) operated wells in the process of drilling and 151 gross (141 net) in the process of completion or waiting on completion.
The following table sets forth information as of December 31, 2020 relating to our leasehold acreage:
|Midland||119,073 ||99,751 ||96,883 ||94,840 ||215,956 ||194,591 |
|Delaware||103,712 ||77,263 ||88,985 ||75,324 ||192,697 ||152,587 |
|Exploration||107 ||107 ||38,097 ||28,838 ||38,204 ||28,945 |
|Conventional Permian||40 ||38 ||2,745 ||2,517 ||2,785 ||2,555 |
|Total||222,932 ||177,159 ||226,710 ||201,519 ||449,642 ||378,678 |
(1)Does not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.
(2)Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.
Undeveloped acreage expirations
As of December 31, 2020, the following gross and net undeveloped acres are set to expire over the next four years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.
|2021||13,727 ||8,149 ||24,099 ||21,093 ||23,474 ||22,063 ||61,300 ||51,305 |
|2022||9,634 ||1,063 ||3,294 ||813 ||659 ||165 ||13,587 ||2,041 |
|2023||966 ||410 ||1,951 ||1,597 ||— ||— ||2,917 ||2,007 |
|2024||370 ||59 ||— ||— ||— ||— ||370 ||59 |
|Total||24,697 ||9,681 ||29,344 ||23,503 ||24,133 ||22,228 ||78,174 ||55,412 |
Title to Properties
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.
Marketing and Customers
We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. 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 do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. For additional information regarding our customer concentrations, see Note 3—Revenue from Contracts with Customers included in notes to the consolidated financial statements included elsewhere in this Annual Report.
Certain of our firm sales agreements for oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We believe our current production and reserves are sufficient to fulfill these delivery commitments and we expect such reserves will continue to be the primary means of fulfilling our future commitments. However, these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate to satisfy our commitment. For additional information regarding commitments, see Note 17—Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Annual Report.
The oil and natural gas industry is intensely competitive, and in our upstream segment, we compete with other companies that have greater resources. 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 to 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 or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local 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. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
In our midstream operations segment, as Rattler seeks to expand its crude oil, natural gas and water-related midstream services, it faces a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store or market oil and natural gas. As Rattler seeks to expand to provide midstream services to third party producers, it similarly faces a high level of competition. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas or natural gas liquids. Within the acreage dedicated by Rattler to us, Rattler does not compete with other midstream companies to provide us with midstream services as a result of our relationship and long-term dedications to Rattler’s midstream assets. However, we may continue to use third party service providers for certain midstream services within such dedicated acreage until the expiration or termination of certain pre-existing dedications.
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 and Delaware Basins are transported to purchasers by pipeline.
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||95 ||%||93 ||%||94 ||%|
|% of produced water transported by pipeline||97 ||%||98 ||%||98 ||%|
We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include a total of approximately 395,000 gross acres across all Rattler’s service lines across the Midland and Delaware Basins.
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 12.5% to 30.0%, resulting in a net revenue interest to us generally ranging from 70.0% to 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. In 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.
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 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 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. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and natural gas waste are not necessary at this time. Any changes in such 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 CWA 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 CWA. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules. The 2015 rule and the 2019 repeal are subject to several ongoing legal challenges. Also, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the CWA. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the 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 rules expand the range of properties subject to the CWA’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 OPA is the primary federal law for oil spill liability. The OPA 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 OPA 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 CWA or the OPA 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 CAA that establish new emission controls for oil and natural gas production and processing operations, which 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 CAA 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 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. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and natural gas operations. For example, on November 4, 2020, the Texas Railroad Commission adopted new guidance on when flaring is permissible, requiring operators to submit more specific information to justify the need to 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. Although the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, 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 its commitment to reduce its national greenhouse gas emissions to meet this objective. Furthermore, many state and local leaders have stated their intent to intensify efforts to support 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, 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 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.
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 CAA 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, the 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. Accordingly, on August 13, 2020, the EPA issued final amendments to the 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 New 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 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.
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; 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 Rattler LLC considers to be natural gas gathering pipelines, Rattler believes that its 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 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 results of operations and cash flow. In addition, if any of the 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 Rattler 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, there 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, Rattler LLC’s natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Gathering 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 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 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 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, under the 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-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.
We 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, 2020, we had approximately 732 full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also utilize independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full-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 corporate headquarters is located at the Fasken Center in Midland, Texas. We also lease additional office space in Houston, Texas, Midland, Texas and Oklahoma City, Oklahoma.
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 Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
Risk Factors Summary
The following is a summary of the 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 risks summarized in this Risk Factors Summary.
Risks Relating to the Pending Merger and to Diamondback Following the Completion of the Pending Merger
•The pending merger may not be completed and the merger agreement may be terminated in accordance with its terms, which could negatively impact the price of our common 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 result in an injunction preventing the completion of the merger and/or substantial costs to us and QEP.
•We may not achieve the intended benefits of the pending merger or do so within the intended timeframe, and it may not be accretive, and may be dilutive, to our earnings per share.
•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.
•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.
•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 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.
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 and particularly volatility in prices for oil and natural gas may continue to adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
•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 and future production.
•Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings, and title defects in the properties in which we invest may lead to losses.
•Our identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
•Despite our hedging activities, we may be adversely affected by continuing and prolonged declines in the price of oil and may be exposed to other risks, including counterparty credit risk.
•If production from our Permian Basin acreage decreases, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which may adversely affect 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.
•Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
•Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
•We are vulnerable to risks associated with our primary operations concentrated in a single geographic area.
•If transportation or other facilities, certain of which we do not control, or rigs, equipment, raw materials, oil services or personnel are unavailable, our operations could be interrupted and our revenues reduced.
•Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive and may impose restrictions on our operations.
•Recent and future U.S. tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
•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.
•A terrorist attack or armed conflict could harm our business and could adversely affect our business.
•A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
Risks Related to Our Indebtedness
•Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under our indebtedness, and we and our subsidiaries may be able to incur substantial additional indebtedness in the future.
•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.
•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.
•We depend on our subsidiaries for dividends, distributions and other payments.
•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.
•Borrowings under our, Viper LLC’s and Rattler LLC’s revolving credit facilities expose us to interest rate risk.
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’s businesses, 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