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.services.

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, 2020,2021, our total acreage position in the Permian Basin was approximately 449,642524,700 gross (378,678(445,848 net) acres, which consisted primarily of approximately 215,956292,903 gross (194,591(265,562 net) acres in the Midland Basin and approximately 192,697189,357 gross (152,587(148,588 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%54% of the limited partner interestinterests 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%74% of the limited partner interestinterests in Rattler.

As of December 31, 2020,2021, our estimated proved oil and natural gas reserves were 1,316,4411,788,991 MBOE (which includes estimated reserves of 99,392127,888 MBOE attributable to the mineral interests owned by Viper). Of these reserves, approximately 62%67% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 628602 gross (559(533 net) horizontal well locations in which we have a working interest, and 3817 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2020,2021, our estimated proved reserves were approximately 58%52% oil, 22%24% natural gas liquids and 20%24% natural gas.

On March 17, 2021, we acquired QEP Resources, Inc. (”QEP”) in a transaction structured as a merger (the “QEP Merger”). The completionaddition of QEP’s assets increased our net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms 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 theagreement with QEP, we issued approximately 12.12 million shares of our common stock to be issuedthe former QEP stockholders, constituting a total value at the closing date of approximately $987 million.

On October 21, 2021, we completed the divestiture of our Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres acquired in connection with the pending merger, which registration statement was declared effective byQEP Merger, for net cash proceeds of approximately $586 million after customary closing adjustments.

GivenDespite the dynamic nature of the events described above, we cannot reasonably estimate the period of time that the ongoing COVID-19 pandemic, the depressedrecovery in commodity prices the reducedand rising demand, we kept our production relatively flat during 2021, using excess cash flow for oil and the adverse macroeconomic conditions will persist, the full extent of the impact they will have ondebt repayment and/or return to our industry andstockholders rather than expanding our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.drilling program.

Our business strategy is to continue to profitably grow our business throughincludes the following:

We believe that the following strengths will help us achieve our business goals:

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, 2020,2021, our total acreage position in the Permian Basin was approximately 449,642524,700 gross (378,678(445,848 net) acres, which consisted primarily of approximately 215,956292,903 gross (194,591(265,562 net) acres in the Midland Basin and approximately 192,697189,357 gross (152,587(148,588 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 787,264930,871 gross acres and 24,35027,027 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 52%54% 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, 2020:2021:

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, 2020:2021:

Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.

Further, ourOur 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. Rattler’s crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Fivestones areas within the Permian Basin. Rattler’s water sourcing and distribution assets consists of water wells, frac pits, pipelines and water treatment and recycling facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Additionally, Rattler previously owned natural gas gathering assets, substantially all of which were divested in the fourth quarter of 2021. Subsequent to the divestiture of these assets, we utilize third party services and joint ventures in which Rattler owns equity interests discussed below for gathering and transportation of our natural gas production.

As of December 31, 2020,2021, Rattler owned and operated 927866 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our sevennine core Midland and Delaware Basin development areas. To facilitate the transportation of water and hydrocarboncrude oil volumes away from the producing wellhead to ensuringensure 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. 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 substantial acreage dedications.

As of December 31, 2020,2021, Rattler also owned (i) interests in the following investments:

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 BarnettBarnett/Meramec 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, 2020,2021, we held working interests in 4,3265,289 gross (3,401(4,430 net) producing wells and only royalty interests in 4,5536,455 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 3,6104,980 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, 2020,2021, net production from our acreage was 109,921137,002 MBOE, or an average of 300,331375,348 BOE/d, of which approximately 60% was oil, 20% was natural gas liquids and 20% was natural gas.

During 2021,2022, we expect to drill an estimated 270 to 290 gross (248 to 267 net) operated horizontal wells and complete an estimated 215260 to 235280 gross (197(240 to 215258 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2021 for drilling and infrastructure2022 will be between $1.4$1.75 billion and $1.6$1.90 billion, consisting of $1.2$1.56 billion to $1.4$1.67 billion for horizontal drilling and completions including non-operated activity $60and capital workovers, $110 million to $130 million for infrastructure and environmental and $80 million to $100 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, 2020,2021, we drilled 208216 gross (195(203 net) and completed 171275 gross (159(258 net) operated horizontal wells. During the year ended December 31, 2020,2021, our capital expenditures for drilling, completing and equipping wells and infrastructure additions to oil and natural gas properties were $1.6$1.5 billion. In addition, we spent $248$30 million for oil and natural gas midstream and infrastructure.

We were operating eight10 drilling rigs and four completion crews at December 31, 20202021 and currently intend to operate between eight10 and 12 rigs and three and four completion crews on average in 2021.2022. 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.

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2021, 2020 2019 and 20182019 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, 20202021 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%95% 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%5% 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

OurPrior to his retirement effective December 31, 2021, our Executive Vice President–President and Chief Engineer iswas primarily responsible for overseeing the preparation of all our reserve estimates. Our ExecutiveEffective January 1, 2022, our Senior Vice President–Chief Engineer is aPresident of Reservoir Engineering has assumed these responsibilities. We collectively refer to these individuals as the primary reserve engineers. The primary reserve engineers are petroleum engineerengineers with over 30 and 18 years of reservoir and operations experience, respectively, and our geoscience staff has an average of approximately 2015 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:

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2021, 2020 2019 and 20182019 (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, 2020,2021, none of our total proved reserves were classified as proved developed non-producing.

As of December 31, 2020,2021, our proved undeveloped reserves totaled 315,937307,815 MBbls of oil, 522,029815,119 MMcf of natural gas and 96,701144,221 MBbls of natural gas liquids, for a total of 499,643587,889 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The increase in proved undeveloped reserves was primarily attributable to extensions of 220,023416,327 MBOE from 277439 gross (236(383 net) wells in which we have a working interest and 15,68624,700 MBOE from 299336 gross wells in which Viper owns royalty interests. Of the 277439 gross working interest wells, 98409 were in the Midland Basin and 30 were in the Delaware Basin. Transfers of 89,133172,526 MBOE from undeveloped to developed reserves were the result of drilling or participating in 102154 gross (94(142 net) horizontal wells in which we have a working interest and 82127 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 78106 of the 82127 gross Viper wells. Downward revisions of 15,742243,268 MBOE were the result of (i) negative revisions of 4,226260,494 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 fromrelated to changes in the corporate development plan.plan following the QEP Merger and the Guidon Acquisition. These negative revisions were partially

Costs incurred relating to the development of PUDs were approximately $381$516 million during 2020.2021. Estimated future development costs relating to the development of PUDs are projected to be approximately $676 million in 2021, $764$844 million in 2022, $859$1,053 million in 2023, and $531$983 million in 2024.2024 and $381 million in 2025. 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, 2020,2021, we owned an interest in a total of 11,744 gross productive wells with an average unweighted 79%84% working interest in 4,3265,289 gross (3,401(4,430 net) productive wells and an average 1.8%1.7% royalty interest in 4,5536,455 additional wells. Through our subsidiary Viper, we own an average 3.8%3.3% net revenue interest in 7,1679,095 of the total 11,744 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 tables set forth information with respect to the number of wells completeddrilled 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.

As of December 31, 2020,2021, the following gross and net undeveloped acres are set to expire over the next four5 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.