SEC Form 10-K Filing Report

Company: Diamondback Energy, Inc.
CIK: 1539838
SIC Code: 1311
Filing Date: 2022-02-24 00:00:00
Market Capitalization: 22689604.241714478

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ITEM 1. BUSINESS

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ITEM 1A. RISK FACTORS
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 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 and volatility in the oil and natural gas markets. In addition, if commodity prices decrease, our production, estimates of proved reserves and liquidity may be adversely affected.
After turning negative in April 2020, NYMEX WTI prices have recovered, closing at $85.43 per Bbl as of January 18, 2022, as demand for oil and natural gas increased and many restrictions on conducting business implemented in response to the COVID-19 pandemic were lifted due to improved treatments and availability of vaccinations in the U.S. and globally. The emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant, however, contributed to economic and pricing volatility as industry and market participants evaluated industry conditions and production outlook. Despite the recent recovery in demand for oil and natural gas and commodity prices, we have kept production on our acreage relatively flat during 2021, using excess cash flow for debt repayment and/or return to our stockholders rather than expanding our drilling program. We intend to continue exercising capital discipline by maintaining our oil production flat in 2022 at the fourth quarter 2021 level. We cannot reasonably predict whether production levels will remain at current levels or the full extent of the events above and any subsequent recovery may have on our industry and our business.
Due to the improvement in commodity pricing environment and industry conditions, we did not record any impairments in 2021. However, 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. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to conduct additional exploration and development activities.
The ongoing COVID-19 pandemic continues to present operational, health, labor, logistics and other challenges, and it is difficult to assess the ultimate impact of the COVID-19 pandemic on our business, financial condition and cash flows.
There are many variables and uncertainties regarding the COVID-19 pandemic, including the emergence, contagiousness and threat of new and different strains of the virus and their severity; the effectiveness of treatments or vaccines against the virus or its new strains; the extent of travel restrictions, business closures and other measures that are or may be imposed in affected areas or countries by governmental authorities; disruptions in the supply chain; an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic; increased logistics costs; additional costs due to remote working arrangements, adherence to social distancing guidelines and other COVID-19-related challenges. Further, there remain increased risks of cyberattacks on information technology systems used in a remote working environment; increased privacy-related risks due to processing health-related personal information; absence of workforce due to illness; the impact of the pandemic on any of our contractual counterparties; and other factors that are currently unknown or considered immaterial. It is difficult to assess the ultimate impact of the COVID-19 pandemic on our business, financial condition and cash flows.
Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries, including the Middle East, Africa, South
America and Russia; the potential impact of any Russian-Ukrainian conflict on the global energy markets; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; the ability of members of the OPEC+ to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes, including the Biden Administration’s energy and environmental policies; global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19 and its variants; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions. Our results of operations may also be 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.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2021, NYMEX WTI prices ranged from $47.62 to $84.65 per Bbl and the NYMEX Henry Hub price of natural gas ranged from $2.45 to $6.31 per MMBtu. If the prices of oil and natural gas decline, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive and to maintain the production in paying quantities, and if we are unsuccessful in drilling such wells and maintaining such production, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2021, our total capital expenditures, including expenditures for drilling, completion, infrastructure and additions to midstream assets, were approximately $1.5 billion. Our 2022 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $1.75 billion to $1.90 billion, representing an increase of 23% from our 2021 capital expenditures. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.
We intend to finance our future capital expenditures with cash flow from operations, while future acquisitions may also be funded from operations as well as proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including our proved reserves; the volume of oil and natural gas we are able to produce from existing wells; the prices at which our oil and natural gas are sold; our ability to acquire, locate and produce economically new reserves; and our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2022 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements or our costs of capital increase, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs, and potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If these acquisitions include geographic regions in which we do not currently operate, we could be subject to unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
Any of these factors could have a material adverse effect on our financial condition and results of operations. Our financial position and results of operations may also fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.
Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs.
As of December 31, 2021, we have approximately 9,314 gross (6,311 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $50.00 per Bbl WTI. As of December 31, 2021, only 602 of our gross identified economic potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, unusual or unexpected geological formations, title problems, facility or equipment malfunctions, unexpected operational events, inclement weather, environmental and other regulatory requirements and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, as of December 31, 2021, we have identified approximately 2,531 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2021, we are the operator of, have participated in, or have acquired working interest in a total of 2,842 horizontal producing wells completed on our acreage. We cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In order to hold our current leases expiring in 2022, we will need to operate at least a one-rig program. Any non-renewal or other loss of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.
We have entered into commodity price derivatives for a portion of our production. Although we have hedged a portion of our estimated 2022 and 2023 production, we may still be adversely affected by declines in the price of oil and may be exposed to other risks, including counterparty credit risk.
We use commodity price derivatives to reduce price volatility associated with certain of our oil and natural gas sales. To the extent that the prices of oil and natural gas remain at current levels or decline further, we may not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition may be negatively impacted.
At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. We do not require collateral from our counterparties.
For additional information regarding our outstanding derivative contracts as of December 31, 2021, see Note 15-Derivatives to our consolidated financial statements included elsewhere in this report.
If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contracts, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.
We are a party to long-term crude oil agreements under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to our counterparties. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions beyond our control. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.
The inability of one or more of our customers to meet their obligations may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $72 million at December 31, 2021) and receivables from purchasers of our oil and natural gas production (approximately $598 million at December 31, 2021). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.
We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See “Business and Properties-Oil and Natural Gas Production Prices and Production Costs-Marketing and Customers” for additional information regarding these customers. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic and other conditions. We do not require our customers to post collateral. Under certain circumstances, the revenue due to them can be offset by any unpaid receivables. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.
Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment.
The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.
No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2021. Impairments of proved oil and natural gas properties of $6.0 billion and $0.8 billion were recorded for the years ended December 31, 2020 and 2019.
Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.
The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.
The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.
Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 33% of our total estimated proved reserves as of December 31, 2021, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling and completion operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.
Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids and extreme weather conditions, such as the severe winter storms in the Permian Basin in February 2021, and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
In addition to the geographic concentration of our producing properties described above, as of December 31, 2021, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Business and Properties-Oil and Natural Gas Production Prices and Production Costs-Marketing and Customers” for additional information regarding these customers. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operators of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water
districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
Recent regulatory restrictions on use of produced water and a moratorium on new produced water disposal wells in the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.
In September 2021, the Texas Railroad Commission curtailed the amount of produced water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oil fields. These restrictions on the disposal of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.
We have incurred losses from operations during certain periods since our inception and may do so in the future.
Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operations involve developing and utilizing the latest drilling and completion techniques. Risks that we face while drilling include, but are not limited to, the following:
•spacing of wells to maximize economic return;
•landing our well bore in the desired drilling zone;
•staying in the desired drilling zone while drilling horizontally through the formation;
•running our casing the entire length of the well bore; and
•being able to run tools and other equipment consistently through the horizontal well bore.
Risks that we face while completing our wells include, but are not limited to, being able to:
•fracture stimulate the planned number of stages;
•run tools the entire length of the well bore during completion operations;
•successfully clean out the well bore after completion of the final fracture stimulation stage; and
•prevent unintentional communication with other wells.
Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we
anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering line, which interconnects with third party pipelines. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with a purchaser or into a third-party gathering system. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Further, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business-Regulation” for a detailed description of certain laws and regulations that affect us.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may
lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act, which we refer to as Dodd-Frank Act, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission, which we refer to as the CFTC, the SEC, and federal regulators of financial institutions, which we refer to as the Prudential Regulators, adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we refer to as the Mandatory Clearing Rule, requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps), a rule, which we refer to as the End User Exception, establishing an “end user” exception to the Mandatory Clearing Rule, a rule, which we refer to as the Margin Rule, setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the Non-Financial End User Exception, and a rule imposing position limits, which we refer to as the Position Limit Rule, and also an exception to the Position Limit Rule for swaps that constitute a “bona fide hedging transaction or position” within the definition of such term under the Position Limit Rule, subject to the party claiming the exemption complying with the applicable filing, recordkeeping and reporting requirements of the Position Limit Rule, which we refer to as the Bona Fide Hedging Exception.
We qualify for the End User Exception to the Mandatory Clearing Rule, we qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule, and each of our existing and anticipated hedging positions constitutes a “bona fide hedging transaction or position” under the Position Limit Rule and we intend to undertake the filing, recordkeeping and reporting necessary to utilize the Bona Fide Hedging Exception under the Position Limit Rule, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (including laws and regulations giving the European Union financial authorities the power to write-down amounts we may be owed on hedging agreements with counterparties subject to such laws and regulations and/or require that we accept equity interests in such counterparties in lieu of cash in satisfaction of such amounts), which we refer to collectively as Foreign Regulations, which may apply to our transactions with counterparties subject to such Foreign Regulations, which we refer to as Foreign Counterparties, and the U.S. adopted law and rules, which we call the U.S. Resolution Stay Rules, clarifying similar rights of U.S. banking authorities with respect to banking institutions subject to their regulation. The Dodd-Frank Act, the rules which have been adopted and not vacated, the Limit Rule and the U.S. Resolution Stay Rules could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulation, the U.S. Resolution Stay Rules and Foreign Regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
Future U.S. tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.
We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We do not have employment agreements with our executives and may not be able to assure their retention. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.
We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements
with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are part of our operations, we maintain insurance to protect against claims made for bodily injury and property damage, and that insurance includes coverage for clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have limited coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Changes in environmental laws could increase our operating costs and adversely impact our business, financial condition and cash flows.
President Biden has indicated that he is supportive of, and has issued executive orders promoting, various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and decarbonize electric generation and the transportation sector. It remains unclear what additional actions President Biden will take and what support he will have for any potential legislative changes from Congress. Further, it is uncertain to what extent any new environmental laws or regulations, or any repeal of existing environmental laws or regulations, may affect our business or operations. However, such actions could significantly increase our operating costs or impair our ability to explore and develop other projects, which could adversely impact our business, financial condition and cash flows.
Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.
We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing
and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
Risks Related to Our Indebtedness
References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback E&P LLC, collectively, unless otherwise specified.
We have relied in the past, and we may rely from time to time in the future, on borrowings under our revolving credit facility to fund a portion of our capital expenditures. Unless we are able to repay borrowings under the revolving credit facility with cash flow from operations and proceeds from equity or debt offerings, implementing our capital programs may require an increase in our total leverage through additional debt issuances. In addition, a reduction in availability under our revolving credit facility and the inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.
We have historically relied on availability under our revolving credit facility to fund a portion of our capital expenditures. We expect that we will continue to fund a portion of our capital expenditures with borrowings under the revolving credit facility, cash flow from operations and the proceeds from debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from debt or equity offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. Instead, we may be required or choose to finance our capital expenditures through additional debt issuances, which would increase our total amount of debt outstanding. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could limit our ability to fund our drilling activities and acquisitions or otherwise finance the capital expenditures necessary to replace our reserves.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.
Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create liens; sell or transfer assets; issue preferred stock; merge or consolidate with another entity; pay dividends or make other distributions; create unrestricted subsidiaries; and engage in transactions with affiliates.
Under our revolving credit facility we are allowed, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under our revolving credit facility, we designated Viper, Viper’s general partner, Viper’s subsidiary, Rattler, Rattler’s general partner and Rattler’s subsidiaries as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the revolving credit facility, including the related guaranty. Further Viper, Viper’s general partner, Viper’s subsidiaries, Rattler, Rattler’s general partner and Rattler’s subsidiaries are designated as unrestricted subsidiaries under the indentures governing our outstanding Senior Notes.
We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our and our subsidiaries’ debt instruments. As an example, our revolving credit facility requires us to maintain a total net debt to capitalization ratio. The requirement that we and our subsidiaries comply with these provisions may materially adversely affect our and our subsidiaries ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
A breach of any of these restrictive covenants could result in default under the applicable debt instrument. If default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.
Our indebtedness is structurally subordinated to the indebtedness and other liabilities of our subsidiaries, and our obligations are not obligations of any of our subsidiaries.
Our senior indebtedness obligations are obligations exclusively of Diamondback Energy, Inc. and Diamondback E&P LLC, and not of any of our other subsidiaries. None of our other subsidiaries is a guarantor of our senior indebtedness. Any assets of those subsidiaries will not be directly available to satisfy the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes. Except to the extent we are a creditor with recognized claims against our subsidiaries, all claims of creditors of our subsidiaries will have priority over our equity interests in such subsidiaries (and therefore the claims of our creditors, including lenders under our revolving credit facility and holders of the senior notes) with respect to the assets of such subsidiaries. Even if we are recognized as a creditor of one or more of our subsidiaries, our claims would still be effectively subordinated to any security interests in the assets of any such subsidiary and to any indebtedness or other liabilities of any such subsidiary senior to our claims. Consequently, our senior indebtedness will be structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries (other than Diamondback E&P LLC) and any subsidiaries that we may in the future acquire or establish. For additional information regarding our subsidiaries outstanding debt as of December 31, 2021, see Note 11-Debt to our consolidated financial statements included elsewhere in this report.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. If we are unable to generate sufficient cash flow to service our debt, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due.
Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
We depend on our subsidiaries for dividends, distributions and other payments.
We depend on our subsidiaries for dividends, distributions and other payments. We are a legal entity separate and distinct from our operating subsidiaries. There are statutory and regulatory limitations on the payment of dividends or distributions by certain of our subsidiaries to us. If our subsidiaries are unable to make dividend or distribution payments to us and sufficient cash or liquidity is not otherwise available, we may not be able to make dividend payments to our stockholders or principal and interest payments on our outstanding indebtedness.
We and our subsidiaries may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our and our subsidiaries’ revolving credit facilities and the indentures restrict, but in each case do not completely prohibit, us from doing so. Further, the indentures governing our and our subsidiaries’ notes allow us to issue additional notes, incur certain other additional debt and to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Borrowings under our, Viper LLC’s and Rattler LLC’s revolving credit facilities expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our and our subsidiaries’ revolving credit facilities. The terms of our and our subsidiaries’ revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate tied to LIBOR. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve, which indicated plans for multiple interest rate increases in 2022, and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. From time to time, we use interest rate swaps to reduce interest rate exposure with respect to our fixed and/or floating rate debt. Our weighted average interest rate on borrowings under our revolving credit facility was 1.67% during the year ended December 31, 2021. Viper LLC’s weighted average interest rate on borrowings from its revolving credit facility was 2.35% during the year ended December 31, 2021. Rattler LLC’s weighted average interest rate on borrowings from its revolving credit facility was 1.41% during the year ended December 31, 2021. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR), which we refer to as the FCA, announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. On March 5, 2021, the ICE Benchmark Administration, which administers LIBOR, and the FCA announced that all LIBOR settings will either cease to be provided by any administrator, or no longer be representative immediately after 2021, for all non-U.S. dollar LIBOR settings and one-week and two-month U.S. dollar LIBOR settings, and immediately after June 30, 2023 for the remaining U.S. dollar LIBOR settings. In light of these recent announcements, the future of LIBOR at this time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phase-out could cause LIBOR to perform differently than in the past or cease to exist. Our current credit agreement provides for any
changes away from LIBOR to a successor rate to be based on prevailing or equivalent standards, however, changes in the method of calculating LIBOR, or the discontinuation, reform, or replacement of LIBOR or any other benchmark rates may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect our results of operations, cash flow and liquidity.
Risks Related to Our Common Stock
The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
Subject to the limitations of applicable law, our certificate of incorporation, among other things; permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested; permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.
If the price of our common stock fluctuates significantly, your investment could lose value.
Although our common stock is listed on the Nasdaq Global Select Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including our quarterly or annual operating results; changes in our earnings estimates; investment recommendations by securities analysts following our business or our industry; additions or departures of key personnel; changes in the business, earnings estimates or market perceptions of our competitors; our failure to achieve operating results consistent with securities analysts’ projections; changes in industry, general market or economic conditions; and announcements of legislative or regulatory changes.
The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.
The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
On February 13, 2018, we initiated payment of quarterly cash dividends on our common stock payable beginning with the first quarter of 2018. The decision to pay any future dividends, however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.
In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock, of which $431 million had been repurchased through December 31, 2021. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.
A change of control could limit our use of net operating losses and certain other tax attributes.
Under Section 382 of the Code, a corporation that experiences an “ownership change” (as defined in the Code) may be subject to limitations on its ability to offset taxable income arising after the ownership change with net operating losses (“NOLs”) or tax credits generated prior to the ownership change. In general, an ownership change occurs if there is a cumulative increase in the ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. An ownership change would establish an annual limitation on the amount of a corporation’s pre-change NOLs or tax credits that could be utilized to offset taxable income in any future taxable year. The amount of the limitation is generally equal to the value of the corporation’s stock immediately prior to the ownership change multiplied by an interest rate, referred to as the long-term tax-exempt rate, periodically promulgated by the IRS. This limitation, however, may be significantly increased if there is “net unrealized built-in gain” in the assets of the corporation undergoing the ownership change.
As of December 31, 2021, we had an NOL carryforward of approximately $2.5 billion and tax credits of $4 million for federal income tax purposes. Due to an ownership change on March 17, 2021 in conjunction with our acquisition of QEP in an all-stock transaction, our NOLs and tax credits, including those acquired from QEP, are subject to an annual limitation under Section 382 of the Code. However, we have determined that our fair market value and our net unrealized built-in gain position resulted in a significant increase in our Section 382 limitation. Accordingly, we believe that the application of Section 382 as a result of this ownership change will not have an adverse effect on our ability to utilize our NOLs and credits.
Future changes in our stock ownership, however, could result in an additional ownership change under Section 382 of the Code. Any such ownership change may limit our ability to offset taxable income arising after such an ownership change with NOLs or other tax attributes generated prior to such an ownership change, possibly substantially.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrade our stock or if our operating results do not meet their expectations, our stock price could decline.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of our company, which could adversely affect the price of our common stock.
The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders; limitations on the ability of our stockholders to call a special meeting and act by written consent; the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws; the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors; the requirement that
the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.
These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows. For additional information regarding contingencies, see Note 18-Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Annual Report.

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ITEM 4. RESERVED
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Listing and Holders of Record
Our common stock is listed on the Nasdaq Global Select Market under the symbol “FANG”. There were 5,624 holders of record of our common stock on February 18, 2022.
Dividend Policy
The Company’s board of directors has authority to declare dividends to the holders of the Company’s common stock. The board of directors intends to continue the payment of dividends to the holders of the Company’s common stock in the future. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended December 31, 2021 was as follows:
(1)Includes 2,308 shares of common stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.
(2)The average price paid per share includes any commissions paid to repurchase stock.
(3)In September 2021, the Company’s board of directors authorized a $2 billion common stock repurchase program. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED.]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
Overview
We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. We operate in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.
We operate under a strategic approach that focuses predominantly on enhancing return through our low-cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. We are also committed to delivering results in a socially and environmentally responsible manner.
2021 Financial and Operating Highlights
•We recorded net income of $2.2 billion for the year ended December 31, 2021.
•Our average production was 137,002 MBOE/d during the year ended December 31, 2021.
•During the year ended December 31, 2021, we drilled 175 gross horizontal wells in the Midland Basin and 41 gross horizontal wells in the Delaware Basin.
•We turned 275 gross operated horizontal wells (including 207 in the Midland Basin and 64 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $1.5 billion during the year ended December 31, 2021.
•The average lateral length for the wells completed during the year ended December 31, 2021 was 10,602 feet.
•As of December 31, 2021, we had approximately 445,848 net acres, which primarily consisted of approximately 265,562 net acres in the Midland Basin and approximately 148,588 net acres in the Delaware Basin. As of December 31, 2021, we had an estimated 9,314 gross horizontal locations that we believe to be economic at $50.00 per Bbl WTI. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 930,871 gross acres and 27,027 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 54% of these net royalty acres are operated by us.
•Our cash operating costs for the year ended December 31, 2021 were $9.46 per BOE, including lease operating expenses of $4.12 per BOE, cash general and administrative expenses of $0.69 per BOE and production and ad valorem taxes and gathering and transportation expenses of 4.65 per BOE.
2021 Transactions and Recent Developments
2021 Acquisition Activity and Recent Transactions
On February 26, 2021, we completed the Guidon Acquisition, which included approximately 32,500 net acres in the Northern Midland Basin, in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash.
On March 17, 2021, we completed the QEP Merger. The addition of QEP’s assets increased our net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the merger agreement, we issued approximately 12.12 million shares of our common stock to the former QEP stockholders, with a total value of approximately $987 million on the closing date.
On October 1, 2021, Viper completed the acquisition of certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) which included certain mineral and royalty interests for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The cash portion of the purchase price was funded through a combination of cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.
On October 5, 2021, Rattler and a private affiliate of an investment fund formed a joint venture entity, Remuda Midstream Holdings LLC (the “WTG joint venture”). Rattler contributed approximately $104 million in cash for a 25% membership interest in the WTG joint venture, which then completed the acquisition of a majority interest in WTG Midstream LLC (“WTG Midstream”).
2021 Divestiture Activity
On June 3, 2021 and June 7, 2021, respectively, we closed transactions to divest certain non-core Permian assets, including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county, Texas and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico, for combined net cash proceeds of $82 million, after customary closing adjustments. We used our net proceeds from these transactions toward debt reduction.
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 the QEP Merger, for net cash proceeds of approximately $586 million after customary closing adjustments. We used our net proceeds from this transaction toward debt reduction.
On November 1, 2021, we completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC, which we refer to as Brazos, for net cash proceeds of approximately $54 million, after customary closing adjustments.
On December 1, 2021, we completed the sale of certain water midstream assets with a carrying value of approximately $160 million to Rattler in exchange for cash proceeds of approximately $160 million.
On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for net cash proceeds of approximately $83 million at closing, after customary closing adjustments, and an aggregate of $10 million in contingent payments.
See Note 4-Acquisitions and Divestitures for additional discussion of these transactions.
Debt Transactions
Issuances of Notes
On March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregate principal amount of 0.900% Senior Notes due March 24, 2023 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes”) and received proceeds, net of $24 million in debt issuance costs and discounts, of $2.18 billion. The net proceeds were primarily used to fund the redemption of other senior notes outstanding as discussed further below.
Redemption of Notes
The net proceeds from the March 2021 Notes discussed above were primarily used to fund the repurchase of $1.65 billion in fair value carrying amount of the QEP Notes that remained outstanding at the effective time of the QEP Merger for total cash consideration of $1.7 billion, and $368 million principal amount of 2025 Senior Notes, for total cash consideration of $381 million. Giving effect to the repurchase of the 2023 Notes discussed below, these refinancing transactions are expected to result in an estimated annual interest cost savings of approximately $40 million in addition to an estimated $60 to $80 million of previously announced expected annual cost synergies from the QEP Merger.
In June 2021, we redeemed the remaining $191 million principal amount of outstanding legacy 4.625% senior notes due September 1, 2021 of Energen Corporation (“Energen”).
In August 2021 we redeemed the remaining $432 million principal amount of our outstanding 5.375% 2025 Senior Notes at a redemption price equal to 102.688% of the principal amount plus accrued interest. We funded the redemption with cash on hand and borrowings under our revolving credit facility.
On November 1, 2021, we redeemed the aggregate $650 million principal amount of our outstanding 2023 Notes with the proceeds received from the divestiture of our Williston Basin assets and cash on hand.
For additional discussion of our 2021 debt transactions and the amendment to the second amended and restated credit facility, see Note 11-Debt.
Fourth Quarter 2021 Dividend Declaration and Increase
On February 18, 2022, our board of directors declared a cash dividend for the fourth quarter of 2021 of $0.60 per share of common stock, payable on March 11, 2022 to our stockholders of record at the close of business on March 4, 2022, representing a 20% increase per share from the previously paid quarterly dividend.
Stock and Unit Repurchase Programs
During the year ended December 31, 2021, we repurchased approximately $431 million of Diamondback common stock, and as of December 31, 2021, $1.6 billion remained available for future purchases under our common stock repurchase program.
During the year ended December 31, 2021, Viper repurchased approximately $46 million of common units under its repurchase program. As of December 31, 2021, $80 million remained available for use to repurchase common units under Viper’s common unit repurchase program.
During the year ended December 31, 2021, Rattler repurchased approximately $48 million of common units under its repurchase program. As of December 31, 2021, $88 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.
See “-Liquidity and Capital Resources” below for additional discussion.
COVID-19 and Effects on Commodity Prices
In early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the COVID-19 pandemic. Demand for oil and natural gas increased during 2021, as many restrictions on conducting business implemented in response to the COVID-19 pandemic were lifted due to improved treatments and availability of vaccinations in the U.S. and globally. As a result, oil and natural gas market prices have improved during 2021 in response to the increase in demand. During 2021 and 2020, the posted price for West Texas intermediate light sweet crude oil, or NYMEX WTI, has ranged from $(37.63) to $84.65 Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.48 to $6.31 per MMBtu. On January 18, 2022, the closing NYMEX WTI price for crude oil was $85.43 per Bbl and the closing NYMEX Henry Hub price of natural gas was $4.28 per MMBtu. The emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant, however, contributed to economic and pricing volatility as industry and market participants evaluated industry conditions and production outlook. Further, on January 4, 2021, OPEC and its non-OPEC allies, known collectively as OPEC+, agreed to continue their program (commenced in August of 2021) of gradual monthly output increases in February 2022, raising its output target by 400,000 Bbls per day, which is expected to further boost oil supply in response to rising demand. In its report issued on February 10, 2022, OPEC noted its expectation that world oil demand will rise by 4.15 million Bbls per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in February 2022, we cannot predict any future volatility in commodity prices or demand for crude oil.
Despite the recovery in commodity prices and rising demand, we kept our production relatively flat during 2021, using excess cash flow for debt repayment and/or return to our stockholders rather than expanding our drilling program.
Outlook
During 2021, we continued building on our execution track record, generating free cash flow while keeping capital costs under control, and our efficiency gains, particularly in the Midland Basin drilling and completion programs, were able to mitigate certain inflationary pressures on well costs and led to a total capital expenditure amount of $1.5 billion down 11% from our guidance presented in April of 2021. We expect to continue to build on these operational efficiencies by controlling the variable portion of our operating and capital costs, which we believe will help mitigate the inflationary pressures seen across our business. We remain committed to capital discipline by maintaining flat oil production in 2022 and expect to maintain our best-in-class capital efficiency and cost structure. We expect to be in a position to continue to deliver on the recently announced enhanced capital return program, where we expect to distribute at least 50% of our quarterly free cash flow to our stockholders. Our capital return program is currently focused on our sustainable and growing dividend and a combination of stock repurchases and variable dividends. We expect to remain flexible on returning capital to our stockholders, depending on which method our board of directors believes presents the best return of capital to our stockholders at the relevant time.
In the Midland Basin, we continued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations.
In the Delaware Basin, we have now drilled and completed a significant number of wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2022, we expect to focus development on these areas.
As of December 31, 2021, we were operating 10 drilling rigs and four completion crews and currently intend to operate between 10 and 12 drilling rigs and between three and four completion crews in 2022 on average across our current acreage position in the Midland and Delaware Basins.
Environmental Responsibility Initiatives and Highlights
In February 2021, we announced significant enhancements to our commitment to environmental, social responsibility and governance, or ESG, performance and disclosure, including Scope 1 and methane emission intensity reduction targets. Our goals include the reduction of our Scope 1 greenhouse gas intensity by at least 50% and methane intensity by at least 70%, in each case by 2024 from the 2019 levels. To further underscore our commitment to carbon neutrality, we have also implemented our “Net Zero Now” initiative under which, effective January 1, 2021, we strive to produce every hydrocarbon molecule with zero Scope 1 emissions. To the extent our greenhouse gas and methane intensity targets do not eliminate our carbon footprint, we have purchased carbon credits to offset the remaining emissions. We have also increased the weighting of ESG metrics in our annual short-term incentive compensation plan to motivate our executives to advance our environmental responsibility goals.
In September 2021, we announced our long-term goal to end routine flaring by 2025 and a long-term target to source over 65% of our water used for drilling and completion operations from recycled sources by 2025. With respect to flaring, we flared 1.55% of our gross natural gas production in the fourth quarter of 2021. For the full year ended 2021, we flared 1.45% of our gross natural gas production, down 26% from 2020.
2022 Capital Budget
We have currently budgeted 2022 total capital spend of $1.75 billion to $1.90 billion. Should commodity prices weaken, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to maintain flat oil production, pay down indebtedness and return cash to our stockholders.
Results of Operations
The following discussion focuses primarily on a comparison of the results of operations between the years ended December 31, 2021 and 2020. The midstream operations segment’s revenues and operating expenses were not significant to our consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019. .For a discussion of the results of operations for the year ended December 31, 2020 as compared to the year ended December 31, 2019, please refer to “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2020 (filed with the SEC on February 25, 2021), which is incorporated in this report by reference from such prior report on Form 10-K.
The following table sets forth selected historical operating data for the periods indicated:
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables provides information on the mix of our production for the years ended December 31, 2021 and 2020:
Comparison of the Years Ended December 31, 2021 and 2020
Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.
Our oil, natural gas and natural gas liquids revenues increased by approximately $4.0 billion, or 145%, to $6.7 billion for the year ended December 31, 2021 from $2.8 billion for the year ended December 31, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $3.3 billion of the total increase. The remainder of the overall change is due to a 25% increase in combined volumes sold.
Higher commodity prices during 2021 compared to 2020 primarily reflect a recovery from historically low prices experienced in 2020 due to the COVID-19 pandemic as discussed in “-2021 Transactions and Recent Developments” above. The increase in production for 2021 compared to 2020 resulted primarily from the Guidon Acquisition and QEP Merger during the first quarter of 2021 and an overall recovery in our drilling and production activities after curtailments in the second quarter of 2020 in response to the COVID-19 pandemic. We expect to hold our oil production levels flat during 2022.
Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2021 and 2020:
Lease operating expenses for the year ended December 31, 2021 as compared to the year ended December 31, 2020 increased by $140 million, or $0.25 per BOE, primarily due to an increase in production between periods driven by the Guidon Acquisition and the QEP Merger in the first quarter of 2021. The increase on a per BOE basis is primarily related to the Williston Basin assets acquired in the QEP Merger which had higher lease operating costs per BOE on average than our historical properties. We completed the divestiture of the Williston Basin properties in October 2021.
Including the impact of our acquisition and divestiture activity in 2021 and future production plans, our total lease operating expenses in 2022 are expected to range from approximately $539 million to $618 million.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2021 and 2020:
In general, production taxes are directly related to production revenues. Production taxes for the year ended December 31, 2021 increased by $214 million, or $1.32 per BOE. The increase in production taxes is attributable to an increase in commodity prices, as well as an increase in overall production due to assets acquired in 2021. The current year increase on a per BOE basis is primarily driven by an increase in current year commodity prices. Production taxes as a percentage of production revenues increased for the year ended December 31, 2021 compared to the year ended December 31, 2020 due primarily to the acquired Williston Basin properties which have a higher production tax rate than our other properties. We completed the divestiture of the Williston Basin properties in October 2021.
Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the year ended December 31, 2021 as compared to the year ended December 31, 2020 increased by $16 million primarily due to additional properties acquired in the Guidon Acquisition and the QEP Merger.
We expect production taxes to be approximately between 7% and 8% of oil, natural gas and natural gas liquids revenue during 2022.
Gathering and Transportation Expense. The following table shows gathering and transportation expense for the year ended December 31, 2021 and 2020:
For the year ended December 31, 2021, the increase for gathering and transportation expenses are primarily attributable to the increase in production between periods. The current year increase on a per BOE basis is primarily driven by production added from the assets acquired in the QEP Merger which, in general, had higher average gathering and transportation costs per BOE than our historical properties, particularly those QEP assets located in the Williston Basin, which we divested in the fourth quarter of 2021. After giving effect to the 2021 acquisition and divestiture activities, we expect gathering and transportation expenses to range from approximately $212 to $243 million in 2022.
Midstream Services Expense. The following table shows midstream services expense for the years ended December 31, 2021 and 2020:
Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities. In the fourth quarter of 2021, we and Rattler divested our natural gas gathering and transportation assets. Midstream services expense for the year ended December 31, 2021 as compared to the year ended December 31, 2020 decreased by $16 million primarily due to decreased maintenance costs, partially offset by increased fees for use of third party disposal systems.
Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion and amortization expense for the years ended December 31, 2021 and 2020:
The decrease in depletion of proved oil and natural gas properties of $40 million for the year ended December 31, 2021 as compared to the year ended December 31, 2020 resulted primarily from a reduction in the average depletion rate partially offset by increased production in 2021. The decline in rate resulted primarily from higher SEC oil prices utilized in the reserve calculations during 2021, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.
Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the year ended December 31, 2021. In connection with the QEP Merger and the Guidon Acquisition, we recorded the oil and natural gas properties acquired at fair value. Pursuant to SEC guidance, we determined the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, we requested and received a waiver from the SEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had we not received the waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded in the first quarter of 2021. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.
As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the year ended December 31, 2020 of $6.0 billion which is included in accumulated depletion, depreciation, amortization and impairment on our consolidated balance sheet. Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 8-Property and Equipment for further details regarding factors that impact the impairment of oil and natural gas properties.
General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2021 and 2020:
General and administrative expenses for the year ended December 31, 2021 as compared to the year ended December 31, 2020 increased by $58 million primarily due to additional payroll and other employee driven costs of $32 million related to the QEP Merger and the Guidon Acquisition as well as $10 million of additional expense related to the implementation of a new enterprise resource planning system. Additionally, equity compensation for the year ended December 31, 2021 increased by $14 million compared to the same period in 2020.
We expect cash general and administrative expenses to range from approximately $87 million to $110 million in 2022, and non-cash stock-based compensation to range from approximately $54 million to $69 million in 2022.
Merger and Integration Expense. The following table shows merger and integration expense for the years ended December 31, 2021 and 2020:
Total merger and integration expense for the year ended December 31, 2021 includes $69 million in costs incurred for the QEP Merger and $9 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of $39 million in severance costs and $30 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory and legal fees. See Note 4-Acquisitions and Divestitures for further details regarding the QEP Merger and the Guidon Acquisition.
Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2021 and 2020:
Net interest expense increased by $2 million for the year ended December 31, 2021 as compared to the year ended December 31, 2020. This increase primarily consisted of (i) $47 million in interest costs on the newly issued March 2021 Notes (ii) $25 million due to incurring a full year of interest expense in 2021 related to our May 2020 Notes and Rattler’s 5.625% Senior Notes due 2025, and (iii) to a lesser extent, interest expense incurred on the QEP Notes that remained outstanding following the QEP Merger completed in March 2021. These increases were partially offset by (i) $33 million in additional capitalized interest costs, (ii) interest cost savings of $23 million on the repurchases of our 2025 Senior Notes in March 2021 and August 2021, (iii) $8 million on the repurchase of our 4.625% senior notes of Energen (iv) a $9 million reduction in borrowings under our revolving credit agreements during 2021, and (v) to a lesser extent, interest savings on the repurchase of our 2023 Notes in November 2021. We expect interest expense, net of interest income to range from approximately $148 million to $178 million in 2022. See Note 11-Debt for further details regarding outstanding borrowings and interest expense.
Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2021 and 2020:
(1)The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million.
(2)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.
(3)The year ended December 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.
We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our commodity derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” As part of the QEP Merger, we received by novation from QEP certain derivative instruments which are included on our balance sheet as of December 31, 2021.
We have designated certain of our interest rate swaps as fair value hedges for accounting purposes. As a result, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and no gain or loss is recognized due to hedge effectiveness. Changes in fair value are recorded as an adjustment to the carrying value of the 2029 Notes in the consolidated balance sheet. Beginning on December 1, 2021, we began recording semi-annual cash settlements of these interest rate swaps in interest expense in the consolidated statements of operations.
At December 31, 2021, we have a short-term derivative asset of $13 million, a long-term derivative asset of $4 million, a short-term derivative liability due in 2022 of $174 million and a long-term derivative liability due in 2023 of $29 million.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2021 and 2020:
The changes in our income tax provision for the year ended December 31, 2021 compared to the same period in 2020 were primarily due to the increase in pre-tax income for the year ended December 31, 2021.
Liquidity and Capital Resources
Overview of Sources and Uses of Cash
Historically, our primary sources of liquidity include cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. At December 31, 2021, we had approximately $2.2 billion of liquidity consisting of $0.7 billion in cash and cash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2022 is $1.75 billion to $1.90 billion. Further, we have $45 million of senior notes maturities in the next 12 months.
Our working capital requirements are supported by our cash and cash equivalents and our credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, debt service obligations and repayment of debt maturities, stock repurchase program and other amounts that may ultimately be paid in connection with contingencies.
Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. In order to mitigate this volatility, we entered into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, hedging a portion of our estimated future crude oil and natural gas production through the end of 2023 as discussed further in Note 15-Derivatives and

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years. Although demand and market prices for oil and natural gas have recently increased substantially due to rising energy use, easing of the COVID-19 pandemic restrictions, availability of treatments and vaccines in the U.S. and globally and improvements in the U.S. and global economic activity, we cannot predict events that may lead to future commodity price volatility. Further, the prices we receive for production depend on many other factors outside of our control.
We use derivatives, including swaps, basis swaps, swaptions, roll hedges, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil and natural gas sales.
At December 31, 2021, we had a net liability derivative position of $168 million related to our commodity price derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of December 31, 2021, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position by $149 million to $317 million, while a 10% decrease in forward curves associated with the underlying commodity would have reduced the net liability derivative position by $117 million to $51 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.
In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.
For additional information on our open commodity derivative instruments at December 31, 2021, see Note 15-Derivatives.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $598 million at December 31, 2021), and to a lesser extent, receivables resulting from joint interest receivables (approximately $72 million at December 31, 2021).
We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results.
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities and changes in the fair value of our fixed-rate debt. The terms of our credit agreement provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.125% per annum in the case of the alternative base rate and from 1.25% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level. The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecure debt. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows. For additional information on our variable interest rate debt at December 31, 2021, see Note 11-Debt.
Historically, we have at times used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility and changes in the fair value of our fixed-rate debt. At December 31, 2021, we have interest rate swap agreements for a notional amount of $1.2 billion to manage the impact of market interest rates on the fair value of our fixed-rate debt. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 whereby we will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. For additional information on our interest rate swaps, see Note 15-Derivatives.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page of this report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures
Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of December 31, 2021, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2021, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting
In July 2021, we implemented an enterprise resource planning system covering various financial and accounting processes. As a result of this implementation, certain internal controls over financial reporting have been automated, modified or implemented to address the new environment associated with the implementation of this system. We believe we have maintained appropriate internal control over financial reporting during the implementation and believe this new system will strengthen our internal control system. However, there are inherent risks in implementing any new system, and we will continue to evaluate these control changes as part of our assessment of internal control over financial reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2021.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2021. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2021, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Diamondback Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2021, and our report dated February 24, 2022 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 24, 2022

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
Effective February 21, 2022, our board of directors promoted Kaes Van’t Hof, then our Chief Financial Officer and Executive Vice President-Business Development to the role of our President. In addition to his role as our President, Mr. Van’t Hof will continue to serve as our Chief Financial Officer. Also, effective February 21, 2022, our board of directors promoted Daniel N. Wesson, then our Executive Vice President-Operations, to the role of our Chief Operating Officer. In addition to his role as our Chief Operating Officer, Mr. Wesson will continue to serve as our Executive Vice President.
Mr. Van’t Hof’s and Mr. Wesson’s full biographies and, to the extent applicable, the information required by Item 404(a) of Regulation S-K, are included in our definitive proxy statement on Schedule 14A, filed by us with the SEC on April 23, 2021, which we refer to as our 2021 proxy statement. Each of Mr. Van’t Hof and Mr. Wesson was named as our named executive officer in our 2021 proxy statement.
In connection with these promotions, the compensation committee of our board of directors approved increases in Mr. Van’t Hof’s and Mr. Wesson’s annual base salaries to $625,000 and $560,000, respectively. In addition, the compensation committee also approved annual long-term equity incentive compensation awards with an intended grant date value of $3,750,000 for Mr. Van’t Hof and $2,250,000 for Mr. Wesson to be granted under our equity incentive plan and represented by a combination of performance-based and time-based restricted stock units, vesting over applicable performance or service periods.
These executives will continue to participate in our annual executive cash incentive plan, which provides an opportunity to receive an annual bonus payable in a single lump sum, based on a target percentage of these executives’ respective annual base salaries and such performance goals and criteria as determined in the discretion of the compensation committee of our board of directors, as well as in other employee benefit plans generally available to similarly situated employees, as in effect from time to time, a description of which is included in our 2021 proxy statement.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
PART III

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.
We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section at http://ir.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.

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ITEM 12. SECURITY OWNERSHIP
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2021.
PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
_______________
*
Filed herewith.
**
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
+
Management contract, compensatory plan or arrangement.
#
The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DIAMONDBACK ENERGY, INC.
Date: February 24, 2022
/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ Travis D. Stice Chairman of the Board, Chief Executive Officer and Director February 24, 2022
Travis D. Stice (Principal Executive Officer)
/s/ Vincent K. Brooks Director February 24, 2022
Vincent K. Brooks
/s/ Michael P. Cross Director February 24, 2022
Michael P. Cross
/s/ David L. Houston Director February 24, 2022
David L. Houston
/s/ Stephanie K. Mains Director February 24, 2022
Stephanie K. Mains
/s/ Mark L. Plaumann Director February 24, 2022
Mark L. Plaumann
/s/ Melanie M. Trent Director February 24, 2022
Melanie M. Trent
/s/ Steven E. West Director February 24, 2022
Steven E. West
/s/ Kaes Van’t Hof President and Chief Financial Officer February 24, 2022
Kaes Van’t Hof (Principal Financial Officer)
/s/ Teresa L. Dick Chief Accounting Officer, Executive Vice President and Assistant Secretary February 24, 2022
Teresa L. Dick (Principal Accounting Officer)
S-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Diamondback Energy, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 24, 2022 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of proved reserves as it relates to the calculation and recognition of depletion expense, the evaluation of impairment, and the valuation of oil and gas properties in the Guidon Acquisition and QEP Merger
As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues to record depletion expense and measure its oil and gas properties for potential impairment. Additionally, as described in Note 4 to the financial statements, the Company acquired significant oil and gas properties during the year through the Guidon Acquisition and QEP Merger. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. Management also utilizes an estimated fair value pricing model for the valuation of acquired proved reserves. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, including acquired reserves, due to its impact on depletion expense, impairment evaluation, and acquisition accounting, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense, and the fair value of acquired oil and gas properties. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation, management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment, and management’s estimation of the fair value of the acquired oil and gas properties. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Company’s accounting records, the management review controls on information provided to the reservoir engineering specialists, the management review controls on the final proved reserve report and on the final fair value reserve reports of the acquired oil and gas properties prepared by the Company’s specialists.
•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:
-Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
-Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;
-Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;
-Compared, on a sample basis, the working and net revenue interests used in the reserve report to land and division order records;
-Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s intent to develop the proved undeveloped properties;
-Evaluated the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties, on a sample basis; and
-Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.
•To the extent key, sensitive inputs and assumptions used to determine the fair value of the acquired proved reserve volumes and other cash flow inputs were analyzed by testing management’s process for determining the assumptions, including examining the underlying support. Specifically, our audit procedures involved testing management’s assumptions as follows:
-Utilized a valuation specialist to evaluate the appropriateness of fair value pricing used in the fair value reserve report to published product pricing on the acquisition closing date;
-Utilized a valuation specialist to evaluate whether the Company’s valuation methodology was reasonable and performed a sensitivity analysis;
-Evaluated the appropriateness of the future operating cost and capital expenditure assumptions used in the fair value reserve report to historical operating costs and capital expenditures of similarly located properties;
-Compared, on a sample basis, the working and net revenue interests used in the fair value reserve report to land and division order records;
-Evaluated, on a sample basis, the appropriateness of management’s estimated future production volumes and the production decline curves; and
-Compared the acreage value allocated, on a per acre basis, to other recent acquisitions in the same or similar locations.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2009.
Oklahoma City, Oklahoma
February 24, 2022
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statement of Stockholders’ Equity
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
1) See Note 2-Summary of Significant Accounting Policies
See accompanying notes to consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Organization and Description of the Business
Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.
The wholly-owned subsidiaries of Diamondback, as of December 31, 2021, include Diamondback E&P LLC (“Diamondback E&P”), a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company (“Viper’s General Partner”), Rattler Midstream GP LLC, a Delaware limited liability company (“Rattler’s General Partner”), and QEP Resources, Inc. (“QEP”), a Delaware Corporation. Diamondback O&G LLC (“O&G”), Energen Corporation (“Energen”), Energen Resources Corporation and EGN Services, Inc., former wholly owned subsidiaries of Diamondback, were merged with and into Diamondback E&P LLC effective June 30, 2021 as part of the internal restructuring of the Company’s subsidiaries (the “E&P Merger”).
Basis of Presentation
The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.
Diamondback’s publicly traded subsidiaries Viper and Rattler are consolidated in the financial statements of the Company. As of December 31, 2021, the Company owned approximately 54% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of December 31, 2021, the Company owned approximately 74% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the equity and net income attributable to the Company.
The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. Actual results could differ from those estimates.
Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices and the effects of the ongoing COVID-19 pandemic. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.
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Notes to Consolidated Financial Statements-(Continued)
The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, the fair value determination of acquired assets and liabilities assumed, fair value estimates of derivative instruments and estimates of income taxes.
Cash, Cash Equivalents and Restricted Cash
The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.
Accounts Receivable
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.
The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications
to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. At December 31, 2021 and 2020, the Company’s allowances for credit losses related to joint interest receivables and credit losses related to sales of oil and natural gas production were not material.
Derivative Instruments
The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. For commodity derivative instruments and interest rate swaps which have not been designated as hedges for accounting purposes, the Company marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. The Company accounts for its interest rate swaps which have been designated as fair value hedges under the “shortcut” method of accounting. As such, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt. For additional information regarding the Company’s derivative instruments, see Note 15-Derivatives.
Oil and Natural Gas Properties
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as
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Notes to Consolidated Financial Statements-(Continued)
they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas and natural liquids. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $8.77, $11.30 and $13.54 for the years ended December 31, 2021, 2020 and 2019, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.2 billion and $1.4 billion for the years ended December 31, 2021, 2020 and 2019, respectively.
Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8-Property and Equipment.
Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on at least an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Real Estate Assets
Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life.
Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset. For additional information regarding the Company’s real estate assets, see Note 7-Real Estate Assets.
Other Property, Equipment and Land
Other property, equipment and land is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight-line method over their estimated useful lives, which range from three to 30 years.
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Notes to Consolidated Financial Statements-(Continued)
Asset Retirement Obligations
The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.
Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties.
The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. For additional information regarding the Company’s asset retirement obligations, see Note 9-Asset Retirement Obligations.
Impairment of Long-Lived Assets
Other property and equipment used in operations and midstream assets are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no significant impairment losses for the years ended December 31, 2021, 2020 and 2019.
Capitalized Interest
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. See Note 11-Debt for further details.
Inventories
Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2021 and 2020. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units.
Debt Issuance Costs
Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11-Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are amortized over the term of the facility.
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Notes to Consolidated Financial Statements-(Continued)
Other Accrued Liabilities
Other accrued liabilities consist of the following:
Revenue and Royalties Payable
For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.
Non-controlling Interests
Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 12-Stockholders' Equity and Earnings Per Share for a discussion of changes of the Company’s ownership interest in consolidated subsidiaries during the year ended December 31, 2021.
Revenue Recognition
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.
Oil sales
The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.
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Notes to Consolidated Financial Statements-(Continued)
Natural gas and natural gas liquids sales
Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. Generally, the midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.
In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.
Midstream Revenue
Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the frac-water meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.
Transaction price allocated to remaining performance obligations
The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts.
Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Contract balances
Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.
Prior-period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the
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Notes to Consolidated Financial Statements-(Continued)
purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the years ended December 31, 2021, 2020 and 2019 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.
Investments
The Company accounts for its corporate joint ventures under the equity method of accounting in accordance with Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 323 “Investments - Equity Method and Joint Ventures.” The Company also applies the equity method of accounting to investments of less than 50% in an investee over which the Company exercises significant influence but does not have control and investments of greater than 50% in an investee over which the Company does not exercise significant influence or have control. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations. As of December 31, 2021, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one-month lag for all equity method investments.
Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method.
The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There were no material impairments of the Company’s equity investments for the years ended December 31, 2021, 2020 and 2019. For additional information on the Company’s investments, see Note 10-Equity Method Investments.
Accounting for Equity-Based Compensation
The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13-Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur.
Environmental Compliance and Remediation
Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see Note 14-Income Taxes.
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Notes to Consolidated Financial Statements-(Continued)
Recent Accounting Pronouncements
Recently Adopted Pronouncements
In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity.
Accounting Pronouncements Not Yet Adopted
In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) - Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 - “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update, but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity.
The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.
3. REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.
The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin:
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Notes to Consolidated Financial Statements-(Continued)
Customers
The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (21%); Shell Trading (USA) Company (“Shell”) (19%); and Plains Marketing LP (“Plains”) (12%). For the year ended December 31, 2020, four purchasers each accounted for more than 10% of the Company’s revenue: Vitol (26%); Shell (22%); Plains (20%); and Trafigura Trading LLC (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (27%); Plains (23%); and Vitol (15%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
4. ACQUISITIONS AND DIVESTITURES
2021 Activity
Guidon Operating LLC
On February 26, 2021, the Company closed on its acquisition of all leasehold interests and related assets of Guidon Operating LLC (the “Guidon Acquisition”) which include approximately 32,500 net acres in the Northern Midland Basin in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash. The cash portion of this transaction was funded through a combination of cash on hand and borrowings under the Company’s credit facility. As a result of the Guidon Acquisition, the Company added approximately 210 gross producing wells.
The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands):
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Purchase Price Allocation
The Guidon Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date and may revise the value of the assets and liabilities as appropriate within that time frame. Through December 31, 2021, there have been no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.
The following table sets forth the Company’s preliminary purchase price allocation (in millions):
Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs.
With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The results of operations attributable to the Guidon Acquisition since the acquisition date have been included in the consolidated statements of operations and include $345 million of total revenue and $170 million of net income for the year ended December 31, 2021.
QEP Resources, Inc.
On March 17, 2021, the Company completed its acquisition of QEP in an all-stock transaction (the “QEP Merger”). The addition of QEP’s assets increased the Company’s net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the QEP Merger, each eligible share of QEP common stock issued and outstanding immediately prior to the effective time converted into the right to receive 0.050 of a share of Diamondback common stock, with cash being paid in lieu of any fractional shares (the “merger consideration”). At the closing date of the QEP Merger, the carrying value of QEP’s outstanding debt was approximately $1.6 billion. See Note 11-Debt for further discussion.
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Notes to Consolidated Financial Statements-(Continued)
The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands):
Purchase Price Allocation
The QEP Merger has been accounted for as a business combination using the acquisition method. The following table represents the preliminary allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, certain data necessary to complete the purchase price allocation is not yet available and includes, but is not limited to, final tax returns that provide the underlying tax basis of QEP’s assets and liabilities and final valuations of the acquired oil and natural gas properties. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.
The following table sets forth the Company’s preliminary purchase price allocation (in millions):
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Notes to Consolidated Financial Statements-(Continued)
The purchase price allocation above is based on estimates of the fair values of the assets and liabilities of QEP as of the closing date of the QEP Merger. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs. The fair value of acquired property and equipment, including midstream assets classified in oil and natural gas properties, is based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of QEP’s outstanding senior unsecured notes was based on unadjusted quoted prices in an active market, which are considered Level 1 inputs. The value of derivative instruments was based on observable inputs including forward commodity price curves which are considered Level 2 inputs. Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed.
With the completion of the QEP Merger, the Company acquired proved properties of $2.0 billion and unproved properties of $742 million, primarily in the Midland Basin and the Williston Basin. The Williston Basin assets were divested in October 2021 as discussed further below. Through December 31, 2021, the fair value allocated to proved properties acquired in the QEP Merger has decreased by $300 million and the fair value allocated to unproved properties has increased by $300 million based on management’s continuing assessment of the inputs utilized in the fair value estimates discussed above. There have been no other material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.
The results of operations attributable to the QEP Merger since the acquisition date have been included in the consolidated statements of operations and include $1.1 billion of total revenue and $455 million of net income for the year ended December 31, 2021.
Pro Forma Financial Information
The following unaudited summary pro forma financial information for the years ended December 31, 2021 and 2020 has been prepared to give effect to the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020. The unaudited pro forma financial information does not purport to be indicative of what the combined company’s results of operations would have been if these transactions had occurred on the dates indicated, nor is it indicative of the future financial position or results of operations of the combined company.
The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for QEP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and the purchase price allocated to property, plant, and equipment as well as adjustments to interest expense and the provision for (benefit from) income taxes.
Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company for the QEP Merger and the Guidon Acquisition of approximately $78 million for the year ended December 31, 2021 and acquisition-related costs incurred by QEP of $31 million through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger and the Guidon Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Divestitures of Certain Non-Core Assets
On June 3, 2021 and June 7, 2021, respectively, the Company closed transactions to divest certain non-core Permian assets including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county, Texas and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for combined net cash proceeds of $82 million, after customary closing adjustments. The Company used its net proceeds from these transactions toward debt reduction.
Williston Basin Divestiture
On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. The Company used its net proceeds from this transaction toward debt reduction.
Gas Gathering Assets Divestiture
On November 1, 2021, the Company completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC, an affiliate of Brazos Midstream (“Brazos”), for net cash proceeds of approximately $54 million, after customary closing adjustments.
2021 Drop Down Transaction
On December 1, 2021, Diamondback completed the sale of certain water midstream assets to Rattler in exchange for cash proceeds of approximately $160 million, in a drop down transaction (the “Drop Down”). The midstream assets consist primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $160 million. The Company and Rattler have also mutually agreed to amend their commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to Rattler’s dedication. The Drop Down transaction was accounted for as a transaction between entities under common control.
Viper’s Swallowtail Acquisition
On October 1, 2021, Viper acquired certain mineral and royalty interests from the Swallowtail entities pursuant to a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition had an effective date of August 1, 2021. The cash portion of this transaction was funded through a combination of Viper’s cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Rattler’s WTG Joint Venture Acquisition
On October 5, 2021, Rattler and a private affiliate of an investment fund formed the WTG joint venture. Rattler contributed approximately $104 million in cash for a 25% membership interest in the WTG joint venture, which then completed the acquisition of a majority interest in WTG Midstream from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.
Rattler’s Gas Gathering Divestiture
On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for aggregate total gross potential consideration of $93 million, consisting of (i) $83 million due at closing, after customary closing adjustments, (ii) a $5 million contingent payment due in 2023 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022, and (iii) a $5 million contingent payment due in 2024 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022 and 2023. The contingent payments will be recorded if and when they become realizable.
2020 Activity
Viper’s Acquisition of Certain Mineral and Royalty Interests
During the year ended December 31, 2020, Viper acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64 million, including post-closing adjustments. Viper funded these acquisitions with cash on hand and borrowings under Viper LLC’s revolving credit facility.
2019 Activity
Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen
On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in its merger with Energen, for an aggregate sale price of $37 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.
On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen, for an aggregate sale price of $285 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.
2019 Drop-Down Transaction
On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18 million of Viper’s newly-issued Class B units, approximately 18 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits. The mineral and royalty interests divested in the drop down transaction represented approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% were operated by the Company, and had an average net royalty interest of approximately 3.2%. The drop down transaction closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the drop down transaction through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
5. VIPER ENERGY PARTNERS LP
Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback to, among other things, own, acquire and exploit oil and natural gas properties in the Permian Basin in North America. Viper LLC (“Viper’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of viper. As of December 31, 2021, Diamondback owned approximately 54% of Viper’s total units outstanding.
In March 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. There were no equity offerings during the years ended December 31, 2021 and 2020.
During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $101 million, $62 million and $133 million, respectively, in respect of its interests in Viper and Viper LLC.
The Company is party to a partnership agreement and tax sharing agreement with Viper which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019.
See Note 4-Acquisitions and Divestitures for discussions of Viper’s acquisitions and divestitures.
Implementation of Viper’s Common Unit Repurchase Program
On November 6, 2020, the board of directors of Viper’s general partner approved a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units. The common unit repurchase program was initially authorized to extended through December 31, 2021, but in November 2021, the board of directors of Viper’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Viper repurchased approximately $46 million of its common units under its repurchase program. As of December 31, 2021, $80 million remained available for use to repurchase common units under Viper’s common unit repurchase program.
Viper LLC’s Revolving Credit Facility
Viper has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 11-Debt for a description of this credit facility.
6. RATTLER MIDSTREAM LP
Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler Midstream GP LLC (“Rattler’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2021, Diamondback owned approximately 74% of Rattler’s total units outstanding.
Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions.
In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution
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Notes to Consolidated Financial Statements-(Continued)
from Rattler’s General Partner and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback.
During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $97 million, $115 million and $36 million, respectively, in respect of its interests in Rattler and Rattler Midstream GP LLC.
The Company is party to a partnership agreement, services and secondment agreement and tax sharing agreement with Rattler which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019.
See Note 4-Acquisitions and Divestitures for discussions of Rattler’s acquisitions and divestitures.
Implementation of Rattler’s Common Unit Repurchase Program
On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units. The common unit repurchase program was initially authorized to extend through December 31, 2021, but in October 2021, the board of directors of Rattler’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Rattler repurchased approximately $48 million of its common units under its repurchase program. As of December 31, 2021, $88 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.
Rattler LLC’s Revolving Credit Facility
Rattler LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 11-Debt for a description of this credit facility.
7. REAL ESTATE ASSETS
The following schedules present the cost and related accumulated depreciation related to Diamondback’s significant real estate assets:
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Notes to Consolidated Financial Statements-(Continued)
8. PROPERTY AND EQUIPMENT
Property and equipment includes the following:
Capitalized internal costs were approximately $60 million, $53 million and $49 million for the years ended December 31, 2021, 2020 and 2019, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within ten years.
Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the book value of proved oil and natural gas properties. No impairment expense was recorded for the year ended December 31, 2021. The Company recorded non-cash ceiling test impairments for the years ended December 31, 2020 and 2019 of $6.0 billion and $790 million, respectively, which are included in accumulated depletion, depreciation, amortization and impairment on the consolidated balance sheet. The impairment charge affected the Company’s reported net income but did not reduce its cash flow.
In connection with the QEP Merger and the Guidon Acquisition, the Company recorded the oil and natural gas properties acquired at fair value, based on forward strip oil and natural gas pricing existing at the closing date of the respective transactions, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, the Company requested and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation for the quarter ended March 31, 2021. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had the Company not received a waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded for such period. Management affirmed there has not been a decline in the fair value of these acquired assets. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.
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Notes to Consolidated Financial Statements-(Continued)
In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. Given the rate of change impacting the oil and natural gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.
At December 31, 2021, there were $135 million in exploration costs and development costs and $124 million in capitalized interest that are not subject to depletion. At December 31, 2020, there were $85 million in exploration costs and development costs and $51 million capitalized interest that were not subject to depletion.
9. ASSET RETIREMENT OBLIGATIONS
The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
(1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s consolidated balance sheets.
The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
10. EQUITY METHOD INVESTMENTS
At December 31, 2021 and 2020, Rattler had the following investments:
(1)The Wink to Webster joint venture is developing a crude oil pipeline (the “Wink to Webster pipeline”). The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the first quarter of 2022.
(2)The ownership interest in Amarillo Rattler was 50% at December 31, 2020. See Note 4-Acquisitions and Divestitures for discussion regarding the sale of this equity method investment during the second quarter of 2021.
Income (loss) and distributions from Rattler’s equity method investees were not material for the years ended December 31, 2021, 2020 or 2019.
The Company reviews its equity method investments to determine if a loss in value which is other than temporary has occurred when events indicate the carrying value of the investment may not be recoverable. Based on indicators present at December 31, 2021, the Company reviewed its investment in EPIC and determined the carrying value of the investment was less than its estimated fair value due to a reduction in expected future cash flow. However, based on the Company’s review of various factors leading to the decline in the fair value of the investment, it was determined the carrying value of the EPIC investment will recover in the near term and therefore an other than temporary impairment in the carrying value of the EPIC equity method investment did not exist at December 31, 2021. However, should the conclusions on certain factors included in the Company’s analysis, including estimates of EPIC’s future cash flows, change, the Company may recognize an impairment that could materially impact it’s consolidated financial statements. No significant impairments were recorded for Rattler’s equity method investments for the years ended December 31, 2020 or 2019. Rattler’s investees all serve customers in the oil and natural gas industry, which experienced economic challenges due to the COVID-19 pandemic and other macroeconomic factors during 2020 prior to recovering in 2021. If similar economic challenges occur in future interim periods, it could result in circumstances requiring Rattler to record potentially material impairment charges on its equity method investments.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
11. DEBT
The Company’s debt consisted of the following as of the dates indicated:
(1) In June 2021, the Company redeemed the remaining $191 million principal amount of outstanding legacy 4.625% senior notes due September 1, 2021 of Energen.
(2) In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes.
(3) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and remained the issuer of these senior notes.
(4) In November 2018, Energen became the Company’s wholly owned subsidiary and remained the issuer of these senior notes. In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture.
(5) The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. As of December 31, 2021, the amount due to CEMOF related to this alliance was $58 million. As of December 31, 2021, fifteen joint wells under this agreement have been drilled and completed.
(6) The Company has two interest rate swap agreements in place on the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. See Note 15-Derivatives for additional information on the Company’s interest rate swaps designated as fair value hedges.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Debt maturities as of December 31, 2021, excluding debt issuance costs, premiums and discounts and fair value of interest rate swap premiums are as follows:
References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback E&P, collectively, unless otherwise specified.
Second Amended and Restated Credit Facility
The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 2, 2021, Diamondback Energy, Inc., as parent guarantor, and O&G, as borrower (the “Borrower”), entered into a twelfth amendment (the “Amendment”) to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, with Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto. The Amendment, among other things, (i) extended the maturity date to June 2, 2026, which may be further extended by two one-year extensions pursuant to the terms set forth in the credit agreement, (ii) decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion) upon election of the Borrower, subject to obtaining additional lender commitments and satisfaction of customary conditions pursuant to the terms set forth in the credit agreement, (iii) added the ability of the Borrower to incur up to $100 million of the loans under the credit agreement as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement.
Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Borrower that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. After giving effect to the Amendment, (i) the applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate, and from 1.250% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.150% to 0.350% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on certain ratings agencies’ ratings of the Company’s long-term senior unsecured debt.
On June 30, 2021, Diamondback E&P, as successor borrower to Diamondback O&G LLC, Diamondback Energy, Inc., as parent guarantor, and the Administrative Agent entered into a Successor Borrower Joinder Agreement (the “Joinder Agreement”) in connection with the E&P Merger. Pursuant to the Joinder Agreement, Diamondback E&P assumed all obligations (including, without limitation, all of the indebtedness) of O&G as the borrower under the credit agreement, the Second Amended and Restated Guaranty Agreement, dated as of November 20, 2019, made by O&G and Diamondback Energy, Inc., and the other documents entered into connection therewith.
As of December 31, 2021, the maximum credit amount available under the credit agreement is $1.6 billion which was fully available for future borrowings, except for an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. The weighted average interest rate on borrowings under the credit agreement was 1.67%, 2.02% and 4.10% for the years ended December 31, 2021, 2020 and 2019, respectively.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022.
The credit agreement contains a financial covenant that requires us to maintain a Total Net Debt to Capitalization Ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets. As of December 31, 2021 and 2020, the Company was in compliance with all financial maintenance covenants under the revolving credit facility, as then in effect.
The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.
2021 Issuances of Notes
On March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregate principal amount of 0.900% Senior Notes due March 24, 2023 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes” and together with the 2023 Notes and the 2031 Notes, the “March 2021 Notes”) and received proceeds, net of $24 million in debt issuance costs and discounts, of $2.18 billion. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below. Interest on the March 2021 Notes is payable semi-annually in March and September, beginning in September 2021. The Company redeemed the 2023 Notes in November 2021 as discussed in “-Redemptions of Diamondback Notes” below.
The 2031 Notes and the 2051 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P. The 2031 Notes and the 2051 Notes are senior in right of payment to any of the Company’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The 2031 Notes and the 2051 Notes are effectively subordinated to the Company’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all of the existing and future indebtedness and other liabilities of the Company’s subsidiaries other than Diamondback E&P.
The Company may redeem (i) the 2031 Notes in whole or in part at any time prior to December 24, 2030 and (ii) the 2051 Notes in whole or in part at any time prior to September 24, 2050, in each case at the redemption price set forth in the IG Indenture. If the 2031 Notes or the 2051 Notes are redeemed on or after the dates noted above, in each case, they may be redeemed at a redemption price equal to 100% of the principal amount of the 2031 Notes or 2051 Notes to be redeemed plus interest accrued thereon to but not including the redemption date.
Upon the occurrence of a change of control triggering event as defined in the IG Indenture, holders may require the Company to purchase some or all of its 2031 Notes or 2051 Notes for cash at a price equal to 101% of the principal amount being purchased, plus accrued and unpaid interest, if any, to the date of purchase.
2021 Redemptions of Notes
On March 17, 2021, at the time of the QEP Merger discussed in Note 4-Acquisitions and Divestitures, QEP had outstanding debt at fair values consisting of $478 million of 5.375% Senior Notes due 2022 (the “QEP 2022 Notes”), $673 million of 5.250% Senior Notes due 2023 (the “QEP 2023 Notes”) and $558 million of 5.625% Senior Notes due 2026 (the “QEP 2026 Notes” and together with the QEP 2022 Notes and QEP 2023 Notes, the “QEP Notes”). Subsequent to the QEP Merger, in March 2021, the Company repurchased pursuant to tender offers commenced by the Company, approximately $1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of $1.7 billion, including redemption and early premium fees of $152 million, which resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of approximately $47 million. The aggregate fair value of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii) $663 million, or 98.43%, of the
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Notes to Consolidated Financial Statements-(Continued)
outstanding fair value carrying amount of the QEP 2023 Notes and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes.
In March 2021, the Company also repurchased an aggregate of $368 million principal amount of its 5.375% 2025 Senior Notes representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of $381 million, including redemption and early premium fees of $13 million. This resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of $14 million. The Company funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.
In connection with the tender offers to repurchase the QEP Notes discussed above, the Company also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. The Company received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.
In June 2021, the Company redeemed the remaining $191 million principal amount of the outstanding 4.625% senior notes of Energen due on September 1, 2021. The Company recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes. The Company funded the redemption with internally generated cash flow from operations as well as proceeds from the divestitures of certain non-core assets as discussed in Note 4-Acquisitions and Divestitures.
In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes for total cash consideration of $449 million, including redemption and early premium fees of $12 million, which resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of $12 million. The Company funded the redemption with cash on hand and borrowings under its revolving credit facility.
On November 1, 2021, the Company redeemed the aggregate $650 million principal amount of its outstanding 2023 Notes at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. The Company funded the redemption with proceeds received from the divestiture of its Williston Basin assets and cash on hand.
Viper’s Credit Agreement
On June 2, 2021, Viper LLC entered into the seventh amendment to the existing credit agreement, which (i) extended the maturity date under the credit agreement to June 2, 2025, (ii) changed the interest rates applicable to the loans under the credit agreement and certain fees payable under the credit agreement, and (iii) added a financial covenant requiring the ratio of secured debt to EBITDAX (as each is defined in the credit agreement) to be not greater than 2.50 to 1.0. On November 15, 2021, Viper LLC entered into the eighth amendment to the existing credit agreement, which maintained the maximum amount of the revolving credit facility of $2.0 billion, reaffirmed the borrowing base of $580 million based on Viper LLC’s oil and natural gas reserves and other factors and added new provisions that allow Viper LLC to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be redetermined semi-annually in May and November. In addition, Viper LLC and Wells Fargo may each request up to three interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2021, Viper LLC had elected a commitment amount of $500 million, with $304 million of outstanding borrowings and $196 million available for future borrowings under the Viper credit agreement.
The outstanding borrowings under the Viper credit agreement bear interest at a rate elected by Viper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternate base rate and from 2.00% to 3.00% per annum in the case of LIBOR, in each case depending on the amount of loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from
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Notes to Consolidated Financial Statements-(Continued)
the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date. The loan is secured by substantially all of the assets of Viper and Viper LLC. The weighted average interest rates on borrowings under the Viper credit agreement were 2.35%, 2.20%, and 4.51% for the years ended December 31, 2021, 2020 and 2019, respectively.
The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below.
The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.
As of December 31, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.
Rattler’s Credit Agreement
In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo, as administrative agent, and a syndicate of banks, as lenders party thereto (the “Rattler credit agreement”).
The Rattler credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary breakage), and is required to be paid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC, Rattler Ajax Processing LLC, Rattler WTG LLC and Rattler Holdings and is secured by substantially all of the assets of Rattler and Rattler LLC. On December 21, 2021, Rattler, as parent, entered into a third amendment (the “Third Amendment”) to the Credit Agreement, dated as of May 28, 2019, with Rattler LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto to, among other things, (i) permit the Rattler internal reorganization, including, without limitation, the formation of Rattler Holdings LLC (“Rattler Holdings”) and the contribution of 100% of the limited liability company interests Rattler held in Rattler LLC to Rattler Holdings and (ii) provide for the addition of Rattler Holdings as a guarantor and restricted subsidiary. As of December 31, 2021, Rattler LLC had $195 million of outstanding borrowings and $405 million available for future borrowings under the Rattler credit agreement.
The outstanding borrowings under the Rattler credit agreement bear interest at a rate elected by Rattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio. The weighted average interest rates on borrowings under the Rattler credit agreement were 1.41%, 2.10%, and 3.13% for the years ended December 31, 2021, 2020 and 2019, respectively.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler or Rattler LLC to issue unsecured debt securities and an exception allowing payment of distributions if no default exists.
The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below:
As of December 31, 2021, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the Credit Agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.
Interest expense
The following amounts have been incurred and charged to interest expense for the years ended December 31, 2021, 2020 and 2019:
12. STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE
Diamondback did not complete any equity offerings during the years ended December 31, 2021, 2020 and 2019.
Stock Repurchase Programs
In September 2021, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific
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Notes to Consolidated Financial Statements-(Continued)
number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the year ended December 31, 2021, the Company repurchased approximately $431 million of common stock under this repurchase program, respectively. As of December 31, 2021, $1.6 billion remained available for use to repurchase shares under the Company’s common stock repurchase program.
In May 2019, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock through December 31, 2020. Purchases under the repurchase program were made from time to time in open market or privately negotiated transactions, and were subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program did not require the Company to acquire any specific number of shares. During the years ended December 31, 2020 and 2019, the Company repurchased $98 million and $598 million, respectively, of its common stock under the repurchase program. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.
Change in Ownership of Consolidated Subsidiaries
Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. The Company’s ownership percentage in Viper and Rattler change as a result of public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on its units. These changes in ownership percentage and the disproportionate allocation of net income to the Company result in the difference between the Company’s share of the underlying net book value in Viper and Rattler. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur.
The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:
(1) The year ended December 31, 2020 includes an adjustment to non-controlling interest for Rattler of $329 million and to additional paid-in-capital of $329 million to reflect the ownership structure that was effective at June 30, 2020. The adjustment had no impact on the consolidated statement of income or consolidated statement of cash flows for the year ended December 31, 2020.
Viper Unitholders’ Equity
For information regarding Viper’s significant equity transactions, refer to Note 5-Viper Energy Partners LP.
Rattler Unitholders’ Equity
For information regarding Rattler’s significant equity transactions, refer to Note 6-Rattler Midstream LP.
Earnings (Loss) Per Share
The Company’s basic earnings (loss) per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
A reconciliation of the components of basic and diluted earnings (loss) per common share is presented in the table below:
(1) For the year ended December 31, 2021, there were 115,865 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method.
(2) For the year ended December 31, 2020, there were 696,223 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive due to recording a net loss.
13. EQUITY-BASED COMPENSATION
On June 3, 2021, the Company’s stockholders approved and adopted the Company’s 2021 amended and restated equity incentive plan (the “Equity Plan”), which, among other things, increased total shares authorized for issuance from 8.3 million to 11.8 million. At December 31, 2021, the Company had 6.9 million shares of common stock available for future grants.
Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. At December 31, 2021, the Company had outstanding restricted stock units, performance-based restricted stock units, immaterial amounts of restricted share awards which were assumed in connection with the QEP Merger, and immaterial amounts of stock options and stock appreciation rights.
The following table presents the effects of the equity and stock based compensation plans and related costs:
Restricted Stock Units
The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period.
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Notes to Consolidated Financial Statements-(Continued)
The following table presents the Company’s restricted stock unit activity under the Equity Plan during the year ended December 31, 2021:
The aggregate fair value of restricted stock units that vested during the years ended December 31, 2021, 2020 and 2019 was $46 million, $25 million and $45 million, respectively. As of December 31, 2021, the Company’s unrecognized compensation cost related to unvested restricted stock units was $52 million. Such cost is expected to be recognized over a weighted-average period of 2.0 years.
During the year ended December 31, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which did not result in any incremental compensation costs.
Performance-Based Restricted Stock Units
To provide long-term incentives for executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period.
In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the performance period of January 1, 2019 to December 31, 2021, subject to continued employment. All remaining awards under this grant cliff vested at December 31, 2021 at 100% based on the final TSR In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards had a performance period of January 1, 2019 to December 31, 2021 and were awarded at 100% based upon the final TSR. The awards under this grant vest in five equal installments beginning on March 1, 2025.
In March 2020, eligible employees received performance restricted stock unit awards totaling 225,047 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the three-year performance period of January 1, 2020 to December 31, 2022 and cliff vest at December 31, 2022 subject to continued employment. The initial payout of the March 2020 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.
In March 2021, eligible employees received performance restricted stock unit awards totaling 198,454 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2021 to December 31, 2023 and cliff vest at December 31, 2023 subject to continued employment. The initial payout of the March 2021 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.
The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the awards granted during the period presented:
The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2021:
(1)A maximum of 1,091,711 units could be awarded based upon the Company’s final TSR ranking.
As of December 31, 2021, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $26 million, which is expected to be recognized over a weighted-average period of 1.9 years.
Rattler Long-Term Incentive Plan
On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”) which authorized a total of 15.2 million common units for issuance, for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. Excluding unvested common units, as of December 31, 2021, a total of 12,696,146 common units had been reserved for future issuance pursuant to the Rattler LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Rattler LTIP is administered by the board of directors of Rattler’s General Partner or a committee thereof.
Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units based on closing price of Rattler’s common units on the grant date of the award, and expenses this value over the applicable vesting period. Upon vesting, the phantom units entitle the recipient to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2021:
The aggregate fair value of phantom units that vested during the year ended December 31, 2021 was $9 million. As of December 31, 2021, the unrecognized compensation cost related to unvested phantom units was $23 million which is expected to be recognized over a weighted-average period of 2.3 years.
14. INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. The Company and its subsidiaries, other than Viper, Viper LLC, Rattler and Rattler LLC, file a federal corporate income tax return on a consolidated basis. As discussed further below, Viper is a taxable entity for federal income tax purposes effective May 10, 2018, and as such files a federal corporate income tax return including the activity of its investment in Viper LLC. Subsequent to Rattler’s election to be treated as a corporation for federal income tax purposes effective May 24, 2019, Rattler is also a taxable entity and as such files a federal corporate income tax return including the activity of its investment in Rattler LLC. Viper’s and Rattler’s provision for income taxes is included in the Company’s consolidated income tax provision and, to the extent applicable, in net income attributable to the non-controlling interest.
The Company’s effective income tax rates were 21.7%, 19.1% and 13.0% for the years ended December 31, 2021, 2020 and 2019, respectively. Total income tax expense for the year ended December 31, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to state income taxes, net of federal benefit. Total income tax benefit for the year ended December 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to the impact of recording a valuation allowance on Viper’s deferred tax assets, partially offset by state income taxes net of federal benefit and by tax benefit resulting from the carryback of federal net operating losses. Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the impact of deferred taxes recognized as a result of Viper’s change in tax status and state income taxes net of federal benefit.
The Company considered the impact of the American Rescue Plan Act, enacted on March 11, 2021, and concluded its provisions related to U.S. income taxes for corporations did not materially affect the Company’s current or deferred tax balances. Under provisions enacted March 27, 2020 in the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), the Company realized income tax benefit of $25 million in the period of enactment related to the carryback of approximately $179 million of the Company’s federal net operating losses to tax years in which the corporate income tax rate was 35%. Prior to the enactment of the CARES Act in the first quarter of 2020, there was no tax refund available to the Company with respect to its losses, resulting in deferred tax assets associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company received a refund of federal taxes in the first quarter of 2021 of approximately $100 million. In addition, the Company received in the third quarter of 2021 a federal tax refund of approximately $50 million related to refundable minimum tax credits resulting from carryback of certain federal net operating losses acquired from QEP.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2021, 2020 and 2019 are as follows:
A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The components of the Company’s deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows:
The Company had net deferred tax liabilities of approximately $1.3 billion and $0.7 billion at December 31, 2021 and 2020, respectively.
At December 31, 2021, the Company had approximately $0.5 billion of federal NOLs expiring in 2037 and $2.0 billion of federal NOLs with an indefinite carryforward life, including NOLs acquired from QEP. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company’s federal tax attributes, including those acquired from QEP, are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period. Other than as described below regarding realization of tax attributes acquired from QEP, the Company believes that the application of Section 382 will not have an adverse effect on future usage of the Company’s NOLs and credits.
On March 17, 2021, the Company completed its acquisition of QEP. For federal income tax purposes, the transaction qualified as a nontaxable merger whereby the Company acquired carryover tax basis in QEP’s assets and liabilities. As of December 31, 2021, QEP’s opening balance sheet net deferred tax asset was approximately $40 million, primarily consisting of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance, and deferred tax liabilities resulting from the excess of financial reporting carrying value over tax basis of oil and natural gas properties and other assets acquired from QEP. The acquired income tax attributes, including federal net operating loss and credit carryforwards, are subject to an annual limitation under Section 382. The Company has considered the positive and negative evidence regarding realizability of these federal tax attributes including taxable income in prior carryback years, the annual limitation imposed by Section 382, and the anticipated timing of reversal of its deferred tax liabilities, resulting in a valuation allowance of $23 million on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. Acquired tax attributes also include state net operating loss carryforwards for which a valuation allowance of $117 million has been provided, since the Company does not believe the state net operating losses are more likely than not to be realized based on its assessment of anticipated future operations in those states.
In addition, as of December 31, 2021, the Company had a valuation allowance of $6 million primarily related to certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate future operations in those states and a valuation allowance of $169 million related to Viper’s deferred tax assets, as discussed further below. Management’s assessment at each balance sheet date included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. Management believes that the balance of the
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Notes to Consolidated Financial Statements-(Continued)
Company’s NOLs are realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As of December 31, 2021, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.
At December 31, 2021, the Company’s net deferred tax liabilities include deferred tax assets of approximately $6 million related to Viper’s NOL carryforwards and approximately $163 million related to Viper’s investment in Viper LLC. Subsequent to Viper’s change in tax status, deferred taxes are provided on the difference between Viper’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in Viper LLC. As of December 31, 2021, Viper had federal NOL carryforwards of approximately $29 million which may be carried forward indefinitely to offset future taxable income.
As of December 31, 2021, Viper had a valuation allowance of approximately $169 million related to deferred tax assets that Viper does not believe are more likely than not to be realized. Management considers the likelihood that Viper’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. The determination to record a valuation allowance was based on Management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the assessment resulted in application of a valuation allowance against Viper’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the years ended December 31, 2020 and 2021.
As discussed further in Note 6-Rattler Midstream LP, on May 28, 2019, Rattler completed its initial public offering. Even though Rattler is organized as a limited partnership under state law, Rattler is subject to U.S. federal and state income tax at corporate rates, subsequent to the effective date of Rattler’s election to be treated as a corporation for U.S. federal income tax purposes. As such, Rattler’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.
At December 31, 2021, the Company’s net deferred tax liabilities include deferred tax assets of approximately $23 million related to Rattlers NOL carryforwards and approximately $40 million related to Rattler’s investment in Rattler LLC. At December 31, 2021, Rattler had federal net operating loss carryforwards of approximately $108 million which may be carried forward indefinitely to offset future taxable income.
Management considers the likelihood that Rattler’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2021, Rattler’s assessment included consideration of all available positive and negative evidence, including Rattler’s projected future taxable income and the anticipated timing of reversal of deferred tax assets. As a result of the assessment, management determined that it is more likely than not that Rattler will realize its deferred tax assets as of December 31, 2021.
The following table sets forth changes in the Company’s unrecognized tax benefits:
The Company recognizes the tax benefit from a tax position only if it is more likely than not that it will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. The Company’s federal and state income tax returns for 2012 through the current tax year remain open and subject to examination by the IRS and major state taxing jurisdictions. Energen is currently under IRS examination of its federal consolidated income tax returns for 2014 and 2016. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax positions may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations
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Notes to Consolidated Financial Statements-(Continued)
is highly uncertain, the Company does not expect the change in unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.
The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2021 and 2020, there was less than $0.2 million of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.
15. DERIVATIVES
At December 31, 2021, the Company has commodity derivative contracts and receive-fixed, pay-variable interest rate hedges outstanding. All derivative financial instruments are recorded at fair value.
Commodity Contracts
The Company has entered into multiple crude oil, natural gas and natural gas liquids derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company has entered into commodity derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk. As such, the Company does not require collateral from its counterparties.
The Company has multiple commodity derivative contracts that contain an other-than-insignificant financing element at inception and, therefore, the cash receipts were classified as cash flows from financing activities in the consolidated statements of cash flow for the year ended December 31, 2021.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
As of December 31, 2021, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:
(1) Excludes 8,250 BO/d of Brent swaptions, whereby the counterparty has the right to exercise the hedge at a weighted-average price of $68.62/Bbl in the second half of 2022.
(2) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Interest Rate Swaps
In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million each to limit the Company’s exposure to changes in the fair value of debt due to movements in LIBOR interest rates. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) whereby the Company will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. Gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt, and were not material for the year ended December 31, 2021. These interest rate swaps are assumed to be perfectly effective and were determined to qualify for the shortcut method of accounting. The swaps expire on December 1, 2029, with an alternative early termination date of September 1, 2029, which mirrors the call option in the 2029 Notes.
During 2020 and the first quarter of 2021, the Company used interest rate swaps to reduce its exposure to variable rate interest payments associated with the Company’s revolving credit facility. These interest rate swaps were not designated as hedging instruments and as a result, the Company recognized all changes in fair value immediately in earnings. During the first quarter of 2021, the Company terminated all of its previously outstanding interest rate swaps which resulted in cash received upon settlement of $80 million, net of fees, during the year ended December 31, 2021. The interest rate swaps contained an other-than-insignificant financing element at inception, and therefore, the cash receipts were classified as cash flows from financing activities in the consolidated statements of cash flow for the year ended December 31, 2021.
Balance Sheet Offsetting of Derivative Assets and Liabilities
The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 16-Fair Value Measurements for further details.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Gains and Losses on Derivative Instruments
The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the consolidated statements of operations:
(1)The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million.
(2)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.
(3)The years ended December 31, 2021 and 2019 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million and $43 million, respectively.
16. FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s commodity derivative instruments and interest rate swaps. The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. Interest rate swaps designated as fair value hedges and those that are not designated as hedges are determined based on inputs that are readily available in public markets, can be derived from information available in publicly quoted markets, or are provided by financial institutions that trade these contracts. These valuations are Level 2 inputs. The net fair value of the Company’s interest rate swaps designated as hedges are included in long-term debt in the consolidated balance sheet.
The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2021 and December 31, 2020. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Assets and Liabilities Not Recorded at Fair Value
The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:
The fair values of the Company’s credit agreement, the Viper credit agreement and the Rattler credit agreement approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair values of the outstanding notes were determined using the December 31, 2021 quoted market prices, a Level 1 classification in the fair value hierarchy.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include those acquired in a business combination, inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Refer to Note 4-Acquisitions and Divestitures and Note 8-Property and Equipment for additional discussion of nonrecurring fair value adjustments.
Fair Value of Financial Assets
The carrying amount of cash and cash equivalents, receivables, funds held in escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
17. SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS
18. COMMITMENTS AND CONTINGENCIES
The Company is a party to various legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company’s current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
Commitments
The following is a schedule of minimum future payments with commitments that have initial or remaining noncancellable terms in excess of one year as of December 31, 2021:
(1)The Company has committed to transport gross quantities of crude oil and natural gas on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above.
(2)The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
(3)Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021.
At December 31, 2021, the Company’s delivery commitments covered the following gross volumes of oil:
As of December 31, 2021, Rattler’s anticipated future capital commitments for its equity method investments total $28 million in the aggregate. The timing of when capital commitments will be requested can vary, but at December 31, 2021, approximately $11 million of the remaining commitment is expected to be funded in 2022, with the remaining $17 million expected to be funded in 2023.
19. SUBSEQUENT EVENTS
Fourth Quarter 2021 Dividend Declaration
On February 18, 2022, the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2021 of $0.60 per share of common stock, payable on March 11, 2022 to its stockholders of record at the close of business on March 4, 2022.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
20. SEGMENT INFORMATION
The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. All of the Company’s equity method investments are included in the midstream operations segment. The segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance.
The following tables summarize the results of the Company's operating segments during the periods presented:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
21. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)
The Company’s oil and natural gas reserves are attributable solely to properties within the United States.
Capitalized oil and natural gas costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
Costs incurred in oil and natural gas activities
Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
Results of Operations from Oil and Natural Gas Producing Activities
The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and income tax expense has been calculated by applying statutory income tax rates to oil, gas and natural gas liquids sales after deducting production costs, depreciation, depletion and amortization and accretion and impairment. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations.
Oil and Natural Gas Reserves
Proved oil and natural gas reserve estimates as of December 31, 2021, 2020 and 2019 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The changes in estimated proved reserves are as follows:
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
During the year ended December 31, 2021, the Company’s extensions and discoveries of 518,722 MBOE resulted primarily from the drilling of 470 new wells, including 345 wells in which we own only a mineral interest through Viper, and from 439 new proved undeveloped locations added. Viper royalty interests accounted for 6% of the extension volumes. The Company’s downward revisions of previous estimates of 134,705 MBOE were the result of negative revisions of 268,560 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 133,855 MBOE associated with higher commodity prices and improved well performance. Purchases of 285,309 MBOE primarily resulted from 276,207 MBOE attributable largely to the QEP Merger and Guidon Acquisition, and 9,102 MBOE of Viper royalty purchases, including the Swallowtail Acquisition. Divestitures of 59,775 MBOE related primarily to the Williston Basin Divestiture.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
During the year ended December 31, 2020, the Company’s extensions and discoveries of 302,092 MBOE resulted primarily from the drilling of 682 new wells and from 298 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,290 MBOE were the result of negative revisions due to lower product pricing of 54,645 MBOE, which were partially offset by positive revisions of 23,066 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 31,579 MBOE. Downgrades of 31,074 MBOE are primarily from changes in the corporate development plan. These revisions were offset by positive performance revisions of 56,362 MBOE associated with less gas flaring and a corresponding increase in natural gas liquid recoveries.
During the year ended December 31, 2019, the Company’s extensions and discoveries totaling 376,287 MBOE resulted primarily from the drilling of 283 new wells and from 291 new proved undeveloped locations added. Viper royalty interests accounted for 5% of the extension volumes. The Company’s downward revisions of 117,898 MBOE were the result of proved undeveloped downgrades associated with inventory refinement following the Energen acquisition along with updated development plans and lower realized prices. Purchases of 21,092 MBOE were the result of 10,939 MBOE of working interest purchases and 10,153 MBOE of Viper royalty purchases, excluding mineral interests dropped down to Viper.
At December 31, 2021, the Company’s estimated PUD reserves were approximately 587,889 MBOE, an 88,246 MBOE increase over the reserve estimate at December 31, 2020 of 499,643 MBOE. The following table includes the changes in PUD reserves for 2021 (MBOE):
The increase in proved undeveloped reserves was primarily attributable to extensions of 416,327 MBOE from 439 gross (383 net) wells in which the Company has a working interest and 24,700 MBOE from 336 gross wells in which Viper owns royalty interests. Of the 439 gross working interest wells, 409 were in the Midland Basin and 30 were in the Delaware Basin. Transfers of 172,526 MBOE from undeveloped to developed reserves were the result of drilling or participating in 154 gross (142 net) horizontal wells in which the Company has a working interest and 127 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 106 of the 127 gross Viper wells. Downward revisions of 243,268 MBOE were the result of negative revisions of 260,494 MBOE due to downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 17,226 MBOE primarily attributable to higher commodity prices and improved well performance. Purchases of 63,013 MBOE were the result of 59,023 MBOE primarily from QEP and Guidon, and 3,990 MBOE of Viper royalty purchases.
As of December 31, 2021, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2021, approximately $516 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is based on the unweighted arithmetic average, first-day-of-the-month price for the rolling 12-month period. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)
The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2021, 2020 and 2019:
(1) Includes $2.1 billion, $1.0 billion, and $1.3 billion, for the years ended December 31, 2021, 2020 and 2019, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 54% non-controlling interest at December 31, 2021.
The table below presents the unweighted arithmetic average first-day-of-the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows:
Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

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