DIAMONDBACK ENERGY, INC. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-K) - marketscreener.com

The following discussion and analysis should be read in conjunction with ourconsolidated financial statements and notes thereto appearing elsewhere in thisAnnual 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 thosecontained in these forward-looking statements due to a number of factors. SeeItem 1A. "Risk Factors" and "Cautionary Statement Regarding Forward-LookingStatements."

Overview

We are an independent oil and natural gas company focused on the acquisition,development, exploration and exploitation of unconventional, onshore oil andnatural gas reserves in the Permian Basin in West Texas. We operate in twooperating segments: (i) the upstream segment, which is engaged in theacquisition, development, exploration and exploitation of unconventional,onshore oil and natural gas reserves primarily in the Permian Basin in WestTexas and (ii) through our subsidiary, Rattler, the midstream operationssegment, which is focused on ownership, operation, development and acquisitionof the midstream infrastructure assets in the Midland and Delaware Basins of thePermian Basin.We operate under a strategic approach that focuses predominantly on enhancingreturn through our low-cost development strategy of resource conversion, capitalallocation and continued improvements in operational and cost efficiencies. Weare also committed to delivering results in a socially and environmentallyresponsible 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 wellsin the Midland Basin and 41 gross horizontal wells in the Delaware Basin.

•We turned 275 gross operated horizontal wells (including 207 in the MidlandBasin 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 endedDecember 31, 2021 was 10,602 feet.

•As of December 31, 2021, we had approximately 445,848 net acres, whichprimarily consisted of approximately 265,562 net acres in the Midland Basin andapproximately 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 beeconomic at $50.00 per Bbl WTI. In addition, our publicly traded subsidiaryViper owns mineral interests underlying approximately 930,871 gross acres and27,027 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 perBOE, including lease operating expenses of $4.12 per BOE, cash general andadministrative expenses of $0.69 per BOE and production and ad valorem taxes andgathering 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 includedapproximately 32,500 net acres in the Northern Midland Basin, in exchange for10.68 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 assetsincreased our net acreage in the Midland Basin by approximately 49,000 netacres. Under the terms of the merger agreement, we issued approximately 12.12million shares of our common stock to the former QEP stockholders, with a totalvalue of approximately $987 million on the closing date. 46-------------------------------------------------------------------------------- Table of ContentsOn October 1, 2021, Viper completed the acquisition of certain mineral androyalty interests from Swallowtail Royalties LLC and Swallowtail Royalties IILLC (the "Swallowtail entities") which included certain mineral and royaltyinterests for 15.25 million of Viper's common units and approximately$225 million in cash (the "Swallowtail Acquisition"). The cash portion of thepurchase price was funded through a combination of cash on hand andapproximately $190 million of borrowings under Viper LLC's revolving creditfacility.On October 5, 2021, Rattler and a private affiliate of an investment fund formeda joint venture entity, Remuda Midstream Holdings LLC (the "WTG joint venture").Rattler contributed approximately $104 million in cash for a 25% membershipinterest in the WTG joint venture, which then completed the acquisition of amajority interest in WTG Midstream LLC ("WTG Midstream").

2021 Divestiture Activity

On June 3, 2021 and June 7, 2021, respectively, we closed transactions to divestcertain non-core Permian assets, including over 7,000 net acres of non-coreSouthern Midland Basin acreage in Upton county, Texas and approximately 1,300net acres of non-core, non-operated Delaware Basin assets in Lea county, NewMexico, for combined net cash proceeds of $82 million, after customary closingadjustments. We used our net proceeds from these transactions toward debtreduction.On October 21, 2021, we completed the divestiture of our Williston Basin oil andnatural gas assets, consisting of approximately 95,000 net acres acquired in theQEP Merger, for net cash proceeds of approximately $586 million after customaryclosing adjustments. We used our net proceeds from this transaction toward debtreduction.On November 1, 2021, we completed the sale of certain gas gathering assets toBrazos Delaware Gas, LLC, which we refer to as Brazos, for net cash proceeds ofapproximately $54 million, after customary closing adjustments.On December 1, 2021, we completed the sale of certain water midstream assetswith a carrying value of approximately $160 million to Rattler in exchange forcash proceeds of approximately $160 million.On November 1, 2021, Rattler completed the sale of its gas gathering assets toBrazos for net cash proceeds of approximately $83 million at closing, aftercustomary closing adjustments, and an aggregate of $10 million in contingentpayments.

See Note 4- Acquisitions and Divestiture s for additional discussion of thesetransactions.

Debt TransactionsIssuances of NotesOn March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregateprincipal 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 netproceeds were primarily used to fund the redemption of other senior notesoutstanding as discussed further below.

Redemption of Notes

The net proceeds from the March 2021 Notes discussed above were primarily usedto fund the repurchase of $1.65 billion in fair value carrying amount of the QEPNotes that remained outstanding at the effective time of the QEP Merger fortotal cash consideration of $1.7 billion, and $368 million principal amount of2025 Senior Notes, for total cash consideration of $381 million. Giving effectto the repurchase of the 2023 Notes discussed below, these refinancingtransactions are expected to result in an estimated annual interest cost savingsof approximately $40 million in addition to an estimated $60 to $80 million ofpreviously announced expected annual cost synergies from the QEP Merger.

In June 2021, we redeemed the remaining $191 million principal amount ofoutstanding legacy 4.625% senior notes due September 1, 2021 of EnergenCorporation ("Energen").

In August 2021 we redeemed the remaining $432 million principal amount of ouroutstanding 5.375% 2025 Senior Notes at a redemption price equal to 102.688% ofthe principal amount plus accrued interest. We funded the redemption with cashon hand and borrowings under our revolving credit facility. 47-------------------------------------------------------------------------------- Table of ContentsOn November 1, 2021, we redeemed the aggregate $650 million principal amount ofour outstanding 2023 Notes with the proceeds received from the divestiture ofour Williston Basin assets and cash on hand.

For additional discussion of our 2021 debt transactions and the amendment to thesecond amended and restated credit facility, see Note 11- Deb t .

Fourth Quarter 2021 Dividend Declaration and Increase

On February 18, 2022, our board of directors declared a cash dividend for thefourth 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 quarterlydividend.

Stock and Unit Repurchase Programs

During the year ended December 31, 2021, we repurchased approximately $431million of Diamondback common stock, and as of December 31, 2021, $1.6 billionremained available for future purchases under our common stock repurchaseprogram.

During the year ended December 31, 2021, Viper repurchased approximately $46million of common units under its repurchase program. As of December 31,2021, $80 million remained available for use to repurchase common units underViper's common unit repurchase program.During the year ended December 31, 2021, Rattler repurchased approximately $48million of common units under its repurchase program. As of December 31,2021, $88 million remained available for use to repurchase common units underRattler's common unit repurchase program.

See " - Li qui dity and Capital Resources " below for additionaldiscussion.

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 thesupply and demand in global oil and natural gas markets, including (i) actionstaken by OPEC members and other exporting nations impacting commodity price andproduction levels and (ii) a significant decrease in demand due to the COVID-19pandemic. Demand for oil and natural gas increased during 2021, as manyrestrictions on conducting business implemented in response to the COVID-19pandemic were lifted due to improved treatments and availability of vaccinationsin the U.S. and globally. As a result, oil and natural gas market prices haveimproved during 2021 in response to the increase in demand. During 2021 and2020, the posted price for West Texas intermediate light sweet crude oil, orNYMEX WTI, has ranged from $(37.63) to $84.65 Bbl, and the NYMEX Henry Hub priceof 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 closingNYMEX Henry Hub price of natural gas was $4.28 per MMBtu. The emergence of theDelta COVID-19 variant in the latter part of 2021 and the subsequent surge ofthe highly transmissible Omicron variant, however, contributed to economic andpricing volatility as industry and market participants evaluated industryconditions and production outlook. Further, on January 4, 2021, OPEC and itsnon-OPEC allies, known collectively as OPEC+, agreed to continue their program(commenced in August of 2021) of gradual monthly output increases in February2022, raising its output target by 400,000 Bbls per day, which is expected tofurther boost oil supply in response to rising demand. In its report issued onFebruary 10, 2022, OPEC noted its expectation that world oil demand will rise by4.15 million Bbls per day in 2022, as the global economy continues to post astrong recovery from the COVID-19 pandemic. Although this demand outlook isexpected to underpin oil prices, already seen at a seven-year high in February2022, we cannot predict any future volatility in commodity prices or demand forcrude oil.

Despite the recovery in commodity prices and rising demand, we kept ourproduction relatively flat during 2021, using excess cash flow for debtrepayment and/or return to our stockholders rather than expanding our drillingprogram.

 48-------------------------------------------------------------------------------- Table of ContentsOutlookDuring 2021, we continued building on our execution track record, generatingfree cash flow while keeping capital costs under control, and our efficiencygains, particularly in the Midland Basin drilling and completion programs, wereable to mitigate certain inflationary pressures on well costs and led to a totalcapital expenditure amount of $1.5 billion down 11% from our guidance presentedin April of 2021. We expect to continue to build on these operationalefficiencies by controlling the variable portion of our operating and capitalcosts, which we believe will help mitigate the inflationary pressures seenacross our business. We remain committed to capital discipline by maintainingflat oil production in 2022 and expect to maintain our best-in-class capitalefficiency and cost structure. We expect to be in a position to continue todeliver on the recently announced enhanced capital return program, where weexpect to distribute at least 50% of our quarterly free cash flow to ourstockholders. Our capital return program is currently focused on our sustainableand growing dividend and a combination of stock repurchases and variabledividends. We expect to remain flexible on returning capital to ourstockholders, depending on which method our board of directors believes presentsthe best return of capital to our stockholders at the relevant time.

In the Midland Basin, we continued to have positive results across our coredevelopment areas located within Midland, Martin, Howard, Glasscock and Andrewscounties, 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 ofwells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which webelieve has been de-risked across a significant portion of our total acreageposition and remains our primary development target. In 2022, we expect to focusdevelopment on these areas.As of December 31, 2021, we were operating 10 drilling rigs and four completioncrews and currently intend to operate between 10 and 12 drilling rigs andbetween three and four completion crews in 2022 on average across our currentacreage position in the Midland and Delaware Basins.

Environmental Responsibility Initiatives and Highlights

In February 2021, we announced significant enhancements to our commitment toenvironmental, social responsibility and governance, or ESG, performance anddisclosure, including Scope 1 and methane emission intensity reduction targets.Our goals include the reduction of our Scope 1 greenhouse gas intensity by atleast 50% and methane intensity by at least 70%, in each case by 2024 from the2019 levels. To further underscore our commitment to carbon neutrality, we havealso implemented our "Net Zero Now" initiative under which, effective January 1,2021, we strive to produce every hydrocarbon molecule with zero Scope 1emissions. To the extent our greenhouse gas and methane intensity targets do noteliminate our carbon footprint, we have purchased carbon credits to offset theremaining emissions. We have also increased the weighting of ESG metrics in ourannual short-term incentive compensation plan to motivate our executives toadvance our environmental responsibility goals.In September 2021, we announced our long-term goal to end routine flaring by2025 and a long-term target to source over 65% of our water used for drillingand completion operations from recycled sources by 2025. With respect toflaring, we flared 1.55% of our gross natural gas production in the fourthquarter of 2021. For the full year ended 2021, we flared 1.45% of our grossnatural gas production, down 26% from 2020.

2022 Capital Budget

We have currently budgeted 2022 total capital spend of $1.75 billion to $1.90billion. Should commodity prices weaken, we intend to act responsibly and,consistent with our prior practices, reduce capital spending. If commodityprices strengthen, we intend to maintain flat oil production, pay downindebtedness and return cash to our stockholders.

Results of Operations

 The following discussion focuses primarily on a comparison of the results ofoperations between the years ended December 31, 2021 and 2020. The midstreamoperations segment's revenues and operating expenses were not significant to ourconsolidated statements of operations for the years ended December 31, 2021,2020 and 2019. .For a discussion of the results of operations for the year endedDecember 31, 2020 as compared to the year ended December 31, 2019, please referto "Part II, Item 7. Management's Discussion and Analysis of FinancialCondition and Results of Operations" in our Annual Report on Form 10-K for theyear ended December 31, 2020 (filed with the SEC on February 25, 2021), which isincorporated in this report by reference from such prior report on Form 10-K. 49

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Table of Contents

The following table sets forth selected historical operating data for theperiods indicated: Year Ended December 31, 2021 2020Revenues (in millions):Oil sales $ 5,396$ 2,410Natural gas sales 569 107Natural gas liquid sales 782 239

Total oil, natural gas and natural gas liquid revenues $ 6,747

$ 2,756Production Data:Oil (MBbls) 81,522 66,182Natural gas (MMcf) 169,406 130,549Natural gas liquids (MBbls) 27,246 21,981Combined volumes (MBOE)(1) 137,002 109,921Daily oil volumes (BO/d) 223,348 180,825Daily combined volumes (BOE/d)(1) 375,348 300,331Average Prices:Oil ($ per Bbl) $ 66.19$ 36.41Natural gas ($ per Mcf) $ 3.36$ 0.82Natural gas liquids ($ per Bbl) $ 28.70$ 10.87Combined ($ per BOE) $ 49.25$ 25.07Oil, hedged ($ per Bbl)(2) $ 52.56$ 40.34Natural gas, hedged ($ per Mcf)(2) $ 2.39$ 0.67Natural gas liquids, hedged ($ per Bbl)(2) $ 28.33$ 10.83Average price, hedged ($ per BOE)(2) $ 39.87

$ 27.26

(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 onour average sales prices and include gains and losses on cash settlements formatured commodity derivatives, which we do not designate for hedge accounting.Hedged prices exclude gains or losses resulting from the early settlement ofcommodity derivative contracts.

Production Data

Substantially all of our revenues are generated through the sale of oil, naturalgas and natural gas liquids production. The following tables providesinformation on the mix of our production for the years ended December 31, 2021and 2020: Year Ended December 31, 2021 2020Oil (MBbls) 60 % 60 %Natural gas (MMcf) 20 % 20 %Natural gas liquids (MBbls) 20 % 20 % 100 % 100 %

Comparison of the Years Ended December 31, 2021 and 2020

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a functionof oil, natural gas and natural gas liquids production volumes sold and averagesales prices received for those volumes. 50-------------------------------------------------------------------------------- Table of ContentsOur 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 dueto a 25% increase in combined volumes sold.Higher commodity prices during 2021 compared to 2020 primarily reflect arecovery from historically low prices experienced in 2020 due to the COVID-19pandemic as discussed in "- 2021 Transactions and Recent Developments " above.The increase in production for 2021 compared to 2020 resulted primarily from theGuidon Acquisition and QEP Merger during the first quarter of 2021 and anoverall recovery in our drilling and production activities after curtailments inthe second quarter of 2020 in response to the COVID-19 pandemic. We expect tohold our oil production levels flat during 2022.

Lease Operating Expenses. The following table shows lease operating expenses forthe years ended December 31, 2021 and 2020:

 Year Ended December 

31,

 2021 

2020

(In millions, except per BOE amounts) Amount Per BOE Amount

 Per BOELease operating expenses $ 565$ 4.12$ 425$ 3.87Lease operating expenses for the year ended December 31, 2021 as compared to theyear 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 GuidonAcquisition and the QEP Merger in the first quarter of 2021. The increase on aper BOE basis is primarily related to the Williston Basin assets acquired in theQEP Merger which had higher lease operating costs per BOE on average than ourhistorical properties. We completed the divestiture of the Williston Basinproperties in October 2021.Including the impact of our acquisition and divestiture activity in 2021 andfuture production plans, our total lease operating expenses in 2022 are expectedto range from approximately $539 million to $618 million.

Production and Ad Valorem Tax Expense. The following table shows production andad valorem tax expense for the years ended December 31, 2021 and 2020:

Year Ended December 31,

 2021 2020(In millions, except per BOE amounts) Amount Per BOE Amount Per BOEProduction taxes $ 349$ 2.55$ 135$ 1.23Ad valorem taxes 76 0.55 60 0.54Total production and ad valorem expense $ 425 $ 

3.10 $ 195$ 1.77

Production taxes as a % of oil, natural gas, andnatural gas liquids revenue 5.2 % 4.9 %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 anincrease in commodity prices, as well as an increase in overall production dueto assets acquired in 2021. The current year increase on a per BOE basis isprimarily driven by an increase in current year commodity prices. Productiontaxes as a percentage of production revenues increased for the year endedDecember 31, 2021 compared to the year ended December 31, 2020 due primarily tothe acquired Williston Basin properties which have a higher production tax ratethan our other properties. We completed the divestiture of the Williston Basinproperties in October 2021.Ad valorem taxes are based, among other factors, on property values driven byprior 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 millionprimarily due to additional properties acquired in the Guidon Acquisition andthe QEP Merger.

We expect production taxes to be approximately between 7% and 8% of oil, naturalgas and natural gas liquids revenue during 2022.

 51-------------------------------------------------------------------------------- Table of ContentsGathering and Transportation Expense. The following table shows gathering andtransportation expense for the year ended December 31, 2021 and 2020: Year Ended December 

31,

 2021 

2020

(In millions, except per BOE amounts) Amount Per BOE Amount

Per BOE

Gathering and transportation expense $ 212$ 1.55$ 140

$ 1.27

For the year ended December 31, 2021, the increase for gathering andtransportation expenses are primarily attributable to the increase in productionbetween periods. The current year increase on a per BOE basis is primarilydriven by production added from the assets acquired in the QEP Merger which, ingeneral, had higher average gathering and transportation costs per BOE than ourhistorical properties, particularly those QEP assets located in the WillistonBasin, which we divested in the fourth quarter of 2021. After giving effect tothe 2021 acquisition and divestiture activities, we expect gathering andtransportation expenses to range from approximately $212 to $243 million in2022.

Midstream Services Expense. The following table shows midstream services expensefor the years ended December 31, 2021 and 2020:

 Year Ended December 31, 2021 2020 (In millions)Midstream services expense $ 89$ 105Midstream services expense represents costs incurred to operate and maintain ouroil and natural gas gathering and transportation systems, natural gas lift,compression infrastructure and water transportation facilities. In the fourthquarter of 2021, we and Rattler divested our natural gas gathering andtransportation assets. Midstream services expense for the year endedDecember 31, 2021 as compared to the year ended December 31, 2020 decreased by$16 million primarily due to decreased maintenance costs, partially offset byincreased fees for use of third party disposal systems.

Depreciation, Depletion, Amortization and Accretion. The following tableprovides the components of our depreciation, depletion and amortization expensefor the years ended December 31, 2021 and 2020:

 Year Ended December 31,(In millions, except BOE amounts) 2021 2020Depletion of proved oil and natural gas properties $ 1,202$ 1,242Depreciation of midstream assets 48 44Depreciation of other property and equipment 16 18Asset retirement obligation accretion 9 7

Depreciation, depletion, amortization and accretion expense $ 1,275$ 1,311Oil and natural gas properties depletion per BOE

 $ 

8.77 $ 11.30

The decrease in depletion of proved oil and natural gas properties of $40million for the year ended December 31, 2021 as compared to the year endedDecember 31, 2020 resulted primarily from a reduction in the average depletionrate partially offset by increased production in 2021. The decline in rateresulted primarily from higher SEC oil prices utilized in the reservecalculations during 2021, lengthening the economic life of the reserve base andresulting in higher projected remaining reserve volumes on our wells.Impairment of Oil and Natural Gas Properties. No impairment expense was recordedfor the year ended December 31, 2021. In connection with the QEP Merger and theGuidon Acquisition, we recorded the oil and natural gas properties acquired atfair value. Pursuant to SEC guidance, we determined the fair value of theproperties acquired in the QEP Merger and the Guidon Acquisition clearlyexceeded the related full cost ceiling limitation beyond a reasonable doubt. Assuch, we requested and received a waiver from the SEC to exclude the acquiredproperties from the first quarter 2021 ceiling test calculation. As a result, noimpairment expense related to the QEP Merger and the Guidon Acquisition wasrecorded for the three months ended March 31, 2021. Had we not received thewaiver from the SEC, an impairment charge of approximately $1.1 billion wouldhave been recorded in the first quarter of 2021. The properties acquired in theQEP Merger and the Guidon Acquisition had total unamortized costs at March 31,2021 of $3.0 billion and $1.1 billion, respectively. 52-------------------------------------------------------------------------------- Table of ContentsAs a result of the sharp decline in commodity prices during 2020, we recordednon-cash ceiling test impairments for the year ended December 31, 2020 of $6.0billion which is included in accumulated depletion, depreciation, amortizationand impairment on our consolidated balance sheet. Impairment charges affect ourresults of operations but do not reduce our cash flow. In addition to commodityprices, our production rates, levels of proved reserves, future developmentcosts, transfers of unevaluated properties and other factors will determine ouractual ceiling test calculation and impairment analysis in future periods. Ifthe trailing 12-month commodity prices fall as compared to the commodity pricesused in prior quarters, we may have material write-downs in subsequent quarters.See Note 8- P roperty and Equipment for further details regarding factorsthat impact the impairment of oil and natural gas properties.

General and Administrative Expenses. The following table shows general andadministrative expenses for the years ended December 31, 2021 and 2020:

 Year Ended December 

31,

 2021 

2020

(In millions, except per BOE amounts) Amount Per BOE Amount Per BOEGeneral and administrative expenses $ 95$ 0.69$ 51$ 0.46Non-cash stock-based compensation 51 0.37 

37 0.34Total general and administrative expenses $ 146$ 1.06$ 88$ 0.80

General and administrative expenses for the year ended December 31, 2021 ascompared to the year ended December 31, 2020 increased by $58 million primarilydue to additional payroll and other employee driven costs of $32 million relatedto the QEP Merger and the Guidon Acquisition as well as $10 million ofadditional expense related to the implementation of a new enterprise resourceplanning system. Additionally, equity compensation for the year endedDecember 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 torange from approximately $54 million to $69 million in 2022.

Merger and Integration Expense. The following table shows merger and integrationexpense for the years ended December 31, 2021 and 2020:

 Year Ended 

December 31,

 2021 

2020

(In millions, except per BOE amounts) Amount Per BOE Amount Per BOEMerger and integration expense

$ 78$ 0.57

$ - $ -

Total merger and integration expense for the year ended December 31, 2021includes $69 million in costs incurred for the QEP Merger and $9 million incosts incurred for the Guidon Acquisition. The QEP Merger related expensesprimarily consist of $39 million in severance costs and $30 million in banking,legal and advisory fees, and the Guidon Acquisition related expenses consistprimarily of advisory and legal fees. See Note 4- Acquisitions andDivestitures for further details regarding the QEP Merger and the GuidonAcquisition. 53-------------------------------------------------------------------------------- Table of ContentsNet Interest Expense. The following table shows net interest expense for theyears ended December 31, 2021 and 2020: Year Ended December 31, 2021 2020 (In millions)Revolving credit agreements $ 11 $ 20Senior notes 252 214Amortization of debt issuance costs and discounts 18 12Other 7 10Capitalized interest (88) (55)Total 200 201Less: interest income 1 4Interest expense, net $ 199 $ 197Net interest expense increased by $2 million for the year ended December 31,2021 as compared to the year ended December 31, 2020. This increase primarilyconsisted of (i) $47 million in interest costs on the newly issued March 2021Notes (ii) $25 million due to incurring a full year of interest expense in 2021related 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 thatremained outstanding following the QEP Merger completed in March 2021. Theseincreases were partially offset by (i) $33 million in additional capitalizedinterest costs, (ii) interest cost savings of $23 million on the repurchases ofour 2025 Senior Notes in March 2021 and August 2021, (iii) $8 million on therepurchase of our 4.625% senior notes of Energen (iv) a $9 million reduction inborrowings under our revolving credit agreements during 2021, and (v) to alesser extent, interest savings on the repurchase of our 2023 Notes in November2021. We expect interest expense, net of interest income to range fromapproximately $148 million to $178 million in 2022. See Note 11- Debt forfurther details regarding outstanding borrowings and interest expense.

Derivative Instruments. The following table shows the net gain (loss) onderivative instruments and the net cash received (paid) on settlements ofderivative instruments for the years ended December 31, 2021 and 2020:

 Year Ended December 31, 2021 2020 (In millions)

Gain (loss) on derivative instruments, net $ (848)

$ (81)Net cash received (paid) on settlements(1)(2)(3) $ (1,225)

$ 250

(1)The year ended December 31, 2021 includes cash paid on commodity contractsterminated prior to their contractual maturity of $16 million.(2)The year ended December 31, 2020 includes cash received on commoditycontracts terminated prior to their contractual maturity of $17 million.(3)The year ended December 31, 2021 includes cash received on interest rate swapcontracts terminated prior to their contractual maturity of $80 million.We are required to recognize all derivative instruments on the balance sheet aseither assets or liabilities measured at fair value. We have not designated ourcommodity derivative instruments as hedges for accounting purposes. As a result,we mark our derivative instruments to fair value and recognize the cash andnon-cash changes in fair value on derivative instruments in our consolidatedstatements of operations under the line item captioned "Gain (loss) onderivative instruments, net." As part of the QEP Merger, we received by novationfrom QEP certain derivative instruments which are included on our balance sheetas of December 31, 2021.We have designated certain of our interest rate swaps as fair value hedges foraccounting purposes. As a result, gains and losses due to changes in the fairvalue of the interest rate swaps completely offset changes in the fair value ofthe hedged portion of the underlying debt and no gain or loss is recognized dueto hedge effectiveness. Changes in fair value are recorded as an adjustment tothe carrying value of the 2029 Notes in the consolidated balance sheet.Beginning on December 1, 2021, we began recording semi-annual cash settlementsof these interest rate swaps in interest expense in the consolidated statementsof operations. 54-------------------------------------------------------------------------------- Table of ContentsAt December 31, 2021, we have a short-term derivative asset of $13 million, along-term derivative asset of $4 million, a short-term derivative liability duein 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 theprovision for (benefit from) income taxes for the years ended December 31, 2021and 2020: Year Ended December 31, 2021 2020 (In millions)Provision for (benefit from) income taxes $ 631 $ 

(1,104)

The changes in our income tax provision for the year ended December 31, 2021compared to the same period in 2020 were primarily due to the increase inpre-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 fromoperations, proceeds from our public equity offerings, borrowings under ourrevolving credit facility, proceeds from the issuance of senior notes and salesof 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 billionin cash and cash equivalents and $1.6 billion available under our creditfacility. 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 thenext 12 months.Our working capital requirements are supported by our cash and cash equivalentsand our credit facility. We may draw on our revolving credit facility to meetshort-term cash requirements, or issue debt or equity securities as part of ourlonger-term liquidity and capital management program. Because of thealternatives available to us as discussed above, we believe that our short-termand long-term liquidity are adequate to fund not only our current operations,but also our near-term and long-term funding requirements including our capitalspending programs, dividend payments, debt service obligations and repayment ofdebt maturities, stock repurchase program and other amounts that may ultimatelybe paid in connection with contingencies.Future cash flows are subject to a number of variables, including the level ofoil and natural gas production and prices, and significant additional capitalexpenditures will be required to more fully develop our properties. In order tomitigate this volatility, we entered into derivative contracts with a number offinancial institutions, all of which are participants in our credit facility,hedging a portion of our estimated future crude oil and natural gas productionthrough the end of 2023 as discussed further in Note 15- Derivatives and Item 7A. Quantitative and Qualitative Disclosures About Market Risk-CommodityPrice Risk . The level of our hedging activity and duration of the financialinstruments employed depend on our desired cash flow protection, available hedgeprices, the magnitude of our capital program and our operating strategy.As we pursue our business and financial strategy, we regularly consider whichcapital resources, including cash flow and equity and debt financings, areavailable to meet our future financial obligations, planned capital expenditureactivities and liquidity requirements. Our future ability to grow provedreserves and production will be highly dependent on the capital resourcesavailable to us. Continued prolonged volatility in the capital, financial and/orcredit markets due to the COVID-19 pandemic, the depressed commodity marketsand/or adverse macroeconomic conditions may limit our access to, or increase ourcost of, capital or make capital unavailable on terms acceptable to us or atall. Although the Company expects that its sources of funding will be adequateto fund its short-term and long-term liquidity requirements, we cannot assureyou that the needed capital will be available on acceptable terms or at all. 55-------------------------------------------------------------------------------- Table of ContentsCash FlowOur cash flows for the years ended December 31, 2021 and 2020 are presentedbelow: Year Ended December 31, 2021 2020 (In millions)

Net cash provided by (used in) operating activities $ 3,944

$ 2,118Net cash provided by (used in) investing activities (1,539) 

(2,101)

Net cash provided by (used in) financing activities (1,841)

 (37)Net change in cash $ 564$ (20)Operating ActivitiesOur operating cash flow is sensitive to many variables, the most significant ofwhich is the volatility of prices for the oil and natural gas we produce. Pricesfor these commodities are determined primarily by prevailing market conditions.Regional and worldwide economic activity, weather and other substantiallyvariable factors influence market conditions for these products. These factorsare beyond our control and are difficult to predict. See Item 1A. "RiskFactors" above.The increase in operating cash flows for the year ended December 31, 2021compared to the same period in 2020 primarily resulted from (i) an increase of$4.0 billion in our total revenues, and (ii) receipt of $152 million in refundsof income taxes receivable related to the carryback of federal net operatinglosses and the accelerated refund of minimum tax credits allowed under the CARESAct in 2020. These net cash inflows were partially offset by (i) a reduction of$1.5 billion due to making net cash payments of $1.2 billion on our derivativecontracts in the year ended December 31, 2021 compared to receiving net cash of$250 million on our derivative contracts in the year ended December 31, 2020,(ii) an increase in our cash operating expenses of approximately $550 millionprimarily due to the QEP Merger and the Guidon Acquisition, and (iii) otherworking capital changes, primarily due to recording increases in accountsreceivable, accounts payable and accrued capital expenditure activity stemmingfrom the QEP Merger and the Guidon Acquisition in 2021. See " - Results ofOperations " for discussion of significant changes in our revenues andexpenses.

Investing Activities

Net cash used in investing activities was $1.5 billion compared to $2.1 billionfor the years ended December 31, 2021 and 2020, respectively. The majority ofour net cash used for investing activities during the year ended December 31,2021 was for the purchase and development of oil and natural gas properties andrelated assets, including the acquisition of certain leasehold interests as partof the Guidon Acquisition. These expenditures were partially offset by proceedsfrom the sale of our Williston Basin assets, leasehold acreage and othergathering assets discussed in Note 4- Acquisitions and Divestitures .The majority of our net cash used in investing activities during the year endedDecember 31, 2020 was for drilling and completion costs in conjunction with ourdevelopment program. Our capital expenditures for each period are discussedfurther below. 56-------------------------------------------------------------------------------- Table of ContentsCapital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments(on a cash basis) were as follows for the specified period:

 Year Ended December 31, 2021 2020 

(In millions)Drilling, completions and non-operated additions to oil and naturalgas properties(1)(2)

$ 1,334$ 1,611Infrastructure additions to oil and natural gas properties 123 108Additions to midstream assets 30 140Total $ 1,487$ 1,859(1) During the year ended December 31, 2021, in conjunction with our developmentprogram, we drilled 216 gross (203 net) operated horizontal wells, of which 175gross (165 net) wells were in the Midland Basin and 41 gross (38 net) wells werein the Delaware Basin, and turned 275 gross (258 net) operated horizontal wellsto production, of which 207 gross (194 net) were in the Midland Basin and 64gross (61 net) wells were in the Delaware Basin.(2) During the year ended December 31, 2020, in conjunction with our developmentprogram, we drilled 208 gross (195 net) operated horizontal wells, of which 133gross (125 net) wells were in the Midland Basin and 75 gross (70 net) wells werein the Delaware Basin, and turned 171 gross (159 net) operated horizontal wellsto production, of which 93 gross (85 net) were in the Midland Basin and 78 gross(74 net) wells were in the Delaware Basin.

Financing Activities

Net cash used in financing activities for the year ended December 31, 2021 was$1.8 billion compared to net cash used in financing activities for the yearended December 31, 2020 of $37 million. During the year ended December 31, 2021,the amount used in financing activities was primarily attributable to (i) $3.2billion paid for the repurchase of outstanding principal on certain senior notesas discussed in "-Repurchases of Notes" below, as well as $178 million ofadditional premiums paid in connection with the repurchases, (ii) $525 millionof repurchases as part of the share and unit repurchase programs, (iii) $312million of dividends paid to stockholders, and (iv) $112 million indistributions to non-controlling interest. The cash outflows were partiallyoffset by (i) $2.2 billion in proceeds from the March 2021 Notes, (ii) $313million of borrowings under our and our subsidiaries' credit facilities, net ofrepayments and (iii) $22 million in net cash receipts from the early settlementof interest rate swaps and commodity derivative contracts that contained another-than-insignificant financing element.Net cash used in financing activities for the year ended December 31, 2020 wasprimarily attributable to $348 million of repayments, net of borrowings, on ourcredit facilities, $239 million in aggregate repayments on the Energen Notes andViper Notes, $236 million in dividends paid to stockholders, $98 million ofshare repurchases as part of our stock repurchase program, and $93 million indistributions to non-controlling interest. These cash outlays were partiallyoffset by net proceeds of $997 million from the issuance of the May 2020 Notesand the Rattler Notes during 2020.

Capital Resources

Revolving Credit Facilities and Other Debt Instruments

As of December 31, 2021, our debt, including the debt of Viper and Rattler,consists of approximately $6.2 billion in aggregate outstanding principal amountof senior notes, $499 million in aggregate outstanding borrowings underrevolving credit facilities and $58 million in outstanding amounts due under ourDrillCo Agreement.At December 31, 2021, we have total principal payments due on our outstandingsenior notes, including those of Viper and Rattler, of $45 million in 2022, $1.2billion cumulatively in the years 2023 through 2024, $2.1 billion cumulativelyin the years 2025 and 2026, and $3.4 billion thereafter. Additionally, we expectto incur future cash interest costs on these senior notes of approximately$177 million in 2022, $371 million in the years from 2023 through 2024,$277 million in the years from 2025 through 2026, and $961 million between 2027and 2051.On June 2, 2021, we entered into a twelfth amendment, or the Amendment, to theSecond Amended and Restated Credit Agreement which, among other things,decreased the total revolving loan commitments from $2.0 billion to $1.6billion, which may be increased in an amount up to $1.0 billion (for a totalmaximum commitment amount of $2.6 billion) upon election of the Borrower,subject to obtaining additional lender commitments and satisfaction of customaryconditions). As of December 31, 2021, we had no outstanding borrowings under ourrevolving credit facility and $1.6 billion available for future borrowings underthe revolving credit facility. 57

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Viper's Revolving Credit Facility

Viper's credit agreement, as amended to date, provides for a revolving creditfacility in the maximum credit amount of $2.0 billion, with a borrowing base of$580 million as of December 31, 2021, based on the Viper's oil and natural gasreserves and other factors. At December 31, 2021, Viper had elected a commitmentamount of $500 million on its credit agreement with $304 million of outstandingborrowings. During the year ended December 31, 2021, the weighted averageinterest rate on borrowings under the Operating Company's revolving creditfacility was 2.35%. Viper's Revolving credit facility matures in 2025.

Rattler's Revolving Credit Facility

Rattler's credit agreement provides for a revolving credit facility in themaximum credit amount of $600 million, which is expandable to $1.0 billion uponits election, subject to obtaining additional lender commitments andsatisfaction of customary conditions. As of December 31, 2021, there was$195 million of outstanding borrowings under Rattler's revolving creditfacility. The weighted average interest rate on borrowings under the creditagreement was 1.41% for the year ended December 31, 2021. Rattler's revolvingcredit facility matures in 2024.

During 2021, we issued an aggregate $2.2 billion of senior notes and redeemed$3.2 billion of senior notes outstanding.

For additional discussion of our outstanding debt as of December 31, 2021, seeNote 11- Debt .

Subject to market conditions, we expect to continue to issue debt securitiesfrom time to time in the future to refinance our maturing debt. Theavailability, interest rate and other terms of any new borrowings will depend onthe ratings assigned by credit rating agencies, among other factors.

We are currently in compliance, and expect to continue to be, with all financialmaintenance covenants in our debt instruments.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. Indetermining our debt ratings, the agencies consider a number of qualitative andquantitative items including, but not limited to, commodity pricing levels, ourliquidity, asset quality, reserve mix, debt levels, cost structure, plannedasset sales and production growth opportunities. Our credit rating from Standardand Poor's Global Ratings Services is BBB-. Our credit rating from FitchInvestor Services is BBB. Our credit rating from Moody's Investor Services isBaa3. Any rating downgrades may result in additional letters of credit or cashcollateral being posted under certain contractual arrangements.

Capital Requirements

In addition to future operating expenses and working capital commitmentsdiscussed in - Results of Operations , our primary short and long-termliquidity requirements consist primarily of (i) capital expenditures, (ii)payments of other contractual obligations and (iii) cash commitments fordividends and share repurchases as discussed below.

Based upon current oil and natural gas prices and production expectations for2022, we believe that our cash flow from operations, cash on hand and borrowingsunder our revolving credit facility will be sufficient to fund our operationsthrough the 12-month period following the filing of this report and thereafter.However, future cash flows are subject to a number of variables, including thelevel of oil and natural gas production and prices, and significant additionalcapital expenditures will be required to more fully develop our properties. Wecannot assure you that the needed capital will be available on acceptable termsor at all. Further, our 2022 capital expenditure budget does not allocate anyfunds for leasehold interest and property acquisitions. 58-------------------------------------------------------------------------------- Table of Contents2022 Capital Spending Plan Our board of directors approved a 2022 capital budget for drilling, midstreamand infrastructure of $1.75 billion to $1.90 billion maintaining our annualizedfourth quarter 2021 cash capital expenditure guidance presented in November of2021. We estimate that, of these expenditures, approximately:•$1.56 billion to $1.67 billion will be spent primarily on drilling 270 to 290gross (248 to 267 net) horizontal wells and completing 260 to 280 gross (240 to258 net) horizontal wells across our operated and non-operated leasehold acreagein the Northern Midland and Southern Delaware Basins, with an average laterallength of approximately 10,200 feet;•$80 million to $100 million will be spent on midstream infrastructure,excluding joint venture investments; and•$110 million to $130 million will be spent on infrastructure and environmentalexpenditures, excluding the cost of any leasehold and mineral interestacquisitions.

We do not have a specific acquisition budget since the timing and size ofacquisitions cannot be accurately forecasted.

The amount and timing of our capital expenditures are largely discretionary andwithin our control. We could choose to defer a portion of these planned capitalexpenditures depending on a variety of factors, including but not limited to thesuccess of our drilling activities, prevailing and anticipated prices for oiland natural gas, the availability of necessary equipment, infrastructure andcapital, the receipt and timing of required regulatory permits and approvals,seasonal conditions, drilling and acquisition costs and the level ofparticipation by other interest owners. We were operating 10 drilling rigs andfour completion crews at December 31, 2021 and currently intend to operatebetween 10 and 12 rigs and between three and four completion crews on average in2022, as we continue to execute on our strategy to hold oil production flatwhile using cash flow from operations to reduce debt, strengthen our balancesheet and return capital to our stockholders. We will continue monitoringcommodity prices and overall market conditions and can adjust our rig cadenceand our capital expenditure budget up or down in response to changes incommodity prices and overall market conditions.

Other Contractual Obligations and Commitments

At December 31, 2021, our other significant contractual obligations consistprimarily of (i) minimum transportation commitments totaling $878 million, (ii)asset retirement obligations totaling $171 million, and (iii) minimum purchasecommitment for quantities of sand used in our drilling operations totaling $77million. We expect to make aggregate payments of approximately $105 million forthese commitments during 2022. See Note 9- Asset Retirement Obligations andNote 18- Commitments and Contingencies for further discussion of these andother contractual obligations and commitments.

Dividends and Share Repurchases

We paid common stock dividends of $312 million and $236 million during 2021 and2020, respectively. On February 18, 2022, our board of directors declared a cashdividend 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 businesson March 4, 2022. The decision to pay any future dividends is solely within thediscretion of, and subject to approval by, our board of directors.In September 2021, our board of directors approved a stock repurchase program toacquire up to $2 billion of our outstanding common stock. The stock repurchaseprogram has no time limit and may be suspended, modified, or discontinued by theboard of directors at any time. We repurchased approximately $431 million of ourcommon stock under this program during the year ended December 31, 2021, andhave $1.6 billion remaining for future repurchases under the repurchase programat December 31, 2021 See Note 12- Stockholders' Equity and Earnings Per Sharefor further discussion of the repurchase program.

Guarantor Financial Information

In connection with the merger of certain of the Company's wholly ownedsubsidiaries in an internal subsidiary restructuring on June 30, 2021,Diamondback E&P became the successor borrower to Diamondback O&G LLC ("O&G")under the credit agreement, the successor issuer of Energen's 7.125% Medium-termNotes, Series B, due February 15, 2028 and Energen's 7.32% Medium-term Notes,Series A, due July 28, 2022, and the sole guarantor under the indenturesgoverning the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes andthe March 2021 Notes. 59-------------------------------------------------------------------------------- Table of ContentsGuarantees are "full and unconditional," as that term is used in Regulation S-X,Rule 3-10(b)(3), except that such guarantees will be released or terminated incertain circumstances set forth in the IG Indenture and the 2025 Indenture, suchas, with certain exceptions, (i) in the event Diamondback E&P (or all orsubstantially all of its assets) is sold or disposed of, (ii) in the eventDiamondback E&P ceases to be a guarantor of or otherwise be an obligor undercertain other indebtedness, and (iii) in connection with any covenantdefeasance, legal defeasance or satisfaction and discharge of the relevantindenture. The 2025 Indenture was terminated in connection with the earlyredemption of the remaining $432 million principal amount of our 2025 SeniorNotes in the third quarter of 2021.Diamondback E&P's guarantees of the December 2019 Notes, the May 2020 Notes andthe March 2021 Notes are senior unsecured obligations and rank senior in rightof payment to any of its future subordinated indebtedness, equal in right ofpayment with all of its existing and future senior indebtedness, including itsobligations under its revolving credit facility, and effectively subordinated toany of its existing and future secured indebtedness, to the extent of the valueof the collateral securing such indebtedness.The rights of holders of the Senior Notes against Diamondback E&P may be limitedunder the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law.Each guarantee contains a provision intended to limit Diamondback E&P'sliability to the maximum amount that it could incur without causing theincurrence of obligations under its guarantee to be a fraudulent conveyance.However, there can be no assurance as to what standard a court will apply inmaking a determination of the maximum liability of Diamondback E&P. Moreover,this provision may not be effective to protect the guarantee from being voidedunder fraudulent conveyance laws. There is a possibility that the entireguarantee may be set aside, in which case the entire liability may beextinguished.The following tables present summarized financial information for DiamondbackEnergy, Inc., as the parent, and Diamondback E&P, as the guarantor subsidiary,on a combined basis after elimination of (i) intercompany transactions andbalances between the parent and the guarantor subsidiary and (ii) equity inearnings from and investments in any subsidiary that is a non-guarantor. Theinformation is presented in accordance with the requirements of Rule 13-01 underthe SEC's Regulation S-X. The financial information may not necessarily beindicative of results of operations or financial position had the guarantorsubsidiary operated as an independent entity. December 31, 2021Summarized Balance Sheets: (In millions)Assets:Current assets $ 1,148Property and equipment, net $ 14,778Other noncurrent assets $ 55Liabilities:Current liabilities $ 1,221Intercompany accounts payable, non-guarantor subsidiary $ 1,440Long-term debt $ 5,093Other noncurrent liabilities $ 1,549 Year Ended December 31, 2021Summarized Statement of Operations: (In millions)Revenues $ 5,049Income (loss) from operations $ 2,898Net income (loss) $ 1,348 60

-------------------------------------------------------------------------------- Table of ContentsCritical Accounting EstimatesThe discussion and analysis of our financial condition and results of operationsare based upon our consolidated financial statements, which have been preparedin accordance with accounting principles generally accepted in the UnitedStates.Certain amounts included in or affecting our consolidated financial statementsand related disclosures must be estimated by our management, requiring certainassumptions to be made with respect to values or conditions that cannot be knownwith certainty at the time the consolidated financial statements are prepared.These estimates and assumptions affect the amounts we report for assets andliabilities and our disclosure of contingent assets and liabilities at the dateof the consolidated financial statements and the reported amounts of revenuesand expenses during the reporting period. We evaluate our estimates andassumptions on a regular basis. Critical accounting estimates are thoseestimates made in accordance with generally accepted accounting principles thatinvolve a significant level of estimation uncertainty and have had or arereasonably likely to have a material impact on the financial condition orresults of operations of the registrant. Any effects on our business, financialposition or results of operations resulting from revisions to these estimatesare recorded in the period in which the facts that give rise to the revisionbecome known.We consider the following to be our most critical accounting estimates and havereviewed these critical accounting estimates with the Audit Committee of ourBoard of Directors.

Oil and Natural Gas Accounting and Reserves

We account for our oil and natural gas producing activities using the full costmethod of accounting, which is dependent on the estimation of proved reserves todetermine the rate at which we record depletion on our oil and natural gasproperties and whether the value of our evaluated oil and natural gas propertiesis permanently impaired based on the quarterly full cost ceiling impairmenttest. Further, we utilize estimated proved reserves to assign fair value toacquired proved oil and natural gas properties including mineral and royaltyinterests. As such, we consider the estimation of proved reserves to be acritical accounting estimate.Oil and natural gas reserve engineering is a subjective process of estimatingunderground accumulations of oil and natural gas that cannot be preciselymeasured and the accuracy of any reserve estimate is a function of the qualityof available data and of engineering and geological interpretation and judgment.Our independent engineers and technical staff prepare our estimates of oil andnatural gas reserves and their associated future net cash flows. The process ofestimating oil and natural gas reserves is complex, requiring significantdecisions in the evaluation of available geological, geophysical, engineeringand economic data. Significant inputs included in the calculation of future netcash flows include our estimate of operating and development costs, anticipatedproduction of proved reserves and other relevant data. The data for a givenproperty may also change substantially over time as a result of numerousfactors, including additional development activity, evolving production historyand a continual reassessment of the viability of production under changingeconomic conditions. As a result, material revisions to existing reserveestimates occur from time to time, and reserve estimates are often differentfrom the quantities of oil and natural gas that are ultimately recovered.Although every reasonable effort is made to ensure that reserve estimatesreported represent the most accurate assessments possible, the subjectivedecisions and variances in available data for various properties increase thelikelihood of significant changes in these estimates. If such changes arematerial, they could significantly affect future depletion of capitalized costsand result in impairment of assets that may be material. Revisions of previousreserve estimates accounted for approximately $719 million, or 6% of the changein the standardized measure of our total reserves from December 31, 2020 toDecember 31, 2021. No impairments were recorded on for our proved oil and gasproperties during the year ended December 31, 2021; however, materialimpairments were recorded during the years ended December 31, 2020 and 2019 asdiscussed further in Note 8- Property and Equipment of the notes to theconsolidated financial statements included elsewhere in this Annual Report. Dueto an increase in the historical 12-month average trailing SEC prices for oiland natural throughout 2021 and into 2022, we are not currently projecting afull cost ceiling impairment in the first quarter of 2022.Additionally, costs associated with unevaluated properties are excluded from thefull cost pool until we have made a determination as to the existence of provedreserves. We assess all items classified as unevaluated property (on anindividual basis or as a group if properties are individually insignificant) onan annual basis for possible impairment. This assessment is subjective andincludes consideration of the following factors, among others: intent of theoperator to drill, remaining lease term with the current operator; geologicaland geophysical evaluations; drilling results and activity; the assignment ofproved reserves; and the economic viability of development if proved reservesare assigned. At December 31, 2021, our unevaluated properties totaled $8billion, which consisted of 214,151 net undeveloped leasehold acres withapproximately 41,855 net acres set to expire in 2022. We did not record anyimpairment on our unevaluated properties during the year ended December 31,2021, but any such future impairment could be material to our consolidatedfinancial statements. 61

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Commodity Derivatives

From time to time, we use commodity derivatives for the purpose of mitigatingthe risk resulting from fluctuations in the market price of crude oil andnatural gas. We exercise significant judgment in determining the types ofinstruments to be used, the level of production volumes to include in ourcommodity derivative contracts, the prices at which we enter into commodityderivative contracts and the counterparties' creditworthiness. We do not usethese instruments for speculative or trading purposes.We have not designated our derivative instruments as hedges for accountingpurposes and, as a result, mark our derivative instruments to fair value andrecognize the cash and non-cash change in fair value on derivative instrumentsfor each period in the consolidated statements of operations. We are alsorequired to recognize our derivative instruments on the consolidated balancesheets as assets or liabilities at fair value with such amounts classified ascurrent or long-term based on their anticipated settlement dates. The accountingfor the changes in fair value of a derivative depends on the intended use of thederivative and resulting designation, and is generally determined using variousinputs and assumptions including established index prices and other sourceswhich are based upon, among other things, futures prices, time to maturity,implied volatilities and counterparty credit risk.These fair values are recorded by netting asset and liability positions,including any deferred premiums, that are with the same counterparty and aresubject to contractual terms which provide for net settlement. Changes in thefair values of our commodity derivative instruments have a significant impact onour net income because we follow mark-to-market accounting and recognize allgains and losses on such instruments in earnings in the period in which theyoccur.

See Item 7A. Quantitative and Qualitative Disclosures About MarketRisk-Commodity Price Risk for additional sensitivity analysis of our openderivative positions at December 31, 2021.

Business Combinations

We account for business combinations using the acquisition method of accounting.Accordingly, identifiable assets acquired and liabilities assumed are recognizedat the date of acquisition at their respective estimated fair values.We make various assumptions in estimating the fair values of assets acquired andliabilities assumed. Fair value estimates are determined based on informationthat existed at the time of the acquisition, utilizing expectations andassumptions that would be available to and made by a market participant. Whenmarket-observable prices are not available to value assets and liabilities, theCompany may use the cost, income, or market valuation approaches depending onthe quality of information available to support management's assumptions.The most significant assumptions relate to the estimated fair values assigned toproved and unproved oil and natural gas properties. The assumptions made inperforming these valuations include future production volumes, future commodityprices and costs, future operating and development activities, projections ofoil and gas reserves and a weighted average cost of capital rate. Themarket-based weighted average cost of capital rate is subjected to additionalproject-specific risking factors. In addition, when appropriate, we reviewcomparable purchases and sales of natural gas and oil properties within the sameregions, and use that data as a proxy for fair market value; for example, theamount a willing buyer and seller would enter into in exchange for suchproperties. Changes in key assumptions may cause the acquisition accounting tobe revised, including the recognition of additional goodwill or discount onacquisition. There is no assurance the underlying assumptions or estimatesassociated with the valuation will occur as initially expected. See Note4- Acquisitions and Divestitures of the notes to the consolidated financialstatements included elsewhere in this Annual Report for further discussion ofthe estimated fair value of assets acquired and liabilities assumed in the QEPMerger and Guidon Acquisition, including any significant changes in theseestimates from the date of acquisition.Estimated fair values assigned to assets acquired can have a significant effecton results of operations in the future. In addition, differences between thefuture commodity prices when acquiring assets and the historical 12-monthaverage trailing price to calculate ceiling test impairments of upstream assetsmay impact net earnings.Income TaxesThe amount of income taxes we record requires interpretations of complex rulesand regulations of federal, state, and provincial tax jurisdictions. We use theasset and liability method of accounting for income taxes, under which deferredtax assets and liabilities are recognized for the future tax consequences of (1)temporary differences between the financial statement carrying amounts and thetax bases of existing assets and liabilities and (2) operating loss and taxcredit 62-------------------------------------------------------------------------------- Table of Contentscarryforwards. Deferred income tax assets and liabilities are based on enactedtax rates applicable to the future period when those temporary differences areexpected to be recovered or settled. The effect of a change in tax rates ondeferred tax assets and liabilities is recognized in income in the period therate change is enacted. A valuation allowance is provided for deferred taxassets when it is more likely than not the deferred tax assets will not berealized.The assessment of the realizability of our deferred tax assets, including theassessment of whether a valuation allowance is required, entails that we makeestimates of, and assumptions about, future events, including the pattern ofreversal of taxable temporary differences and our future income from operations.As of December 31, 2021, we had established a total valuation allowance of $315million, including a valuation allowance for the full amount of Viper's deferredtax assets. The valuation allowance remains in place based on the uncertainty offuture events, including Viper's ability to generate future taxable income inexcess of special allocations to be made to Diamondback, and managementconsidered this and other factors in evaluating the realizability of Viper'sdeferred tax assets. No such valuation allowance was determined to be necessaryagainst Rattler's deferred tax assets as of December 31, 2021 based on therelative predictability of its future income stream based on its long termcustomer contracts. Any changes in the positive or negative evidence evaluatedwhen determining if Viper's or Rattler's deferred tax assets will be realized,including projected future income, could result in a material change to ourconsolidated financial statements. In addition, the determination to record avaluation allowance on certain tax attributes acquired from QEP and certainstate NOL carryforwards which the Company does not believe are realizable priorto expiration was based on an evaluation of available positive and negativeevidence, including the annual limitation imposed by IRC Section 382 subsequentto an ownership change and the anticipated timing of reversal of the Company'sdeferred tax liabilities in the applicable jurisdictions. As of December 31,2021, although the Company's recent cumulative losses represent negativeevidence regarding reliance on future taxable income exclusive of reversingtemporary differences, our balance of taxable temporary differences anticipatedto reverse within the carryforward period provides significant positive evidencefor the determination that our remaining deferred tax assets are more likelythan not to be realized. Any change in the positive or negative evidenceevaluated when determining if our deferred tax assets will be realized,including projected future taxable income primarily related to the excess ofbook carrying value over tax basis of our oil and natural gas properties, couldresult in a material change to our consolidated financial statements.The accruals for deferred tax assets and liabilities are often based onuncertain tax positions and assumptions that are subject to a significant amountof judgment by management. These assumptions and judgments are reviewed andadjusted as facts and circumstances change. At December 31, 2021, our uncertaintax positions were insignificant, however, material changes to our income taxaccruals may occur in the future based on the progress of ongoing audits,changes in legislation or resolution of pending matters.

Recent Accounting Pronouncements

See Note 2- Summary of Significant Accounting Policies included in notes tothe consolidated financial statements included elsewhere in this Annual Reportfor recent accounting pronouncements and accounting policies not yet adopted, ifany.

Off-Balance Sheet Arrangements

Please read Note 18- Commitments and Contingencies included in notes to theconsolidated financial statements included elsewhere in this Form 10-K for adiscussion of our commitments and contingencies, some of which are notrecognized in the consolidated balance sheets under GAAP.

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