DIAMONDBACK ENERGY, INC. MANAGEMENT REPORT AND ANALYSIS OF FINANCIAL POSITION AND OPERATING RESULTS (Form 10-K)
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."
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 Basinin 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 Basinin West Texasand (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 Midlandand 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 Operational Highlights
•We recorded a net profit of
• Our average production was 137,002 MBOE/d during the year ended
• During the year ended
•We turned 275 gross operated horizontal wells (including 207 in the
Midland Basinand 64 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $1.5 billionduring the year ended December 31, 2021.
• The average lateral length of wells completed during the year ended
December 31, 2021, we had approximately 445,848 net acres, which primarily consisted of approximately 265,562 net acres in the Midland Basinand 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 $50.00per 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 Basinand Eagle Ford Shale. Approximately 54% of these net royalty acres are operated by us. •Our cash operating costs for the year ended December 31, 2021were $9.46per BOE, including lease operating expenses of $4.12per BOE, cash general and administrative expenses of $0.69per BOE and production and ad valorem taxes and gathering and transportation expenses of 4.65 per BOE.
2021 transactions and recent developments
Acquisition activity and recent transactions in 2021
March 17, 2021, we completed the QEP Merger. The addition of QEP's assets increased our net acreage in the Midland Basinby 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 millionon the closing date. 46 -------------------------------------------------------------------------------- Table of Contents On October 1, 2021, Viper completed the acquisition of certain mineral and royalty interests from Swallowtail Royalties LLCand 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 millionin cash (the "Swallowtail Acquisition"). The cash portion of the purchase price was funded through a combination of cash on hand and approximately $190 millionof borrowings under Viper LLC'srevolving 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 millionin 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").
Disposal activity 2021
June 3, 2021and 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 Basinacreage in Upton county, Texasand approximately 1,300 net acres of non-core, non-operated Delaware Basinassets 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 Basinoil and natural gas assets, consisting of approximately 95,000 net acres acquired in the QEP Merger, for net cash proceeds of approximately $586 millionafter 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 millionto 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 millionat closing, after customary closing adjustments, and an aggregate of $10 millionin contingent payments.
See Note 4 – Acquisitions and Disposals for additional discussion of these transactions.
Debt Transactions Issuances of Notes On
March 24, 2021, Diamondback Energy, Inc.issued $650 millionaggregate principal amount of 0.900% Senior Notes due March 24, 2023(the "2023 Notes"), $900 millionaggregate principal amount of 3.125% Senior Notes due March 24, 2031(the "2031 Notes") and $650 millionaggregate principal amount of 4.400% Senior Notes due March 24, 2051(the "2051 Notes") and received proceeds, net of $24 millionin 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.
Refund of Notes
The net proceeds from the
March 2021Notes discussed above were primarily used to fund the repurchase of $1.65 billionin 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 millionprincipal 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 millionin addition to an estimated $60to $80 millionof previously announced expected annual cost synergies from the QEP Merger.
August 2021we redeemed the remaining $432 millionprincipal 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. 47 -------------------------------------------------------------------------------- Table of Contents On November 1, 2021, we redeemed the aggregate $650 millionprincipal amount of our outstanding 2023 Notes with the proceeds received from the divestiture of our Williston Basinassets and cash on hand.
For more information on our debt transactions in 2021 and the modification of the Amended and Restated Second Credit Facility, see Note 11 – Debt t .
Declaration and increase of the fourth quarter 2021 dividend
February 18, 2022, our board of directors declared a cash dividend for the fourth quarter of 2021 of $0.60per share of common stock, payable on March 11, 2022to 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.
Share and unit buyback programs
During the year ended
remained available for future purchases under our common stock repurchase program.
During the year ended
December 31, 2021, Viper repurchased approximately $46 millionof common units under its repurchase program. As of December 31, 2021, $80 millionremained 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 millionof common units under its repurchase program. As of December 31, 2021, $88 millionremained available for use to repurchase common units under Rattler's common unit repurchase program.
See “- Liquidity and Capital Resources” below for further discussion.
COVID-19 and effects on commodity prices
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 OPECmembers 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 Texasintermediate light sweet crude oil, or NYMEX WTI, has ranged from $(37.63)to $84.65Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.48to $6.31per MMBtu. On January 18, 2022, the closing NYMEX WTI price for crude oil was $85.43per Bbl and the closing NYMEX Henry Hub price of natural gas was $4.28per 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, OPECand its non- OPECallies, 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, OPECnoted 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 have kept our production relatively stable in 2021, using excess cash flow for debt repayment and/or return to our shareholders rather than expand our drilling program.
48 -------------------------------------------------------------------------------- Table of Contents 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 Basindrilling and completion programs, were able to mitigate certain inflationary pressures on well costs and led to a total capital expenditure amount of $1.5 billiondown 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.
counties, where development has primarily focused on drilling multi-well longitudinal rigs targeting the Spraberry and Wolfcamp formations.
Delaware Basin, we have now drilled and completed a significant number of wells in Pecos, Reevesand Wardcounties 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 Midlandand Delaware Basins.
Environmental Responsibility Initiatives and Highlights
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 investment budget
We have currently budgeted total capital expenditures for 2022 of
The following discussion focuses primarily on a comparison of the results of operations between the years ended
December 31, 2021and 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, 2020as 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 SECon February 25, 2021), which is incorporated in this report by reference from such prior report on Form 10-K. 49
The following table sets forth selected historical operating data for the periods indicated: Year Ended December 31, 2021 2020 Revenues (in millions): Oil sales
$ 5,396 $ 2,410Natural gas sales 569 107 Natural gas liquid sales 782 239
Total oil, natural gas and natural gas liquids revenues
$ 2,756Production Data: Oil (MBbls) 81,522 66,182 Natural gas (MMcf) 169,406 130,549 Natural gas liquids (MBbls) 27,246 21,981 Combined volumes (MBOE)(1) 137,002 109,921 Daily oil volumes (BO/d) 223,348 180,825 Daily combined volumes (BOE/d)(1) 375,348 300,331 Average 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
(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.
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, 2021and 2020: Year Ended December 31, 2021 2020 Oil (MBbls) 60 % 60 % Natural gas (MMcf) 20 % 20 % Natural gas liquids (MBbls) 20 % 20 % 100 % 100 %
Comparison of the years ended
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. 50 -------------------------------------------------------------------------------- Table of Contents Our oil, natural gas and natural gas liquids revenues increased by approximately
$4.0 billion, or 145%, to $6.7 billionfor the year ended December 31, 2021from $2.8 billionfor 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 billionof 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 operating expenses for leases for the years ended
Year Ended December
(In millions, except per boe amounts) Amount Per boe Amount
Per BOE Lease operating expenses
$ 565 $ 4.12 $ 425 $ 3.87Lease operating expenses for the year ended December 31, 2021as compared to the year ended December 31, 2020increased by $140 million, or $0.25per 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 Basinassets 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 Basinproperties 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 millionto $618 million.
Production and ad valorem tax expenditures. The following table shows production and ad valorem tax expense for the years ended
2021 2020 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Production taxes
$ 349 $ 2.55 $ 135 $ 1.23Ad valorem taxes 76 0.55 60 0.54 Total production and ad valorem expense $ 425$
Production taxes as a % of oil, natural gas, and natural 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, 2021increased by $214 million, or $1.32per 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, 2021compared to the year ended December 31, 2020due primarily to the acquired Williston Basinproperties which have a higher production tax rate than 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 by prior year commodity prices. Ad valorem taxes for the year ended December 31, 2021as compared to the year ended December 31, 2020increased by $16 millionprimarily due to additional properties acquired in the Guidon Acquisition and the QEP Merger.
We expect production taxes to represent approximately 7% to 8% of oil, natural gas and natural gas liquids revenues in 2022.
51 -------------------------------------------------------------------------------- Table of Contents Gathering and Transportation Expense. The following table shows gathering and transportation expense for the year ended
December 31, 2021and 2020: Year Ended December
(In millions, except per boe amounts) Amount Per boe Amount
Assembly and transport costs
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 $212to $243 millionin 2022.
Intermediate service expenses. The following table presents the intermediate services expenses for the years ended
Year Ended December 31, 2021 2020 (In millions) Midstream services expense
$ 89 $ 105Midstream 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, 2021as compared to the year ended December 31, 2020decreased by $16 millionprimarily 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 shows the components of our amortization expense for the years ended
Year Ended December 31, (In millions, except BOE amounts) 2021 2020 Depletion of proved oil and natural gas properties
$ 1,202 $ 1,242Depreciation of midstream assets 48 44 Depreciation of other property and equipment 16 18 Asset retirement obligation accretion 9 7
Depreciation, depletion, amortization and accretion charges
Depletion of oil and gas properties per boe
The decrease in depletion of proved oil and natural gas properties of
$40 millionfor the year ended December 31, 2021as compared to the year ended December 31, 2020resulted primarily from a reduction in the average depletion rate partially offset by increased production in 2021. The decline in rate resulted primarily from higher SECoil 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 SECguidance, 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 SECto 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 billionwould 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, 2021of $3.0 billionand $1.1 billion, respectively. 52 -------------------------------------------------------------------------------- Table of Contents 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, 2020of $6.0 billionwhich 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- P roperty 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
Year Ended December
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE General and administrative expenses
$ 95 $ 0.69 $ 51 $ 0.46Non-cash stock-based compensation 51 0.37
37 0.34 Total general and administrative expenses
General and administrative expenses for the year ended
December 31, 2021as compared to the year ended December 31, 2020increased by $58 millionprimarily due to additional payroll and other employee driven costs of $32 millionrelated to the QEP Merger and the Guidon Acquisition as well as $10 millionof additional expense related to the implementation of a new enterprise resource planning system. Additionally, equity compensation for the year ended December 31, 2021increased by $14 millioncompared to the same period in 2020. We expect cash general and administrative expenses to range from approximately $87 millionto $110 millionin 2022, and non-cash stock-based compensation to range from approximately $54 millionto $69 millionin 2022.
Merger and integration costs. The following table shows the merger and integration costs for the years ended
(In millions, except amounts per boe) Amount per boe Amount per boe Merger and integration costs
$ 78 $ 0.57
Total merger and integration expense for the year ended
December 31, 2021includes $69 millionin costs incurred for the QEP Merger and $9 millionin costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of $39 millionin severance costs and $30 millionin 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. 53 -------------------------------------------------------------------------------- Table of Contents Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2021and 2020: Year Ended December 31, 2021 2020 (In millions) Revolving credit agreements $ 11 $ 20Senior notes 252 214 Amortization of debt issuance costs and discounts 18 12 Other 7 10 Capitalized interest (88) (55) Total 200 201 Less: interest income 1 4 Interest expense, net $ 199 $ 197Net interest expense increased by $2 millionfor the year ended December 31, 2021as compared to the year ended December 31, 2020. This increase primarily consisted of (i) $47 millionin interest costs on the newly issued March 2021Notes (ii) $25 milliondue to incurring a full year of interest expense in 2021 related to our May 2020Notes 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 millionin additional capitalized interest costs, (ii) interest cost savings of $23 millionon the repurchases of our 2025 Senior Notes in March 2021and August 2021, (iii) $8 millionon the repurchase of our 4.625% senior notes of Energen (iv) a $9 millionreduction 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 millionto $178 millionin 2022. See Note 11- Debt for further details regarding outstanding borrowings and interest expense.
Derivatives. The following table shows the net gain (loss) on derivatives and net cash received (paid) on settlements of derivatives for the years ended
December 31, 20212020 (In millions)
Gain (loss) on derivative instruments, net $(848)
$ (81)Net cash received (paid) on settlements(1)(2)(3) $ (1,225)
(1)The year ended
December 31, 2021includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million. (2)The year ended December 31, 2020includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million. (3)The year ended December 31, 2021includes 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. 54 -------------------------------------------------------------------------------- Table of Contents 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 millionand 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, 2021and 2020: Year Ended December 31, 2021 2020 (In millions) Provision for (benefit from) income taxes $ 631$
Changes in our income tax expense for the year ended
compared to the same period in 2020 are mainly due to the increase in profit before tax for the year ended
Cash and capital resources
Overview of sources and uses of species
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 billionof liquidity consisting of $0.7 billionin cash and cash equivalents and $1.6 billionavailable under our credit facility. As discussed below, our capital budget for 2022 is $1.75 billionto $1.90 billion. Further, we have $45 millionof 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 Item 7A. Quantitative and Qualitative Disclosures About Market Risk-Commodity Price Risk . The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy. As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although the Company expects that its sources of funding will be adequate to fund its short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all. 55 -------------------------------------------------------------------------------- Table of Contents Cash Flow Our cash flows for the years ended December 31, 2021and 2020 are presented below: Year Ended December 31, 20212020 (In millions)
Net cash provided by (used in) operating activities
$ 2,118Net cash provided by (used in) investing activities (1,539)
Net cash provided by (used in) financing activities (1,841)
(37) Net change in cash
$ 564 $ (20)Operating Activities Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See Item 1A. "Risk Factors" 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 billionin our total revenues, and (ii) receipt of $152 millionin refunds of income taxes receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the CARES Act in 2020. These net cash inflows were partially offset by (i) a reduction of $1.5 billiondue to making net cash payments of $1.2 billionon our derivative contracts in the year ended December 31, 2021compared to receiving net cash of $250 millionon 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) other working capital changes, primarily due to recording increases in accounts receivable, accounts payable and accrued capital expenditure activity stemming from the QEP Merger and the Guidon Acquisition in 2021. See " - Results of Operations " for discussion of significant changes in our revenues and expenses.
Net cash used in investing activities was
$1.5 billioncompared to $2.1 billionfor the years ended December 31, 2021and 2020, respectively. The majority of our net cash used for investing activities during the year ended December 31, 2021was for the purchase and development of oil and natural gas properties and related assets, including the acquisition of certain leasehold interests as part of the Guidon Acquisition. These expenditures were partially offset by proceeds from the sale of our Williston Basinassets, leasehold acreage and other gathering assets discussed in Note 4- Acquisitions and Divestitures . The majority of our net cash used in investing activities during the year ended December 31, 2020was for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below. 56 -------------------------------------------------------------------------------- Table of Contents Capital Expenditure Activities
Our capital expenditures, excluding acquisitions and investments using the equity method (on a cash basis), were as follows for the period specified:
December 31, 20212020
(in millions) Non-operated drilling, completions and additions to oil and gas properties(1)(2)
$ 1,334 $ 1,611Infrastructure additions to oil and natural gas properties 123 108 Additions to midstream assets 30 140 Total $ 1,487 $ 1,859(1) During the year ended December 31, 2021, in conjunction with our development program, we drilled 216 gross (203 net) operated horizontal wells, of which 175 gross (165 net) wells were in the Midland Basinand 41 gross (38 net) wells were in the Delaware Basin, and turned 275 gross (258 net) operated horizontal wells to production, of which 207 gross (194 net) were in the Midland Basinand 64 gross (61 net) wells were in the Delaware Basin. (2) During the year ended December 31, 2020, in conjunction with our development program, we drilled 208 gross (195 net) operated horizontal wells, of which 133 gross (125 net) wells were in the Midland Basinand 75 gross (70 net) wells were in the Delaware Basin, and turned 171 gross (159 net) operated horizontal wells to production, of which 93 gross (85 net) were in the Midland Basinand 78 gross (74 net) wells were in the Delaware Basin.
Net cash used in financing activities for the year ended
December 31, 2021was $1.8 billioncompared to net cash used in financing activities for the year ended December 31, 2020of $37 million. During the year ended December 31, 2021, the amount used in financing activities was primarily attributable to (i) $3.2 billionpaid for the repurchase of outstanding principal on certain senior notes as discussed in "-Repurchases of Notes" below, as well as $178 millionof additional premiums paid in connection with the repurchases, (ii) $525 millionof repurchases as part of the share and unit repurchase programs, (iii) $312 millionof dividends paid to stockholders, and (iv) $112 millionin distributions to non-controlling interest. The cash outflows were partially offset by (i) $2.2 billionin proceeds from the March 2021Notes, (ii) $313 millionof borrowings under our and our subsidiaries' credit facilities, net of repayments and (iii) $22 millionin net cash receipts from the early settlement of interest rate swaps and commodity derivative contracts that contained an other-than-insignificant financing element. Net cash used in financing activities for the year ended December 31, 2020was primarily attributable to $348 millionof repayments, net of borrowings, on our credit facilities, $239 millionin aggregate repayments on the Energen Notes and Viper Notes, $236 millionin dividends paid to stockholders, $98 millionof share repurchases as part of our stock repurchase program, and $93 millionin distributions to non-controlling interest. These cash outlays were partially offset by net proceeds of $997 millionfrom the issuance of the May 2020Notes and the Rattler Notes during 2020.
Revolving credit facilities and other debt instruments
December 31, 2021, our debt, including the debt of Viper and Rattler, consists of approximately $6.2 billionin aggregate outstanding principal amount of senior notes, $499 millionin aggregate outstanding borrowings under revolving credit facilities and $58 millionin outstanding amounts due under our DrillCo Agreement. At December 31, 2021, we have total principal payments due on our outstanding senior notes, including those of Viper and Rattler, of $45 millionin 2022, $1.2 billioncumulatively in the years 2023 through 2024, $2.1 billioncumulatively in the years 2025 and 2026, and $3.4 billionthereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $177 millionin 2022, $371 millionin the years from 2023 through 2024, $277 millionin the years from 2025 through 2026, and $961 millionbetween 2027 and 2051. On June 2, 2021, we entered into a twelfth amendment, or the Amendment, to the Second Amended and Restated Credit Agreement which, among other things, decreased the total revolving loan commitments from $2.0 billionto $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). As of December 31, 2021, we had no outstanding borrowings under our revolving credit facility and $1.6 billionavailable for future borrowings under the revolving credit facility. 57
Viper Revolving Credit Facility
Viper's credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of
$2.0 billion, with a borrowing base of $580 millionas of December 31, 2021, based on the Viper's oil and natural gas reserves and other factors. At December 31, 2021, Viper had elected a commitment amount of $500 millionon its credit agreement with $304 millionof outstanding borrowings. During the year ended December 31, 2021, the weighted average interest rate on borrowings under the Operating Company'srevolving credit facility was 2.35%. Viper's Revolving credit facility matures in 2025.
Rattler Revolving Credit Facility
Rattler's credit agreement provides for a revolving credit facility in the maximum credit amount of
$600 million, which is expandable to $1.0 billionupon its election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of December 31, 2021, there was $195 millionof outstanding borrowings under Rattler's revolving credit facility. The weighted average interest rate on borrowings under the credit agreement was 1.41% for the year ended December 31, 2021. Rattler's revolving credit facility matures in 2024.
In 2021, we published an aggregate
For more information on our outstanding debt at
Subject to market conditions, we expect to continue to issue debt securities from time to time in the future to refinance our maturing debt. The availability, interest rate and other terms of any new borrowings will depend on the ratings assigned by credit rating agencies, among other factors.
We currently comply with, and expect to continue to comply with, all financial safeguard covenants of our debt instruments.
We receive debt ratings from the major ratings agencies in the
U.S.In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor's Global Ratings Servicesis BBB-. Our credit rating from Fitch Investor Servicesis BBB. Our credit rating from Moody's Investor Servicesis Baa3. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.
In addition to future operating expenses and working capital commitments described in – Results of Operations, our primary short-term and long-term cash requirements consist primarily of (i) capital expenditures, (ii) other contractual obligations and (iii) cash commitments for dividends and share buybacks as set out below.
Based upon current oil and natural gas prices and production expectations for 2022, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through the 12-month period following the filing of this report and thereafter. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that the needed capital will be available on acceptable terms or at all. Further, our 2022 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions. 58 -------------------------------------------------------------------------------- Table of Contents 2022 Capital Spending Plan Our board of directors approved a 2022 capital budget for drilling, midstream and infrastructure of
$1.75 billionto $1.90 billionmaintaining our annualized fourth quarter 2021 cash capital expenditure guidance presented in November of 2021. We estimate that, of these expenditures, approximately: •$1.56 billion to $1.67 billionwill be spent primarily on drilling 270 to 290 gross (248 to 267 net) horizontal wells and completing 260 to 280 gross (240 to 258 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midlandand Southern Delaware Basins, with an average lateral length of approximately 10,200 feet; •$80 million to $100 millionwill be spent on midstream infrastructure, excluding joint venture investments; and •$110 million to $130 millionwill be spent on infrastructure and environmental expenditures, excluding the cost of any leasehold and mineral interest acquisitions.
We do not have a specific acquisition budget since the timing and size of acquisitions cannot be predicted with precision.
The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We were operating 10 drilling rigs and four completion crews at
December 31, 2021and currently intend to operate between 10 and 12 rigs and between three and four completion crews on average in 2022, as we continue to execute on our strategy to hold oil production flat while using cash flow from operations to reduce debt, strengthen our balance sheet and return capital to our stockholders. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget up or down in response to changes in commodity prices and overall market conditions.
Other contractual obligations and commitments
December 31, 2021, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $878 million, (ii) asset retirement obligations totaling $171 million, and (iii) minimum purchase commitment for quantities of sand used in our drilling operations totaling $77 million. We expect to make aggregate payments of approximately $105 millionfor these commitments during 2022. See Note 9- Asset Retirement Obligations and Note 18- Commitments and Contingencies for further discussion of these and other contractual obligations and commitments.
Dividends and share buybacks
We paid common stock dividends of
$312 millionand $236 millionduring 2021 and 2020, respectively. On February 18, 2022, our board of directors declared a cash dividend for the fourth quarter of 2021 of $0.60per share of common stock, payable on March 11, 2022to our stockholders of record at the close of business on March 4, 2022. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billionof our outstanding common stock. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time. We repurchased approximately $431 millionof our common stock under this program during the year ended December 31, 2021, and have $1.6 billionremaining for future repurchases under the repurchase program at December 31, 2021See Note 12- Stockholders' Equity and Earnings Per Share for further discussion of the repurchase program.
Financial information of the guarantor
In connection with the merger of certain of the Company's wholly owned subsidiaries in an internal subsidiary restructuring on
June 30, 2021, Diamondback E&Pbecame the successor borrower to Diamondback O&G LLC("O&G") under the credit agreement, the successor issuer of Energen's 7.125% Medium-term Notes, Series B, due February 15, 2028and Energen's 7.32% Medium-term Notes, Series A, due July 28, 2022, and the sole guarantor under the indentures governing the December 2019Notes, the May 2020Notes, the 2025 Senior Notes and the March 2021Notes. 59 -------------------------------------------------------------------------------- Table of Contents Guarantees are "full and unconditional," as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the IG Indenture and the 2025 Indenture, such as, with certain exceptions, (i) in the event Diamondback E&P(or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&Pceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture. The 2025 Indenture was terminated in connection with the early redemption of the remaining $432 millionprincipal amount of our 2025 Senior Notes in the third quarter of 2021. Diamondback E&P'sguarantees of the December 2019Notes, the May 2020Notes and the March 2021Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness. The rights of holders of the Senior Notes against Diamondback E&Pmay be limited under 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 the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished. The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback E&P, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC'sRegulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity. December 31, 2021 Summarized Balance Sheets: (In millions) Assets: Current assets $ 1,148 Property and equipment, net $ 14,778 Other noncurrent assets $ 55 Liabilities: Current liabilities $ 1,221 Intercompany accounts payable, non-guarantor subsidiary $ 1,440 Long-term debt $ 5,093 Other noncurrent liabilities $ 1,549 Year Ended December 31, 2021 Summarized Statement of Operations: (In millions) Revenues $ 5,049 Income (loss) from operations $ 2,898 Net income (loss) $ 1,348 60
-------------------------------------------------------------------------------- Table of Contents Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in
the United States. Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results of operations of the registrant. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
Oil and natural gas accounting and reserves
We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired proved oil and natural gas properties including mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate. 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. Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and their associated future net cash flows. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include our estimate of operating and development costs, anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future depletion of capitalized costs and result in impairment of assets that may be material. Revisions of previous reserve estimates accounted for approximately
$719 million, or 6% of the change in the standardized measure of our total reserves from December 31, 2020to December 31, 2021. No impairments were recorded on for our proved oil and gas properties during the year ended December 31, 2021; however, material impairments were recorded during the years ended December 31, 2020and 2019 as discussed further in Note 8- Property and Equipment of the notes to the consolidated financial statements included elsewhere in this Annual Report. Due to an increase in the historical 12-month average trailing SECprices for oil and natural throughout 2021 and into 2022, we are not currently projecting a full cost ceiling impairment in the first quarter of 2022. Additionally, costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property (on an individual basis or as a group if properties are individually insignificant) on an annual basis for possible impairment. This assessment is subjective and includes consideration of the following factors, among others: intent of the operator to drill, remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. At December 31, 2021, our unevaluated properties totaled $8 billion, which consisted of 214,151 net undeveloped leasehold acres with approximately 41,855 net acres set to expire in 2022. We did not record any impairment on our unevaluated properties during the year ended December 31, 2021, but any such future impairment could be material to our consolidated financial statements. 61
From time to time, we use commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties' creditworthiness. We do not use these instruments for speculative or trading purposes. We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which 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 are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.
See Section 7A. Quantitative and qualitative disclosures on market risk and commodity price risk for additional sensitivity analysis of our open derivative positions at
We account for business combinations using the acquisition method of accounting. Accordingly, identifiable assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. Fair value estimates are determined based on information that existed at the time of the acquisition, utilizing expectations and assumptions that would be available to and made by a market participant. When market-observable prices are not available to value assets and liabilities, the Company may use the cost, income, or market valuation approaches depending on the quality of information available to support management's assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. The assumptions made in performing these valuations include future production volumes, future commodity prices and costs, future operating and development activities, projections of oil and gas reserves and a weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of natural gas and oil properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of additional goodwill or discount on acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected. See Note 4- Acquisitions and Divestitures of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of the estimated fair value of assets acquired and liabilities assumed in the QEP Merger and Guidon Acquisition, including any significant changes in these estimates from the date of acquisition. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. In addition, differences between the future commodity prices when acquiring assets and the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net earnings. Income Taxes The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit 62 -------------------------------------------------------------------------------- Table of Contents 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. The assessment of the realizability of our deferred tax assets, including the assessment of whether a valuation allowance is required, entails that we make estimates of, and assumptions about, future events, including the pattern of reversal of taxable temporary differences and our future income from operations. As of
December 31, 2021, we had established a total valuation allowance of $315 million, including a valuation allowance for the full amount of Viper's deferred tax assets. The valuation allowance remains in place based on the uncertainty of future events, including Viper's ability to generate future taxable income in excess of special allocations to be made to Diamondback, and management considered this and other factors in evaluating the realizability of Viper's deferred tax assets. No such valuation allowance was determined to be necessary against Rattler's deferred tax assets as of December 31, 2021based on the relative predictability of its future income stream based on its long term customer contracts. Any changes in the positive or negative evidence evaluated when determining if Viper's or Rattler's deferred tax assets will be realized, including projected future income, could result in a material change to our consolidated financial statements. In addition, the determination to record a valuation allowance on certain tax attributes acquired from QEP and certain state NOL carryforwards which the Company does not believe are realizable prior to expiration was based on an evaluation of available positive and negative evidence, including the annual limitation imposed by IRC Section 382 subsequent to an ownership change and the anticipated timing of reversal of the Company's deferred tax liabilities in the applicable jurisdictions. As of December 31, 2021, although the Company's recent cumulative losses represent negative evidence regarding reliance on future taxable income exclusive of reversing temporary differences, our balance of taxable temporary differences anticipated to reverse within the carryforward period provides significant positive evidence for the determination that our remaining deferred tax assets are more likely than not to be realized. Any change in the positive or negative evidence evaluated when determining if our deferred tax assets will be realized, including projected future taxable income primarily related to the excess of book carrying value over tax basis of our oil and natural gas properties, could result in a material change to our consolidated financial statements. The accruals for deferred tax assets and liabilities are often based on uncertain tax positions and assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. At December 31, 2021, our uncertain tax positions were insignificant, however, material changes to our income tax accruals 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 to the consolidated financial statements included elsewhere in this Annual Report for recent accounting pronouncements and accounting policies not yet adopted, if any.
Off-balance sheet arrangements
Please read Note 18- Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Form 10-K for a discussion of our commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.
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