The following discussion and analysis of our financial condition and results ofoperations should be read in conjunction with our consolidated financialstatements and related notes appearing elsewhere in this Annual Report on Form10-K. The Consolidated Balance Sheets and Consolidated Statements of Operationshave been recast from prior periods to reflect the OMP Merger (defined below) asa discontinued operation. Refer to "Part II, Item 8. Financial Statements andSupplementary Data-Note 6-Discontinued Operations." In addition, the followingdiscussion contains "forward-looking statements" that reflect our future plans,estimates, beliefs and expected performance. We caution that assumptions,expectations, projections, intentions or beliefs about future events may, andoften do, vary from actual results, and the differences can be material. See"Cautionary Note Regarding Forward-Looking Statements" at the beginning of thisreport for an explanation of these types of statements.For discussion related to changes in financial condition and results ofoperations for the years endedDecember 31, 2020 and 2019, refer to "Part II,Item 7. Management's Discussion and Analysis of Financial Condition and Resultsof Operations" in our Annual Report on Form 10-K for the year endedDecember 31,2020 , filed with theSEC onMarch 8, 2021 .
Overview
We are an independent E&P company with quality and sustainable long-lived assetsin theNorth Dakota andMontana regions of theWilliston Basin . Our mission isto improve lives by safely and responsibly providing affordable, reliable andabundant energy. We are uniquely positioned with a best-in-class balance sheetand are focused on rigorous capital discipline and generating free cash flow byoperating efficiently, safely and responsibly to develop our unconventionalonshore oil-rich resources in the continentalUnited States .
Recent Developments
Return of Capital Plan
OnFebruary 9, 2022 , we announced a plan to return$280 million of capital toshareholders over the next year ($70 million per quarter) through a combinationof a base dividend (approximately$45 million ), variable dividends and sharerepurchases. This return of capital plan represents a balanced approach thatreflects our strategic goals of exercising capital discipline while deliveringboth return on and return of capital to shareholders. The Board of Directors hasincreased the quarterly base dividend by 17% from$0.50 per share of commonstock to$0.585 per share of common stock and expects to pay an aggregate basedividend of$11.3 million per quarter during 2022. The Board of Directorsdeclared the base dividend for the fourth quarter of 2021 of$0.585 per share ofcommon stock ($2.34 per share annualized) payable onMarch 4, 2022 toshareholders of record as ofFebruary 21, 2022 . In addition, the Board ofDirectors authorized a new$150.0 million share repurchase program to replacethe$100.0 million share repurchase program that was fully utilized in 2021. Weexpect to return capital proportionately each quarter through 2022. After theend of each quarter, we expect to announce a variable dividend based on$70million less cash utilized to pay the base dividend and repurchase shares duringthe prior quarter. See "Liquidity and Capital Resources" below for additionalinformation.Williston Basin AcquisitionOnOctober 21, 2021 , we completed our acquisition of approximately 95,000 netacres in theWilliston Basin , effectiveApril 1, 2021 , fromQEP Energy Company ("QEP"), a wholly-owned subsidiary of Diamondback Energy, Inc. for total cashconsideration of$585.8 million (the "Williston Basin Acquisition"). The totalcash consideration paid was comprised of a deposit of$74.5 million paid onMay 3, 2021 and$511.3 million paid at closing onOctober 21, 2021 . TheWilliston Basin Acquisition was funded with cash on hand, which includedproceeds from the Permian Basin Sale (defined below) and the Oasis Senior Notes(defined below).Permian Basin SaleOnJune 29, 2021 , we completed the sale of our upstream assets in theTexas region of thePermian Basin , effectiveMarch 1, 2021 , toPercussion PetroleumOperating II, LLC ("Percussion") for an aggregate purchase price of$450.0 million (the "Primary Permian Basin Sale"). The purchase price consistedof$375.0 million cash at closing and up to three earn-out payments of$25.0 million per year for each of 2023, 2024 and 2025 if the average dailysettlement price of NYMEX West Texas Intermediate ("NYMEX WTI") crude oilexceeds$60 per barrel for such year (the "Permian Basin Sale ContingentConsideration"). We received cash proceeds of$342.3 million after purchaseprice adjustments that were primarily related to cash flows from the effectivedate to the close date. The total consideration remains subject to earn-outpayments related to the Permian Basin Sale Contingent Consideration.In addition to the Primary Permian Basin Sale, we also divested certain wellboreinterests in theTexas region of thePermian Basin to separate buyers in thesecond quarter of 2021 (the "Additional Permian Basin Sale" and together withthe Primary 54
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Permian Basin Sale, the "Permian Basin Sale"). We received cash proceeds fromthe Additional Permian Basin Sale of
OMP Merger
OnOctober 25, 2021 , OMP and OMP GP entered into the OMP Merger pursuant towhich we agreed to sell to Crestwood our entire ownership of OMP common unitsand all of the limited liability company interests of OMP GP in exchange for$160.0 million in cash and approximately 21 million common units representinglimited partner interests of Crestwood. The OMP Merger was unanimously approvedby the Board of Directors of both Oasis and Crestwood and was also unanimouslyapproved by the Board of Directors andConflicts Committee of OMP GP .The OMP Merger was completed onFebruary 1, 2022 and we own approximately 21.7%of Crestwood's issued and outstanding common units, and we are Crestwood'slargest single customer. In connection with the closing of the OMP Merger, theCompany and Crestwood executed a director nomination agreement pursuant to whichwe designated two directors to the Board of Directors of Crestwood GP.The OMP Merger represents a strategic shift for the Company and qualified forreporting as a discontinued operation. See "Item 8. Financial Statements andSupplementary Data-Note 5-Oasis Midstream Partners ."
Change in Chief Executive Officer
OnApril 13, 2021 ,Daniel E. Brown was appointed Chief Executive Officer of theCompany. At the same time,Mr. Brown was also appointed to the Company's Boardof Directors.Mr. Brown replacedDouglas E. Brooks , who was previously appointedto serve as Chief Executive Officer on an interim basis.Mr. Brooks continues toserve in his role as Board Chair.
Market Conditions and COVID-19
COVID-19 remains a global health crisis and there continues to be considerableuncertainty regarding the extent to which COVID-19 and its variants willcontinue to spread. Despite improvements in global economic activity levels andhigher energy demand compared to 2020, the impacts of COVID-19 continue to beunpredictable, including the impacts of new virus strains, the risk of renewedrestrictions and the uncertainty of successful administration of effectivetreatments and vaccines. We are unable to reasonably estimate the period of timethat related conditions could exist or the extent to which they could impact ourbusiness, results of operations, financial condition or cash flows. Commodityprices have risen from historic lows in 2020; however, further negative impactsfrom COVID-19 may require us to adjust our business plan.We are committed to the health and safety of our employees, contractors andcommunities. We have established appropriate policies and procedures while wehave continued to operate during the COVID-19 pandemic. All managers andsupervisors have been trained on how to address positive COVID-19 cases,including procedures on notifying, tracking and communicating COVID-19 cases.Our Crisis Management Team continuously monitors public health data andguidance, engages with peer companies, and participates with industryassociations to ensure alignment with guidance for employee health and safety.InSeptember 2021 ,President Biden announced a COVID-19 action plan that wouldhave theOccupational Safety and Health Administration ("OSHA") develop anEmergency Temporary Standard ("ETS") which may include new obligations foremployers with one hundred or more employees with respect to vaccinations,testing and paid time off. InNovember 2021 ,OSHA published an ETS that requirescovered employers to take affirmative steps to address COVID-19 safety,including having a written COVID-19 vaccination policy and having a process inplace where employees are able to confidentially submit proof of vaccinationstatus. The ETS also requires any employee who is not fully vaccinated to wear aface covering at the workplace, effectiveJanuary 20, 2022 , and be subject toregular COVID-19 testing, effectiveFebruary 9, 2022 . In connection with theETS, we established a policy to comply withOSHA's ETS on vaccination, testingand face coverings that applies to all of our employees. OnJanuary 13, 2022 ,theU.S. Supreme Court stayed the OSHA ETS. We monitor mandates related toCOVID-19 at both the federal and state levels on an ongoing basis and continueto assess the potential impacts of those mandates.
Commodity Prices
Our revenue, profitability and ability to return cash to shareholders dependsubstantially on factors beyond our control, such as economic, political andregulatory developments as well as competition from other sources of energy.Prices for crude oil, natural gas and NGLs have experienced significantfluctuations in recent years and may continue to fluctuate widely in the future.In an effort to improve price realizations from the sale of our crude oil,natural gas and NGLs, we manage our commodities marketing activities in-house,which enables us to market and sell our crude oil, natural gas and NGLs to abroader array of potential purchasers. We enter into crude oil, natural gas andNGL sales contracts with purchasers who have access to transportation capacity,utilize derivative financial instruments to manage our commodity price risk andenter into physical 55
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delivery contracts to manage our price differentials. Due to the availability ofother markets and pipeline connections, we do not believe that the loss of anysingle customer would have a material adverse effect on our results ofoperations or cash flows. Please see "Part I, Item 1. Business-Exploration andProduction Operations-Marketing and major customers."
Our average net realized crude oil prices and average price differentials areshown in the tables below for the periods presented:
2021 (Successor) Year ended December Q1 Q2 Q3 Q4 31, 2021 (Successor)Average Realized Crude Oil Prices($/Bbl)(1)$ 56.09 $ 65.53 $ 70.11 $ 76.37 $ 67.49
Average Price Differential ($/Bbl)(2)
$ 0.70Average Price Differential Percentage(2) 3 % 1 % 1 % 0.3 % 1 % Predecessor Successor Period from 2020 October 1, 2020 Period from through November 20, 2020 November through Q1 Q2 Q3 19, 2020 December 31, 2020Average Realized Crude Oil Prices($/Bbl)(1)$ 43.22 $ 24.45 $ 38.52 $ 37.67 $ 43.36
Average Price Differential ($/Bbl)(2)
$ 3.16 Average Price Differential Percentage(2) 7 % 11 % 6 % 5 % 7 % 2019 (Predecessor) Year ended December 31, Q1 Q2 Q3 Q4 2019 (Predecessor)Average Realized Crude Oil Prices($/Bbl)(1)$ 53.52 $ 58.87 $ 55.12 $ 53.66 $ 55.27Average Price Differential($/Bbl)(2)$ 1.30 $ 0.96 $ 1.30 $ 3.23 $ 1.68Average Price DifferentialPercentage(2) 2 % 2 % 2 % 6 % 3 %__________________(1)Realized crude oil prices do not include the effect of derivative contractsettlements.(2)Price differential reflects the difference between our realized crude oilprices and NYMEX WTI crude oil index prices.We sell a significant amount of our crude oil production through gatheringsystems connected to multiple pipeline and rail facilities. As ofDecember 31,2021 , 95% of our gross operated crude oil production was connected to gatheringsystems, which originate at the wellhead and reduce the need to transportbarrels by truck from the wellhead. Our market optionality on these crude oilgathering systems allows us to shift volumes between pipeline and rail marketsin order to optimize price realizations. Expansions of both rail and pipelinefacilities in theWilliston Basin has reduced prior constraints on crude oiltakeaway capacity and improved our price differentials received at the lease.
Results of Operations
The OMP Merger qualified for reporting as a discontinued operation. Accordingly,the results of operations of OMP have been classified as discontinued operationsin the Consolidated Statement of Operations for the year endedDecember 31, 2021 (Successor). Prior periods have been recast so that the basis of presentation isconsistent with that of the 2021 consolidated financial statements. See "Item 8.Financial Statements and Supplementary Data-Note 6-Discontinued Operations" foradditional information.In addition, we emerged from bankruptcy onNovember 19, 2020 (the "EmergenceDate") and adopted fresh start accounting, which resulted in us becoming a newentity for financial reporting purposes. Accordingly, the consolidated financialstatements on or afterNovember 19, 2020 are not comparable to the consolidatedfinancial statements prior to that date. References to "Successor" relate to ourfinancial position and results of operations as of and subsequent to theEmergence Date. References to "Predecessor" relate to our financial positionprior to, and our results of operations through and including, the EmergenceDate.Highlights
During the year ended
•Production volumes averaged 58,032 Boepd (64% oil).
•Lease operating expenses were$9.63 per Boe, compared to$9.27 per Boe duringthe period fromNovember 20, 2020 throughDecember 31, 2020 (Successor) and$7.55 per Boe during the period fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor).
•E&P and other capital expenditures, excluding capitalized interest andacquisition capital, were
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•Estimated net proved reserves were 250.9 MMBoe as of
•Paid regular cash dividends of
•Completed
Revenues
Our crude oil and natural gas revenues are derived from the sale of crude oiland natural gas production. These revenues do not include the effects ofderivative instruments and may vary significantly from period to period as aresult of changes in volumes of production sold or changes in commodity prices.Our purchased oil and gas sales are primarily derived from the sale of crude oiland natural gas purchased through our marketing activities primarily to optimizetransportation costs, for blending to meet pipeline specifications or to coverproduction shortfalls. Revenues and expenses from crude oil and natural gassales and purchases are recorded on a gross basis when we act as a principal inthese transactions by assuming control of the purchased crude oil or natural gasbefore it is transferred to the customer. In certain cases, we enter into salesand purchases with the same counterparty in contemplation of one another, andthese transactions are recorded on a net basis.Our other services revenues are derived from equipment rentals, and alsoincluded revenues for well completion services and product sales prior to ourtransition of our well fracturing services fromOasis Well Services LLC ("OWS"),a wholly-owned subsidiary, to a third-party provider during the first quarter of2020 (the "Well Services Exit"). Substantially all of our other servicesrevenues are from services provided to our operated wells. Intercompany revenuesfor work performed for our ownership interests are eliminated in consolidation,and only the revenues related to non-affiliated interest owners and otherthird-party customers are included in other services revenues.The following table summarizes our revenues for the periods presented (inthousands): Successor Predecessor Period from Period from November 20, January 1, 2020 Year Ended 2020 through through Year Ended December 31, December 31, November 19, December 31, 2021 2020 2020 2019RevenuesCrude oil revenues$ 910,381 $ 69,075 $ 522,812 $ 1,261,413 Natural gas revenues 289,875 17,070 78,698 146,396Purchased oil and gas sales 378,983 20,633 237,111 481,014Other services revenues 687 215 6,836 41,974Total revenues$ 1,579,926 $ 106,993 $ 845,457 $ 1,930,797 57
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The following table summarizes the changes in production and average realizedprices for the periods presented:
Successor Predecessor Period from Period from November 20, January 1, 2020 Year Ended 2020 through through December 31, December 31, November 19, 2021 2020 2020Production dataCrude oil (MBbls) 13,489 1,593 14,226Natural gas (MMcf) 46,157 5,008 42,199Oil equivalents (MBoe) 21,182 2,428 21,258Average daily production (Boepd) 58,032 57,809 65,612Average sales pricesCrude oil (per Bbl)Average sales price$ 67.49 $ 43.36 $ 36.75 Effect of derivative settlements(1) (18.94) - 11.38Average realized price after the effect of derivativesettlements(1)$ 48.55 $ 43.36 $ 48.13 Natural gas (per Mcf)(2)Average sales price$ 6.28 $ 3.41 $ 1.86 Effect of derivative settlements(1) (0.32) (0.01) -Average realized price after the effect of derivativesettlements(1)$ 5.96 $ 3.40 $ 1.86 __________________(1)The effect of derivative settlements includes the cash received or paid forthe cumulative gains or losses on our commodity derivatives settled in theperiods presented, but does not include proceeds from derivative liquidations orpayments for derivative modifications. Our commodity derivatives do not qualifyfor or were not designated as hedging instruments for accounting purposes.(2)Natural gas prices include the value for natural gas and NGLs.Crude oil and natural gas revenues. Crude oil and natural gas revenues increased$512.6 million , or 75%, in 2021. This increase was attributable to a$676.3million increase due to higher crude oil and natural gas sales prices, partiallyoffset by a$163.8 million decrease due to lower crude oil and natural gasproduction sold. During the year endedDecember 31, 2021 (Successor), our crudeoil and natural gas revenues were positively impacted by higher commodity pricescompared to the previous year due largely to higher energy demand as a result ofincreased economic activity following severe COVID-19 restrictions during 2020.Excluding the effect of derivative settlements, average crude oil sales pricesincreased 80%, and average natural gas sales prices, which include the value fornatural gas and NGLs, increased 209% year over year. Average daily productionsold decreased by 6,685 Boepd year over year, primarily driven by a decrease of5,353 Boepd due to the divestiture of our upstream assets in thePermian Basin onJune 29, 2021 . We closed theWilliston Basin Acquisition onOctober 21, 2021 ,and average daily production from theWilliston Basin Acquisition asset betweenthe close date toDecember 31, 2021 was 21,226 Boepd. During the yearendedDecember 31, 2021 (Successor), we completed and placed on production 22.3total net operated wells in theWilliston Basin .Purchased oil and gas sales. Purchased oil and gas sales, which consistprimarily of the sale of crude oil purchased to optimize transportation costs,for blending to meet pipeline specifications or to cover production shortfalls,increased$121.2 million to$379.0 million for the year endedDecember 31, 2021 (Successor), primarily due to higher crude oil sales prices period over period,partially offset by lower crude oil volumes purchased and then subsequentlysold.Other services revenues. Other services revenues decreased by$6.4 million to$0.7 million during the year endedDecember 31, 2021 (Successor), which wasprimarily attributable to a decrease in well completion revenues due to the WellServices Exit in the first quarter of 2020. 58
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Expenses and other income
The following table summarizes our operating expenses, gain (loss) on sale ofproperties, other income and expenses, income tax benefit, net income (loss)from continuing operations, income from discontinued operations attributable toOasis, net of income tax and net income (loss) attributable to Oasis for theperiods presented (in thousands, except per Boe of production): Successor Predecessor Period from November 20, Year Ended 2020 through Period from January Year Ended December 31, December 31, 1, 2020 through December 31, 2021 2020 November 19, 2020 2019Operating expensesLease operating expenses$ 203,933 $ 22,517 $ 160,406 $ 288,690 Other services expenses 47 - 6,658 28,761Gathering, processing and transportationexpenses 122,614 13,198 117,884 174,026Purchased oil and gas expenses 379,972 20,278 229,056 474,914Production taxes 76,835 5,938 45,439 112,592Depreciation, depletion and amortization 126,436 13,789 271,002 771,640Exploration expenses 2,760 - 2,748 6,658Rig termination - - 1,279 384Impairment 3 - 4,825,530 10,257General and administrative expenses 80,688 14,803 144,700 128,595Litigation settlement - - 22,750 20,000Total operating expenses 993,288 90,523 5,827,452 2,016,517Gain (loss) on sale of properties 222,806 11 10,396 (4,455)Operating income (loss) 809,444 16,481 (4,971,599) (90,175)Other income (expense)Net gain (loss) on derivative instruments (589,641) (84,615) 233,565 (106,314)Interest expense, net of capitalized interest (30,806) (2,020) (141,836) (159,287)Gain on extinguishment of debt - - 83,867 4,312Reorganization items, net - - 665,916 -Other income (expense) (1,010) (401) 1,271 569Total other income (expense), net (621,457) (87,036) 842,783 (260,720)Income (loss) from continuing operations 187,987 (70,555) (4,128,816) (350,895)Income tax benefit 973 3,447 262,962 32,715Net income (loss) from continuing operations 188,960 (67,108) (3,865,854) (318,180)Income from discontinued operations attributableto Oasis, net of income tax 130,642 17,196 225,526 189,937
Net income (loss) attributable to Oasis
$ (3,640,328) $ (128,243) Costs and expenses (per Boe of production)Lease operating expenses$ 9.63 $ 9.27 $ 7.55$ 8.98 Gathering, processing and transportationexpenses 5.79 5.44 5.55 5.41Production taxes 3.63 2.45 2.14 3.50Lease operating expenses. Lease operating expenses ("LOE") increased$21.0million year over year to$203.9 million for the year endedDecember 31, 2021 (Successor). This increase was due to a$32.0 million increase in theWillistonBasin related to higher costs for gas lift of$10.9 million , fixed costs of$10.5 million and workover expenses of$9.3 million . These increases were offsetby a decrease of$11.0 million for LOE in thePermian Basin due to thedivestiture of those assets in June of 2021. LOE increased$1.91 per Boe to$9.63 per Boe due to a combination of higher costs and lower production volumes.Other services expenses. The$6.6 million decrease year over year was primarilyattributable to a decrease in well completion expenses due to the Well ServicesExit in the first quarter of 2020. 59
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Gathering, processing and transportation expenses. Gathering, processing andtransportation ("GPT") expenses decreased $8.5 million year over year, which wasattributable to a $3.4 million decrease in natural gas gathering and processingexpenses and a $2.2 million decrease in crude oil gathering and transportationexpenses, both related to a decrease in our production volumes. In addition,there was a decrease of $2.8 million related to non-cash valuation adjustmentsfor pipeline imbalances. GPT per Boe was $5.79 for the year ended December 31,2021 (Successor) and increased year over year due to lower production volumes.Purchased oil and gas expenses. Purchased oil and gas expenses, which representthe crude oil purchased primarily to optimize transportation costs, for blendingto meet pipeline specifications or to cover production shortfalls, increased$130.7 million year over year to $380.0 million for the year ended December 31,2021 (Successor) primarily due to higher crude oil prices period over period,partially offset by lower crude oil volumes purchased.Production taxes. Production taxes increased $25.5 million year over year to$76.8 million for the year ended December 31, 2021 (Successor) primarily due tohigher crude oil and natural gas revenues. The production tax rate as apercentage of crude oil and natural gas sales was 6.4% for the year endedDecember 31, 2021 (Successor), compared to 6.9% for the period from November 20,2020 through December 31, 2020 (Successor) and 7.6% for the period from January1, 2020 through November 19, 2020 (Predecessor). The production tax ratedecreased year over year primarily due to a lower crude oil production mix inthe Williston Basin .Depreciation, depletion and amortization. Depreciation, depletion andamortization ("DD&A") expense decreased $158.4 million , or 56%, year over yearto $126.4 million for the year ended December 31, 2021 (Successor). Thisdecrease was primarily due to a decrease in DD&A related to oil and gasproperties in the Williston Basin of $136.5 million , of which $133.8 million wasdue to a lower average unit-of-production rate and $2.7 million was due to lowerproduction volumes. In the Williston Basin , the average unit-of-production DD&Arate decreased $6.55 per Boe, or 56%, in 2021 as compared to 2020 primarily dueto a lower basis in our oil and gas properties due to write-downs during 2020.In addition, DD&A expense decreased $31.2 million due to a partial year ofdepletion expense on our Permian Basin properties that were sold in June of2021. These decreases were offset by an increase in depreciation expense relatedto our fixed assets of $9.9 million due to a higher book basis in wellfracturing equipment as a result of fresh start accounting fair valueadjustments made in November 2020 .Rig termination. There were no rig termination expenses recorded during the yearended December 31, 2021 (Successor) or for the period from November 20, 2020 through December 31, 2020 (Successor). We recorded $1.3 million of rigtermination expenses for the period from January 1, 2020 through November 19,2020 (Predecessor) to early terminate certain drilling rig contracts in thePermian Basin .Impairment. Impairment expenses were immaterial for the year ended December 31,2021 (Successor). There were no impairment expenses for the period from November20, 2020 through December 31, 2020 (Successor). We recorded impairment expensesof $4.8 billion for the period from January 1, 2020 through November 19, 2020 (Predecessor), primarily due to the following:•Proved oil and gas properties. The Predecessor recorded an impairment charge of$4.4 billion on its proved oil and gas properties, including $3.8 billion in theWilliston Basin and $637.3 million in the Permian Basin for the period endedNovember 19, 2020 , primarily due to a significant decline in commodity prices.•Unproved oil and gas properties. The Predecessor recorded impairment losses onits unproved oil and gas properties of $401.1 million for the period endedNovember 19, 2020 as a result of leases expiring or expected to expire, as wellas drilling plan uncertainty on certain acreage of unproved properties.General and administrative expenses. Our general and administrative ("G&A")expenses decreased $78.8 million year over year to $80.7 million for the yearended December 31, 2021 (Successor). This decrease was primarily due to loweremployee compensation expenses due to a 21% decrease in employee headcount yearover year, coupled with restructuring related expenses incurred during 2020.Cash G&A, a non-GAAP financial measure, was $2.18 per Boe during the year endedDecember 31, 2021 (Successor), compared to $5.04 per Boe during the period fromNovember 20, 2020 through December 31, 2020 (Successor) and $4.52 per Boe duringthe period from January 1, 2020 through November 19, 2020 (Predecessor). For adefinition of Cash G&A and a reconciliation of G&A to Cash G&A, see "Non-GAAPFinancial Measures" below.Litigation settlement. There were no litigation settlement expenses recordedduring the year ended December 31, 2021 (Successor) or for the period fromNovember 20, 2020 through December 31, 2020 (Successor). During the period fromJanuary 1, 2020 through November 19, 2020 (Predecessor), we recorded a lossaccrual of $22.8 million for the remaining settlement of legal proceedings withMirada Energy, LLC and certain related parties. See "Item 8. FinancialStatements and Supplementary Data-Note 22-Commitments and Contingencies" formore information.
Gain (loss) on sale of properties. For the year ended
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2020 (Predecessor), we recognized a$10.4 million net gain on sale of propertiesprimarily related to the sale of certain oil and gas properties in theWillistonBasin . For more information on our divestitures, see "Item 8. FinancialStatements and Supplementary Data-Note 13-Acquisitions and Divestitures".Derivative instruments. As a result of entering into derivative contracts andthe effect of the forward strip commodity price changes, we recognize gains orlosses on our derivative instruments for the change in their fair value duringthe period. During the year endedDecember 31, 2021 (Successor), we recorded a$589.6 million net loss on derivative instruments, primarily due to anunrealized loss of$319.5 million and a realized loss of$270.1 million . Theunrealized loss includes a loss of$331.5 million related to our commodityderivative contracts, partially offset by a gain of$12.0 million related to thePermian Basin Sale Contingent Consideration. The realized loss includes$255.5million related to settlement payments on crude oil derivative contracts and$14.7 million related to settlement payments on natural gas derivativecontracts. During the 2020 Successor Period, we recognized an$84.6 million losson derivative instruments, including net cash settlement payments of$0.1million , for the decrease in the fair value of our derivative contracts as aresult of an increase in forward commodity prices during the period. During the2020 Predecessor Period, we recognized a$233.6 million gain on derivativeinstruments, including net cash settlement receipts of$224.4 million , of which$62.6 million was received for derivative contracts liquidated prior to theirmaturities.Interest expense, net of capitalized interest. Interest expense decreased$113.1million year over year to$30.8 million for the year endedDecember 31, 2021 (Successor). The decrease was primarily due to interest expense related to thePredecessor's senior unsecured notes of$92.5 million and the Predecessor'srevolving credit facility of$21.0 million that were recorded during the periodfromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor), coupled with aspecified default interest charge of$30.3 million that was incurred during theperiod fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor) and wassubsequently waived on the Emergence Date. These decreases were offset byinterest expense recorded during the year endedDecember 31, 2021 (Successor)related to the Oasis Senior Notes (defined below) of$13.7 million and the OasisCredit Facility (defined below) of$9.3 million , coupled with a fee of$7.8 million that was incurred to enter into a commitment letter for a seniorsecured second lien facility. The senior secured second lien facility wasterminated prior to being drawn and was replaced with financing from the OasisSenior Notes (defined below).For the year endedDecember 31, 2021 (Successor), the weighted average debtoutstanding under the Oasis Credit Facility (defined below) was$65.5 million ,and the weighted average interest rate incurred on outstanding borrowings underthe Oasis Credit Facility (defined below) was 4.2%. Interest capitalized duringthe year endedDecember 31, 2021 (Successor) was$2.1 million .Gain on extinguishment of debt. There was no extinguishment of debt during theyear endedDecember 31, 2021 (Successor). During the period fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor), we repurchased an aggregate principalamount of$156.8 million of senior unsecured notes for an aggregate cost of$68.0 million and recognized a pre-tax gain of$83.9 million .Reorganization items, net. During the period fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor), we recorded$665.9 million of netreorganization items related to our emergence from bankruptcy, consisting of (i)gains on the settlement of obligations under the Predecessor senior unsecurednotes, (ii) fresh start accounting fair value adjustments, (iii) professionalfees, (iv) the write-off of unamortized deferred financing costs and anunamortized debt discount and (v) fees associated with a debtor-in-possessioncredit facility. See "Item 8. Financial Statements and Supplementary Data-Note3-Fresh Start Accounting" for more information on amounts recorded toreorganization items, net.Income tax benefit. Our income tax benefit for the year endedDecember 31, 2021 (Successor) was recorded at (0.3)% of pre-tax income. Our income tax benefit forthe period fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor) and theperiod fromNovember 20, 2020 throughDecember 31, 2020 (Successor) was recordedat 6.6% and 7.0% of pre-tax loss, respectively. Our effective tax rate for theyear endedDecember 31, 2021 (Successor) was lower than the effective tax ratefor the previous year primarily due to the impacts of the change in thevaluation allowance, reorganization impacts and the impacts of non-controllinginterests.Income from discontinued operations attributable to Oasis, net of income tax.Income from discontinued operations attributable to Oasis, net of income taxdecreased$112.1 million year over year to$130.6 million during the year endedDecember 31, 2021 (Successor). The decrease was primarily due to$120.9 million of reorganization items recorded during the period fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor) related to our emergence from bankruptcy,consisting of (i) fresh start accounting adjustments of$92.9 million and (ii)reorganization adjustments of$28.0 million . This decrease was coupled withhigher midstream expenses of$68.5 million due to an increase in natural gaspurchase costs and higher depreciation expense of$9.5 million , offset by highermidstream revenues of$61.6 million due to an increase in natural gas revenuesand higher intercompany eliminations for LOE and GPT of$29.2 million . 61
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Liquidity and Capital Resources
Our primary sources of liquidity during the period covered by this report havebeen cash flows from operations, proceeds from the Permian Basin Sale, theissuance of the Oasis Senior Notes and OMP Senior Notes and proceeds from theOMP Equity Offering. Our primary uses of cash have been for net principalpayments under the OMP Credit Facility (defined below), payments for derivativesettlements and modifications, acquisition and development of oil and gasproperties, interest payments on our long-term debt, dividends paid to ourshareholders, payments to repurchase common stock under our share repurchaseprogram and distributions to non-controlling interests. Upon closing of the OMPMerger onFebruary 1, 2022 , the OMP Senior Notes (defined below) were assumed byCrestwood and the OMP Credit Facility (defined below) was paid in full byCrestwood. In addition, following the OMP Merger, we will no longer makedistributions to non-controlling interests, which represented the minorityinterest ownership of OMP. Crestwood has historically declared cashdistributions to its common unitholders, and we expect to receive cashdistributions from Crestwood of approximately$54 million in 2022.We have announced a plan to return$280 million of capital to shareholders overthe next year (approximately$70 million per quarter) through a combination of abase dividend (approximately$45 million ), variable dividends and sharerepurchases. This return of capital plan represents a balanced approach thatreflects our strategic goals of exercising capital discipline while deliveringboth return on and return of capital to shareholders. The Board of Directors hasincreased the quarterly base dividend by 17% from$0.50 per share of commonstock to$0.585 per share of common stock and expects to pay an aggregate basedividend of$11.3 million per quarter during 2022. We expect to return capitalproportionately each quarter through 2022. After the end of each quarter, weexpect to announce a variable dividend based on$70 million less cash utilizedto pay the base dividend and repurchase shares during the prior quarter.Our cash flows depend on many factors, including the price of crude oil andnatural gas and the success of our development and exploration activities aswell as future acquisitions. We actively manage our exposure to commodity pricefluctuations by executing derivative transactions to mitigate the change incrude oil and natural gas prices on our production, thereby mitigating ourexposure to crude oil and natural gas price declines, but these transactions mayalso limit our cash flow in periods of rising crude oil and natural gas prices.During 2021, we entered into a series of transactions with derivativecounterparties to modify the strike price of certain crude oil swap contracts.We modified the strike price on our 2022 crude oil swap contracts covering totalnotional volumes of 6,935 MBbls to a NYMEX WTI price of$70.00 per barrel from aweighted average price of$40.89 per barrel. In addition, we modified the strikeprice on our 2023 crude oil swap contracts covering total notional volumes of5,110 MBbls to a NYMEX WTI price of$50.00 per barrel from a weighted averageprice of$43.68 per barrel. As ofDecember 31, 2021 , our derivative contracts inplace cover 22,495 MBbls of our crude oil production from 2022 through 2023. Foradditional information on the impact of changing prices and our derivativearrangements on our financial position, see "Item 7A. Quantitative andQualitative Disclosures about Market Risk" as well as "Part I, Item 1A. RiskFactors".Our material cash requirements from known obligations include repayment ofoutstanding principal and interest payment obligations under the Oasis SeniorNotes, future obligations to plug, abandon and remediate our oil and gasproperties at the end of their productive lives, and payment obligationspursuant to our operating and finance leases. There were no borrowingsoutstanding under the Oasis Credit Facility (defined below) as ofDecember 31,2021 ; however, on a quarterly basis, we pay a commitment fee of 0.5% on theaverage amount of borrowing base capacity not utilized during the quarter andfees calculated on the average amount of letter of credit balances outstandingduring the quarter.We have contracts which include provisions for the delivery, transport, orpurchase of a minimum volume of crude oil, natural gas, NGLs and water withinspecified time frames, the majority of which are ten years or less. Under theterms of these contracts, if we fail to deliver, transport or purchase thecommitted volumes we will be required to pay a deficiency payment for thevolumes not tendered over the duration of the contract. The estimable futurecommitments under these agreements were approximately$547.7 million as ofDecember 31, 2021 . We recorded a liability as ofDecember 31, 2021 on theConsolidated Balance Sheet of$11.9 million related to unfavorable contractsassumed in connection with theWilliston Basin Acquisition where we determinedit was probable we would not meet the minimum volume commitment. The futurecommitments related to these contracts are included in the above total estimablefuture commitments as ofDecember 31, 2021 .We believe we have adequate liquidity to fund our capital expenditures and tomeet our obligations during the next 12 months and the foreseeable future. As ofDecember 31, 2021 , we had$619.7 million of liquidity available, including$172.1 million in cash and cash equivalents and$447.6 million of aggregateunused borrowing capacity available under the Oasis Credit Facility (definedbelow).Oasis Credit Facility. We have a reserves-based credit agreement (the "OasisCredit Facility"), which has an overall senior secured line of credit of$1,500.0 million , an aggregate amount of elected commitments of$450.0 million and a borrowing base of$900.0 million as ofDecember 31, 2021 . The Oasis CreditFacility matures onMay 19, 2024 . 62
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As ofDecember 31, 2021 , we had no borrowings outstanding and$2.4 million ofoutstanding letters of credit issued under the Oasis Credit Facility, resultingin an unused borrowing capacity of$447.6 million . As ofDecember 31, 2020 , wehad$260.0 million and$6.8 million of outstanding letters of credit issuedunder the Oasis Credit Facility. For the year endedDecember 31, 2021 (Successor), the weighted average interest rate incurred on borrowings under theOasis Credit Facility was 4.2%, compared to 3.6% for the period fromJanuary 1,2020 throughNovember 19, 2020 (Predecessor) and 4.6% for the period fromNovember 20, 2020 throughDecember 31, 2020 (Successor).During the year endedDecember 31, 2021 , the Company entered into variousamendments to the Oasis Credit Facility which, among other things, removed arequirement for the Company to enter into hedges covering minimum productionvolumes, provide for increased flexibility of restricted payments toshareholders, removed a cap on cash netting in the calculation of the leverageratio if no borrowings are outstanding under the Oasis Credit Facility (otherthan letters of credit) and otherwise increased the cap on cash netting to$90.0million and increased the anti-cash hoarding thresholds from$50.0 million to$90.0 million .
We were in compliance with the financial covenants in the Oasis Credit Facilityat
Oasis Senior Notes. OnJune 9, 2021 , we issued in a private placement$400.0million of 6.375% senior unsecured notes dueJune 1, 2026 (the "Oasis Senior Notes"). The Oasis Senior Notes were issued at par and resulted in net proceedsof$391.6 million . We used the proceeds from the Oasis Senior Notes offering tofund a portion of theWilliston Basin Acquisition. Interest is payablesemi-annually onJune 1 andDecember 1 of each year. See "Item 8. FinancialStatements and Supplementary Data-Note 14-Long-Term Debt" for more information.OMP Credit Facility. OMP had a senior secured revolving credit facility (the"OMP Credit Facility") among OMP, as parent,OMP Operating LLC , as borrower,Wells Fargo, as administrative agent and the lenders party thereto. The OMPCredit Facility was paid in full by Crestwood at the closing of the OMP Mergerand has been classified as held for sale on the Consolidated Balance Sheets. AsofDecember 31, 2021 , OMP had$203.0 million of borrowings and$5.5 million ofletters of credit outstanding under the OMP Credit Facility. See "Item 8.Financial Statements and Supplementary Data-Note 6-Discontinued Operations" formore information.OMP Senior Notes. OnMarch 30, 2021 , OMP issued in a private placement$450.0 million of 8.00% senior unsecured notes dueApril 1, 2029 (the "OMPSenior Notes"). The OMP Senior Notes were issued at par and resulted in netproceeds of$442.1 million . Interest on the OMP Senior Notes is payablesemi-annually onApril 1 andOctober 1 of each year. The OMP Senior Notes wereassumed by Crestwood at closing of the OMP Merger and have been classified asheld for sale on the Consolidated Balance Sheets. See "Item 8. FinancialStatements and Supplementary Data-Note 6-Discontinued Operations" for moreinformation.
Cash flows
The Consolidated Statements of Cash Flows have not been recast for discontinuedoperations, therefore the discussion below concerning cash flows from operatingactivities, investing activities and financing activities includes the resultsof both continuing operations and discontinued operations. See "Item 8.Financial Statements and Supplementary Data-Note 6-Discontinued Operations" fordisclosure of cash flow impacts attributable to discontinued operations.
The following table summarizes our change in cash flows (in thousands):
Successor Predecessor Period from Period from November 20, January 1, 2020 Year Ended 2020 through through Year Ended December 31, December 31, November 19, December 31, 2021 2020 2020 2019
Net cash provided by operating activities
$ 202,936 $ 892,853 Net cash used in investing activities (920,769) (9,881) (92,403) (828,756)Net cash provided by (used in) financingactivities 161,190 (85,702) (109,998) (66,268)
Net change in cash and cash equivalents
$ 535 $ (2,171)
Cash flows provided by operating activities
Net cash provided by operating activities increased during the year ended
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impact of volumes and prices on revenues and for more information on increasesand decreases in certain expenses between periods.
Working capital. Our working capital fluctuates primarily as a result of changesin commodity prices and production volumes, capital spending to fund ourdevelopment program and the impact of our outstanding derivative instruments.Excluding the effects of assets held for sale from discontinued operations, wehad a working capital surplus of$60.6 million atDecember 31, 2021 , compared toa working capital deficit of$73.8 million atDecember 31, 2020 . Our workingcapital increased year over year due to increases in cash and cash equivalentsand accounts receivable, offset by increases in revenues and production taxespayable, accrued liabilities and current derivative liabilities.
Cash flows used in investing activities
Net cash used in investing activities increased during the year endedDecember31, 2021 (Successor) primarily due to an increase in payments for derivativesettlements, coupled with payments to modify the terms of outstanding derivativecontracts. In addition, we paid total cash consideration (excluding transactioncosts) of$585.8 million for theWilliston Basin Acquisition. See "Item 8.Financial Statements and Supplementary Data-Note -13-Acquisitions andDivestitures" for more information.
Cash flows provided by (used in) financing activities
Net cash provided by financing activities increased during the year endedDecember 31, 2021 (Successor) primarily due to the issuance of the Oasis SeniorNotes and OMP Senior Notes, partially offset by cash payments for dividends toshareholders and share repurchases.
Capital expenditures
Expenditures for the acquisition and development of oil and gas properties arethe primary use of our capital resources. Our capital expenditures aresummarized in the following table (in thousands):
Successor Predecessor Period from Period from November 20, January 1, 2020 Year Ended 2020 through through Year Ended December 31, December 31, November 19, December 31, 2021 2020 2020 2019Capital expendituresE&P$ 168,189 $ 14,839 $ 194,004 $ 594,217 Other capital expenditures(1) 2,277 179 7,071 15,760Total E&P and other capital expenditures 170,466 15,018 201,075 609,977Acquisitions 586,030 - - 21,010Total capital expenditures from continuing 756,496 15,018 201,075 630,987
operations
Discontinued operations(2) 49,123 3,054 24,266 212,381Total capital expenditures(3)$ 805,619 $ 18,072 $ 225,341 $ 843,368
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(1)Other capital expenditures includes administrative capital and capitalizedinterest.(2)Represents capital expenditures attributable to our midstream assets thatwere classified as discontinued operations. See "Recent Developments-OMP Merger"for additional information.(3)Total capital expenditures (including acquisitions) reflected in the tableabove differs from the amounts for capital expenditures and acquisitions shownin the statements of cash flows in our consolidated financial statements becauseamounts reflected in the table include changes in accrued liabilities from theprevious reporting period for capital expenditures, while the amounts presentedin the statements of cash flows are presented on a cash basis.In 2021, our total E&P and other capital expenditures were$170.5 million , adecrease of 21% as compared to 2020. The decrease was primarily due to areduction in capital expenditures for drilling and completions in thePermianBasin of$68.8 million due to the divestiture of those assets in June of 2021.This was partially offset by an increase in capital expenditures for drillingand completions in theWilliston Basin of$40.0 million due to higher activitycompared to 2020 when we temporarily suspended drilling and completionsactivity. As ofDecember 31, 2021 , we had two operated rigs running. Inaddition, midstream capital expenditures, which have been classified asdiscontinued operations, increased$21.8 million primarily due to an increase incapital expenditures for gathering infrastructure.Our planned 2022 E&P capital expenditures are expected to approximate$295million . We expect to run two operated rigs during 2022 and plan to complete 40to 42 gross operated wells with an average working interest of approximately72%. 64
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The ultimate amount of capital we will expend may fluctuate materially based onmarket conditions and the success of our drilling and operations results as theyear progresses. Our capital plan may further be adjusted as business conditionswarrant. The amount, timing and allocation of capital expenditures is largelydiscretionary and within our control. If crude oil prices decline substantiallyor for an extended period of time, we could defer a significant portion of ourplanned capital expenditures until later periods to prioritize capital projectsthat we believe have the highest expected returns and potential to generatenear-term cash flows. We routinely monitor and adjust our capital expendituresin response to changes in prices, availability of financing, drilling andacquisition costs, industry conditions, the timing of regulatory approvals, theavailability of rigs, success or lack of success in drilling activities,contractual obligations, internally generated cash flows and other factors bothwithin and outside our control. Furthermore, we actively review acquisitionopportunities on an ongoing basis. If we acquire additional acreage, our capitalexpenditures may be higher than planned. However, our ability to makesignificant acquisitions for cash would require us to obtain additional equityor debt financing, which we may not be able to obtain on terms acceptable to usor at all.We believe that cash on hand, cash flows from operating activities, includingcash settlement receipts or payments under our derivative contracts, andavailability under the Oasis Credit Facility should be sufficient to fund our2022 capital expenditure plan and to meet our future obligations.
Dividends
During 2021, we paid regular cash dividends of$1.625 per share of common stocktotaling$32.3 million and a special dividend of$4.00 per share of common stocktotaling$80.0 million . OnFebruary 9, 2022 , we declared a dividend of$0.585 per share of common stock ($2.34 per share annualized) payable onMarch 4, 2022 to shareholders of record as ofFebruary 21, 2022 .We recently announced an updated return of capital plan and expect to pay a basedividend and a variable dividend in 2022. The base dividend is expected to be$11.3 million in aggregate per quarter, and we expect to announce a variabledividend after each quarter based on$70 million less cash utilized to pay thebase dividend and repurchase shares during the prior quarter.
Future dividend payments will depend on our earnings, financial condition,capital requirements, level of indebtedness, statutory and contractualrestrictions applicable to the payment of dividends and other considerationsthat the Board of Directors deems relevant.
Share Repurchase Program
InMarch 2021 , the Board of Directors authorized a share-repurchase programcovering up to$100.0 million of the Company's common stock. During the yearendedDecember 31, 2021 , we repurchased 871,018 shares of common stock at aweighted average price of$114.79 per common share for a total cost of$100.0million .The Board of Directors has authorized a new$150.0 million share repurchaseprogram, which replaces the$100.0 million share repurchase program that wasfully utilized in 2021. The$150.0 million share repurchase program will be inplace through the end of 2022 and is part of the Company's plan to return$280million of capital to shareholders over the next year.
Tax Benefits Preservation Plan
Upon emergence from bankruptcy inNovember 2020 , the Company experienced an"ownership change" as defined by Section 382 of the Code. Under Section 382 ofthe Code, the Company's Tax Benefits are potentially subject to variouslimitations going forward. However, the Company believes that it qualified for,and as a result, utilized an exception under Section 382(l)(5) of the Code fromthe limitation that would otherwise be imposed under Section 382 of the Code. InAugust 2021 , the Board of Directors adopted a Tax Benefits Preservation Plan(the "Tax Plan") designed to protect the availability of the Company's TaxBenefits. Adopting the Tax Plan reduced the likelihood that changes in theCompany's investor base would limit the Company's future use of its TaxBenefits. OnFebruary 1, 2022 , the Company announced the termination of the TaxPlan after the Board of Directors determined the Tax Plan was no longernecessary or desirable for the preservation of the Tax Benefits.
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operationsare based upon our audited consolidated financial statements, which have beenprepared in accordance with GAAP. The preparation of our consolidated financialstatements requires us to make estimates and assumptions that affect thereported amounts of assets, liabilities, revenues and expenses and relateddisclosure of contingent assets and liabilities. Certain accounting policiesinvolve judgments and uncertainties to such an extent that there is reasonablelikelihood that materially different amounts could have been reported underdifferent conditions, or if different assumptions had been used. We evaluate ourestimates and assumptions on a regular basis. We base our estimates onhistorical experience and various other assumptions that are believed to bereasonable under the circumstances, the results of which form the basis formaking judgments about the carrying values of assets and liabilities that arenot readily apparent from other sources. Actual results may differ from theseestimates and assumptions used in preparation 65
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of our consolidated financial statements. We provide expanded discussion of ourmore significant accounting policies, estimates and judgments used inpreparation of our consolidated financial statements below. See "Item 8.Financial Statements and Supplementary Data-Note 4-Summary of SignificantAccounting Policies" for a discussion of additional accounting policies andestimates made by management as well as the expected impact of recent accountingpronouncements on our consolidated financial statements.
Method of accounting for oil and gas properties
Crude oil and natural gas exploration and development activities are accountedfor using the successful efforts method. Under this method, all propertyacquisition costs and costs of exploratory and development wells are capitalizedwhen incurred, pending determination of whether the well has found provedreserves. If an exploratory well does not find proved reserves, the costs ofdrilling the well are charged to expense. The costs of development wells arecapitalized whether productive or nonproductive. Expenditures for maintenance,repairs and minor renewals necessary to maintain properties in operatingcondition are expensed as incurred. Major betterments, replacements and renewalsare capitalized to the appropriate property and equipment accounts. Estimateddismantlement and abandonment costs for oil and gas properties are capitalizedat their estimated net present value.The provision for DD&A of oil and gas properties is calculated using theunit-of-production method. All capitalized well costs (including futureabandonment costs, net of salvage value) and leasehold costs of provedproperties are amortized on a unit-of-production basis over the remaining lifeof proved developed reserves and total proved reserves, respectively, related tothe associated field. Natural gas is converted to barrel equivalents at the rateof six thousand cubic feet of natural gas to one barrel of crude oil.Costs of retired, sold or abandoned properties that constitute a part of anamortization base are charged or credited, net of proceeds, to accumulated DD&Aunless doing so significantly affects the unit-of-production amortization ratein which case a gain or loss is recognized currently.Unproved properties consist of costs incurred to acquire unproved leases, orlease acquisition costs. Lease acquisition costs are capitalized until theleases expire or when we specifically identify leases that will revert to thelessor, at which time we expense the associated lease acquisition costs. Theexpensing of the lease acquisition costs is recorded as impairment in ourConsolidated Statements of Operations. Lease acquisition costs related tosuccessful exploratory drilling are reclassified to proved properties anddepleted on a unit-of-production basis.For sales of entire working interests in unproved properties, gain or loss isrecognized to the extent of the difference between the proceeds received and thenet carrying value of the property. Proceeds from sales of partial interests inunproved properties are accounted for as a recovery of costs unless the proceedsexceed the entire cost of the property.
Crude oil and natural gas reserve quantities and Standardized Measure ofdiscounted future net cash flows
Our independent reserve engineers and technical staff prepare our estimates ofcrude oil and natural gas reserves and associated future net revenues. While theSEC rules allow us to disclose proved, probable and possible reserves, we haveelected to disclose only proved reserves in this Annual Report on Form 10-K. TheSEC's rules define proved reserves as the quantities of oil and gas, which, byanalysis of geoscience and engineering data, can be estimated with reasonablecertainty to be economically producible from a given date forward, from knownreservoirs, and under existing economic conditions, operating methods andgovernment regulations prior to the time at which contracts providing the rightto operate expire, unless evidence indicates that renewal is reasonably certain,regardless of whether deterministic or probabilistic methods are used for theestimation. The project to extract the hydrocarbons must have commenced or theoperator must be reasonably certain that it will commence the project within areasonable time. Our independent reserve engineers and technical staff must makea number of subjective assumptions based on their professional judgment indeveloping reserve estimates. Reserve estimates are updated annually andconsider recent production levels and other technical information about eachfield. Crude oil and natural gas reserve engineering is a subjective process ofestimating underground accumulations of crude oil and natural gas that cannot beprecisely measured. The accuracy of any reserve estimate is a function of thequality of available data and of engineering and geological interpretation andjudgment.Periodic revisions to the estimated reserves and related future net cash flowsmay be necessary as a result of a number of factors, including reservoirperformance, new drilling, crude oil and natural gas prices, cost changes,technological advances, new geological or geophysical data or other economicfactors. Accordingly, reserve estimates are generally different from thequantities of crude oil and natural gas that are ultimately recovered. We cannotpredict the amounts or timing of future reserve revisions. If such revisions aresignificant, they could significantly affect future amortization of capitalizedcosts and result in impairment of assets that may be material. 66
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Revenue recognition
We recognize revenue in accordance with Accounting Standards Codification 606,Revenue from Contracts with Customers ("ASC 606"). ASC 606 includes a five-steprevenue recognition model to depict the transfer of goods or services tocustomers in an amount that reflects the consideration to which we expect to beentitled in exchange for those goods or services. The unit of account in ASC 606is a performance obligation, which is a promise in a contract to transfer to acustomer either a distinct good or service (or bundle of goods or services) or aseries of distinct goods or services provided over a period of time. ASC 606requires that a contract's transaction price, which is the amount ofconsideration to which an entity expects to be entitled in exchange fortransferring promised goods or services to a customer, is to be allocated toeach performance obligation in the contract based on relative standalone sellingprices and recognized as revenue when (point in time) or as (over time) theperformance obligation is satisfied.Crude oil, natural gas and NGL revenues from our interests in producing wellsare recognized when we satisfy a performance obligation by transferring controlof a product to a customer. Substantially all of our crude oil and natural gasproduction is sold to purchasers under short-term (less than 12-month) contractsat market-based prices, and our NGL production is sold to purchasers underlong-term (more than 12-month) contracts at market-based prices. The salesprices for crude oil, natural gas and NGLs are adjusted for transportation andother related deductions. These deductions are based on contractual orhistorical data and do not require significant judgment. Subsequently, theserevenue deductions are adjusted to reflect actual charges based on third-partydocuments. Since there is a ready market for crude oil, natural gas and NGL, wesell the majority of our production soon after it is produced at variouslocations. As a result, we maintain a minimum amount of product inventory instorage.Our purchased crude oil and natural gas sales are derived from the sales ofcrude oil and natural gas purchased from third parties. Revenues and expensesfrom these sales and purchases are recorded on a gross basis when we act as aprincipal in these transactions by assuming control of the purchased crude oilor natural gas before it is transferred to the customer. In certain cases, weenter into sales and purchases with the same counterparty in contemplation ofone another, and these transactions are recorded on a net basis in accordancewith Accounting Standards Codification 845, Nonmonetary Transactions.
Impairment of proved properties
We review our proved oil and gas properties for impairment whenever events andcircumstances indicate that a decline in the recoverability of their carryingvalue may have occurred. We estimate the expected undiscounted future cash flowsof our oil and gas properties by field and compare such undiscounted future cashflows to the carrying amount of the oil and gas properties in the applicablefield to determine if the carrying amount is recoverable. The factors used todetermine the undiscounted future cash flows are subject to our judgment andexpertise and include, but are not limited to, estimates of proved reserves,future commodity pricing, future production estimates and estimates of operatingand development costs. If the carrying amount exceeds the estimated undiscountedfuture cash flows, we will adjust the carrying amount of the oil and gasproperties to fair value. The factors used to determine fair value are subjectto our judgment and expertise and include, but are not limited to, our estimatedundiscounted future cash flows and the discount rate commensurate with the riskand current market conditions associated with realizing the expected cash flowsprojected. Because of the uncertainty inherent in these factors, we cannotpredict when or if future impairment charges for proved oil and gas propertieswill be recorded.
Impairment of unproved properties
The assessment of unproved properties to determine any possible impairmentrequires significant judgment. We assess our unproved properties periodicallyfor impairment on a property-by-property basis based on remaining lease terms,drilling results or future plans to develop acreage.We recognize impairment expense for unproved properties at the time when thelease term has expired or sooner based on management's periodic assessments. Weconsider the following factors in our assessment of the impairment of unprovedproperties:
•the remaining amount of unexpired term under our leases;
•our ability to actively manage and prioritize our capital expenditures to drillleases and to make payments to extend leases that may be close to expiration;
•our ability to exchange lease positions with other companies that allow forhigher concentrations of ownership and development;
•our ability to convey partial mineral ownership to other companies in exchangefor their drilling of leases; and
•our evaluation of the continuing successful results from the application ofcompletion technology in the Bakken andThree Forks formations in theWillistonBasin by us or by other operators in areas adjacent to or near our unprovedproperties. 67
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Asset retirement obligations
We record the fair value of a liability for a legal obligation to retire anasset in the period in which the liability is incurred and can be reasonablyestimated with the corresponding cost capitalized by increasing the carryingamount of the related long-lived asset. For oil and gas properties and producedwater disposal wells, this is the period in which the well is drilled oracquired. The asset retirement obligation ("ARO") represents the estimatedamount we will incur to plug, abandon and remediate the properties at the end oftheir productive lives, in accordance with applicable state laws. The liabilityis accreted to its present value each period, and the capitalized costs areamortized on the unit-of-production method. The accretion expense is recorded asa component of depreciation, depletion and amortization in our ConsolidatedStatements of Operations.We determine the ARO by calculating the present value of estimated future cashflows related to the liability. Estimating the future ARO requires management tomake estimates and judgments regarding timing and existence of a liability, aswell as what constitutes adequate restoration. Inherent in the fair valuecalculation are numerous assumptions and judgments including the ultimate costs,inflation factors, credit adjusted discount rates, timing of settlement andchanges in the legal, regulatory, environmental and political environments. Ifactual results are not consistent with our assumptions and estimates or ourassumptions and estimates change due to new information, we may be exposed tofuture revisions, which could result in an increase to the existing AROliability and could ultimately result in a higher potential impact on ouroperations and cash flows for settlement charges. To the extent future revisionsto these assumptions impact the fair value of the existing ARO liability, acorresponding adjustment is made to the related asset.
Derivatives
We record all derivative instruments on the Consolidated Balance Sheets aseither assets or liabilities measured at their estimated fair value. Thesignificant inputs used to estimate fair value are crude oil and natural gasprices, volatility, skew, discount rate and the contract terms of the derivativeinstruments. Derivative assets and liabilities arising from derivative contractswith the same counterparty are reported on a net basis, as all counterpartycontracts provide for net settlement. We have not designated any derivativeinstruments as hedges for accounting purposes, and we do not enter into suchinstruments for speculative trading purposes. Gains and losses from valuationchanges in commodity derivative instruments are reported under other income(expense) in our Consolidated Statements of Operations. Our cash flow is onlyimpacted when the actual settlements under the derivative contracts result inmaking or receiving a payment to or from the counterparty. These cashsettlements represent the cumulative gains and losses on our derivativeinstruments and do not include a recovery of costs that were paid to acquire ormodify the derivative instruments that were settled. Cash settlements arereflected as investing activities in our Consolidated Statements of Cash Flows.
Equity-based compensation
We grant various types of equity-based awards, including restricted stockawards, restricted stock units, performance share units, phantom units, andother awards under any long-term incentive plan then in effect to employees andnon-employee directors. We determine the compensation expense for share-settledawards based on the grant date fair value, and such expense is recognizedratably over the requisite service period, which is generally the vestingperiod. Cash-settled awards are classified as liabilities. Compensation expensefor cash-settled awards is recognized over the requisite service period and isremeasured at the fair value of such awards at the end of each reporting period.Forfeitures are accounted for as they occur by reversing the expense previouslyrecognized for awards that were forfeited during the period.The fair values of awards are determined based on the type of award and mayutilize market prices on the date of grant (for service-based equity awards) orat the end of the reporting period (for liability-classified awards),MonteCarlo simulations or other acceptable valuation methodologies, as appropriatefor the type of award. A Monte Carlo simulation model uses assumptions regardingrandom projections and must be repeated numerous times to achieve aprobabilistic assessment. The key valuation assumptions for theMonte Carlo model are the forecast period, risk-free interest rates, stock price volatility,initial value, stock price on the date of grant and correlation coefficients.
See "Item 8. Financial Statements and Supplementary Data-Note 17-Equity-BasedCompensation" for additional information regarding our equity-basedcompensation.
Income taxes
Our provision for taxes includes both federal and state income taxes. We recordour income taxes in accordance with ASC 740, which results in the recognition ofdeferred tax assets and liabilities for the expected future tax consequences oftemporary differences between the book carrying amounts and the tax basis ofassets and liabilities. Deferred tax assets and liabilities are measured usingenacted tax rates expected to apply to taxable income in the years in whichthose temporary differences and carryforwards are expected to be recovered orsettled. The effect on deferred tax assets and liabilities of a change in taxrates is recognized in income in the period that includes the enactment date. Avaluation allowance is established to reduce deferred tax assets if it is morelikely than not that the related tax benefits will not be realized. 68
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We apply significant judgment in evaluating our tax positions and estimating ourprovision for income taxes. During the ordinary course of business, there may betransactions and calculations for which the ultimate tax determination isuncertain. The actual outcome of these future tax consequences could differsignificantly from our estimates, which could impact our financial position,results of operations and cash flows.We also account for uncertainty in income taxes recognized in the financialstatements in accordance with GAAP by prescribing a recognition threshold andmeasurement attribute for a tax position taken or expected to be taken in a taxreturn. Authoritative guidance for accounting for uncertainty in income taxesrequires that we recognize the financial statement benefit of a tax positiononly after determining that the relevant tax authority would more likely thannot sustain the position following an audit. For tax positions meeting themore-likely-than-not threshold, the amount recognized in the financialstatements is the largest benefit that has a greater than 50% likelihood ofbeing realized upon ultimate settlement with the relevant tax authority.
Non-GAAP Financial Measures
Cash G&A, Cash Interest, Adjusted EBITDA and Adjusted Free Cash Flow aresupplemental non-GAAP financial measures that are used by management andexternal users of our financial statements, such as industry analysts,investors, lenders and rating agencies. These non-GAAP financial measures shouldnot be considered in isolation or as a substitute for G&A expenses, interestexpense, net income (loss), or net cash provided by (used in) operatingactivities or any other measures prepared under GAAP. Because these non-GAAPfinancial measures exclude some but not all items that affect net income (loss)and may vary among companies, the amounts presented may not be comparable tosimilar metrics of other companies.
Cash G&A
We define Cash G&A as total G&A expenses less G&A expenses attributable todiscontinued operations, G&A expenses attributable to shared service allocationsto our midstream operations, non-cash equity-based compensation expenses andother non-cash charges. Cash G&A is not a measure of G&A expenses as determinedby GAAP. Management believes that the presentation of Cash G&A provides usefuladditional information to investors and analysts to assess our operating costsin comparison to peers without regard to G&A expenses that were allocated to ourmidstream operations, equity-based compensation programs and other non-cashitems, which can vary substantially from company to company.The following table presents a reconciliation of the GAAP financial measure ofG&A expenses to the non-GAAP financial measure of Cash G&A for the periodspresented (in thousands): Successor Predecessor Period from November 20, Period from Year Ended 2020 through January 1, 2020 Year Ended December 31, December 31, through November December 31, 2021 2020 19, 2020 2019
General and administrative expenses
$ 145,294 $ 123,506 Less: General and administrative expensesattributable to discontinued operations 4,193 (579) 594 (5,089)General and administrative expensesattributable to continuing operations 80,688 14,803 144,700 128,595G&A expenses attributable to shared services (19,443) (2,569) (18,881) (19,648)Equity-based compensation expenses (14,663) - (29,794) (32,755)Other non-cash adjustments (371) - - -Cash G&A$ 46,211 $ 12,234 $ 96,025 $ 76,192 Cash InterestWe define Cash Interest as interest expense less interest expense attributableto discontinued operations plus capitalized interest less amortization andwrite-offs of deferred financing costs and debt discounts. Cash Interest is nota measure of interest expense as determined by GAAP. Management believes thatthe presentation of Cash Interest provides useful additional information toinvestors and analysts for assessing the interest charges incurred on our debtto finance our E&P activities, excluding non-cash amortization, and our abilityto maintain compliance with our debt covenants. 69
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The following table presents a reconciliation of the GAAP financial measure ofinterest expense to the non-GAAP financial measure of Cash Interest for theperiods presented (in thousands):
Successor Predecessor Period from Period from November 20, January 1, 2020 Year Ended 2020 through through Year Ended December 31, December 31, November 19, December 31, 2021 2020 2020(1) 2019Interest expense$ 67,751 $ 3,168 $ 181,484 $ 176,223 Less: Interest expense attributable todiscontinued operations 36,945 1,148 39,648 16,936Interest expense attributable tocontinuing operations 30,806 2,020 141,836 159,287Capitalized interest 2,077 128 6,106 11,270Amortization of deferred financingcosts(2) (13,727) (152) (6,865) (7,886)Amortization of debt discount - - (8,317) (12,164)Cash Interest$ 19,156 $ 1,996 $ 132,760 $ 150,507
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(1)For the period fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor),interest expense and cash interest include a specified default interest chargeof$30.3 million attributable to continuing operations. In addition, for theperiod fromJanuary 1, 2020 throughNovember 19, 2020 (Predecessor), interestexpense includes a specified default interest charge of$28.0 million attributable to discontinued operations. These specified default interestcharges were waived on the Emergence Date.(2)For the year endedDecember 31, 2021 (Successor), we incurred a$7.8 million fee to enter into a commitment letter for a senior secured second lien facility.The senior secured second lien facility was terminated prior to being drawn.
Adjusted EBITDA and Adjusted Free Cash Flow
We define Adjusted EBITDA as earnings (loss) before interest expense, incometaxes, DD&A, exploration expenses and other similar non-cash or non-recurringcharges. We define Adjusted EBITDA from continuing operations as Adjusted EBITDAless Adjusted EBITDA attributable to discontinued operations, plus distributionsfrom OMP. We define Adjusted Free Cash Flow as Adjusted EBITDA from continuingoperations less Cash Interest and E&P and other capital expenditures (excludingcapitalized interest and acquisition capital).Adjusted EBITDA and Adjusted Free Cash Flow are not measures of net income(loss) or cash flows as determined by GAAP. Management believes that thepresentation of Adjusted EBITDA and Adjusted Free Cash Flow provides usefuladditional information to investors and analysts for assessing our results ofoperations, financial performance, ability to generate cash from our businessoperations without regard to our financing methods or capital structure and ourability to maintain compliance with our debt covenants.The following table presents reconciliations of the GAAP financial measures ofnet income (loss) including non-controlling interests and net cash provided byoperating activities to the non-GAAP financial measures of Adjusted EBITDA andAdjusted Free Cash Flow for the periods presented (in thousands): Successor Predecessor Period from November 20, Year Ended 2020 through Period from January Year Ended December 31, December 31, 1, 2020 through December 31, 2021 2020 November 19, 2020 2019
Net income (loss) including non-controlling
$ (3,724,611) $ (90,647)
interests
(Gain) loss on sale of properties (222,806) (11) (10,396) 4,455Gain on extinguishment of debt - - (83,867) (4,312)Net (gain) loss on derivative instruments 589,641 84,615 (233,565) 106,314Derivative settlements (270,118) (76) 224,416 19,098Interest expense, net of capitalized interest 67,751 3,168 181,484 176,223Depreciation, depletion and amortization 158,304 16,094 291,115 787,192Impairment 5 - 4,937,143 10,257Rig termination - - 1,279 384Exploration expenses 2,760 - 2,748 6,658 70
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Table of Contents Successor Predecessor Period from Period from November 20, January 1, 2020 Year Ended 2020 through through Year Ended December 31, December 31, November 19, December 31, 2021 2020 2020 2019Equity-based compensation expenses 15,476 270 31,315 33,607Litigation settlement - - 22,750 20,000Reorganization items, net - - (786,831) -Income tax benefit (956) (3,447) (262,962) (32,715)Other non-cash adjustments 123 468 2,324 3,035Adjusted EBITDA 695,478 55,119 592,342 1,039,549Adjusted EBITDA attributable to discontinued (216,540) (22,309) (173,457) (241,226)
operations
Cash distributions from OMP and DevCo 71,781 7,734 123,057 150,388
Interests
Adjusted EBITDA from continuing operations 550,719 40,544 541,942 948,711Cash Interest (19,156) (1,996) (132,760) (150,507)E&P and other capital expenditures (170,466) (15,018) (201,075) (609,977)Midstream capital expenditures attributable - (1,173) (6,147) (14,353)to DevCo InterestsCapitalized interest 2,077 128 6,106 11,270Adjusted Free Cash Flow$ 363,174 $ 22,485 $ 208,066 $ 185,144
Net cash provided by operating activities
$ 202,936 $ 892,853 Derivative settlements (270,118) (76) 224,416 19,098Interest expense, net of capitalized 67,751 3,168 181,484 176,223interestRig termination - - 1,279 384Exploration expenses 2,760 - 2,748 6,658Deferred financing costs amortization and (12,991) (6,824) (41,811) (27,263)
other
Current tax (benefit) expense 21 - (36) (16)Changes in working capital (6,204) (36,872) (25,953) (51,423)Litigation settlement - - 22,750 20,000Cash paid for reorganization items - - 22,205 -Other non-cash adjustments 123 468 2,324 3,035Adjusted EBITDA 695,478 55,119 592,342 1,039,549Adjusted EBITDA attributable to discontinued (216,540) (22,309) (173,457) (241,226)
operations
Cash distributions from OMP and DevCo 71,781 7,734 123,057 150,388
Interests
Adjusted EBITDA from continuing operations 550,719 40,544 541,942 948,711Cash Interest (19,156) (1,996) (132,760) (150,507)E&P and other capital expenditures (170,466) (15,018) (201,075) (609,977)Midstream capital expenditures attributable - (1,173) (6,147) (14,353)to DevCo InterestsCapitalized interest 2,077 128 6,106 11,270Adjusted Free Cash Flow$ 363,174 $ 22,485 $ 208,066 $ 185,144 71
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