# Chord Energy Corp (CHRD) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Chord Energy Corp's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1486159/000148615922000014/oas-20211231.htm
Accession: 0001486159-22-000014
Filing date: 2022-02-25
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/CHRD/
All MD&A years: /company/CHRD/mda/
Next year: /company/CHRD/mda/fy2022/ (FY 2022)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The Consolidated Balance Sheets and Consolidated Statements of Operations have been recast from prior periods to reflect the OMP Merger (defined below) as a discontinued operation. Refer to “Part II, Item 8. Financial Statements and Supplementary Data—Note 6—Discontinued Operations.” In addition, the following discussion 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, and often do, vary from actual results, and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report for an explanation of these types of statements.

For discussion related to changes in financial condition and results of operations for the years ended December 31, 2020 and 2019, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on March 8, 2021.

Overview

We are an independent E&P company with quality and sustainable long-lived assets in the North Dakota and Montana regions of the Williston Basin. Our mission is to improve lives by safely and responsibly providing affordable, reliable and abundant energy. We are uniquely positioned with a best-in-class balance sheet and are focused on rigorous capital discipline and generating free cash flow by operating efficiently, safely and responsibly to develop our unconventional onshore oil-rich resources in the continental United States.

Recent Developments

Return of Capital Plan

On February 9, 2022, we announced a plan to return $280 million of capital to shareholders over the next year ($70 million per quarter) through a combination of a base dividend (approximately $45 million), variable dividends and share repurchases. This return of capital plan represents a balanced approach that reflects our strategic goals of exercising capital discipline while delivering both return on and return of capital to shareholders. The Board of Directors has increased the quarterly base dividend by 17% from $0.50 per share of common stock to $0.585 per share of common stock and expects to pay an aggregate base dividend of $11.3 million per quarter during 2022. The Board of Directors declared the base dividend for the fourth quarter of 2021 of $0.585 per share of common stock ($2.34 per share annualized) payable on March 4, 2022 to shareholders of record as of February 21, 2022. In addition, the Board of Directors authorized a new $150.0 million share repurchase program to replace the $100.0 million share repurchase program that was fully utilized in 2021. We expect to return capital proportionately each quarter through 2022. After the end of each quarter, we expect to announce a variable dividend based on $70 million less cash utilized to pay the base dividend and repurchase shares during the prior quarter. See “Liquidity and Capital Resources” below for additional information.

Williston Basin Acquisition

On October 21, 2021, we completed our acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy, Inc. for total cash consideration of $585.8 million (the “Williston Basin Acquisition”). The total cash consideration paid was comprised of a deposit of $74.5 million paid on May 3, 2021 and $511.3 million paid at closing on October 21, 2021. The Williston Basin Acquisition was funded with cash on hand, which included proceeds from the Permian Basin Sale (defined below) and the Oasis Senior Notes (defined below).

Permian Basin Sale

On June 29, 2021, we completed the sale of our upstream assets in the Texas region of the Permian Basin, effective March 1, 2021, to Percussion Petroleum Operating II, LLC (“Percussion”) for an aggregate purchase price of $450.0 million (the “Primary Permian Basin Sale”). The purchase price consisted of $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 daily settlement price of NYMEX West Texas Intermediate (“NYMEX WTI”) crude oil exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”). We received cash proceeds of $342.3 million after purchase price adjustments that were primarily related to cash flows from the effective date to the close date. The total consideration remains subject to earn-out payments related to the Permian Basin Sale Contingent Consideration.

In addition to the Primary Permian Basin Sale, we also divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 (the “Additional Permian Basin Sale” and together with the Primary

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Permian Basin Sale, the “Permian Basin Sale”). We received cash proceeds from the Additional Permian Basin Sale of $30.0 million.

OMP Merger

On October 25, 2021, OMP and OMP GP entered into the OMP Merger pursuant to which we agreed to sell to Crestwood our entire ownership of OMP common units and all of the limited liability company interests of OMP GP in exchange for $160.0 million in cash and approximately 21 million common units representing limited partner interests of Crestwood. The OMP Merger was unanimously approved by the Board of Directors of both Oasis and Crestwood and was also unanimously approved by the Board of Directors and Conflicts Committee of OMP GP.

The OMP Merger was completed on February 1, 2022 and we own approximately 21.7% of Crestwood’s issued and outstanding common units, and we are Crestwood’s largest single customer. In connection with the closing of the OMP Merger, the Company and Crestwood executed a director nomination agreement pursuant to which we designated two directors to the Board of Directors of Crestwood GP.

The OMP Merger represents a strategic shift for the Company and qualified for reporting as a discontinued operation. See “Item 8. Financial Statements and Supplementary Data—Note 5—Oasis Midstream Partners.”

Change in Chief Executive Officer

On April 13, 2021, Daniel E. Brown was appointed Chief Executive Officer of the Company. At the same time, Mr. Brown was also appointed to the Company’s Board of Directors. Mr. Brown replaced Douglas E. Brooks, who was previously appointed to serve as Chief Executive Officer on an interim basis. Mr. Brooks continues to serve in his role as Board Chair.

Market Conditions and COVID-19

COVID-19 remains a global health crisis and there continues to be considerable uncertainty regarding the extent to which COVID-19 and its variants will continue to spread. Despite improvements in global economic activity levels and higher energy demand compared to 2020, the impacts of COVID-19 continue to be unpredictable, including the impacts of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. We are unable to reasonably estimate the period of time that related conditions could exist or the extent to which they could impact our business, results of operations, financial condition or cash flows. Commodity prices have risen from historic lows in 2020; however, further negative impacts from COVID-19 may require us to adjust our business plan.

We are committed to the health and safety of our employees, contractors and communities. We have established appropriate policies and procedures while we have continued to operate during the COVID-19 pandemic. All managers and supervisors 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 and guidance, engages with peer companies, and participates with industry associations to ensure alignment with guidance for employee health and safety.

In September 2021, President Biden announced a COVID-19 action plan that would have the Occupational Safety and Health Administration (“OSHA”) develop an Emergency Temporary Standard (“ETS”) which may include new obligations for employers with one hundred or more employees with respect to vaccinations, testing and paid time off. In November 2021, OSHA published an ETS that requires covered employers to take affirmative steps to address COVID-19 safety, including having a written COVID-19 vaccination policy and having a process in place where employees are able to confidentially submit proof of vaccination status. The ETS also requires any employee who is not fully vaccinated to wear a face covering at the workplace, effective January 20, 2022, and be subject to regular COVID-19 testing, effective February 9, 2022. In connection with the ETS, we established a policy to comply with OSHA’s ETS on vaccination, testing and face coverings that applies to all of our employees. On January 13, 2022, the U.S. Supreme Court stayed the OSHA ETS. We monitor mandates related to COVID-19 at both the federal and state levels on an ongoing basis and continue to assess the potential impacts of those mandates.

Commodity Prices

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations 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 a broader array of potential purchasers. We enter into crude oil, natural gas and NGL sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical

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delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows. Please see “Part I, Item 1. Business—Exploration and Production Operations—Marketing and major customers.”

Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented:

[[GREPCENT_TABLE]]
[["","2021 (Successor)","","","Year ended December 31, 2021 (Successor)"],["","Q1","","Q2","","Q3","","Q4"],["Average Realized Crude Oil Prices ($/Bbl)(1)","$","56.09","","","$","65.53","","","$","70.11","","","$","76.37","","","","$","67.49"],["Average Price Differential ($/Bbl)(2)","$","1.58","","","$","0.61","","","$","0.43","","","$","0.24","","","","$","0.70"],["Average Price Differential Percentage(2)","3","%","","1","%","","1","%","","0.3","%","","","1","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","Predecessor","","","Successor"],["","2020","","Period from October 1, 2020 through November 19, 2020","","","Period from November 20, 2020 through December 31, 2020"],["","Q1","","Q2","","Q3"],["Average Realized Crude Oil Prices ($/Bbl)(1)","$","43.22","","","$","24.45","","","$","38.52","","","$","37.67","","","","$","43.36"],["Average Price Differential ($/Bbl)(2)","$","3.19","","","$","2.90","","","$","2.44","","","$","2.07","","","","$","3.16"],["Average Price Differential Percentage(2)","7","%","","11","%","","6","%","","5","%","","","7","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","2019 (Predecessor)","","Year ended December 31, 2019 (Predecessor)"],["","Q1","","Q2","","Q3","","Q4"],["Average Realized Crude Oil Prices ($/Bbl)(1)","$","53.52","","","$","58.87","","","$","55.12","","","$","53.66","","","$","55.27"],["Average Price Differential ($/Bbl)(2)","$","1.30","","","$","0.96","","","$","1.30","","","$","3.23","","","$","1.68"],["Average Price Differential Percentage(2)","2","%","","2","%","","2","%","","6","%","","3","%"]]
[[/GREPCENT_TABLE]]

__________________ 

(1)Realized crude oil prices do not include the effect of derivative contract settlements.

(2)Price differential reflects the difference between our realized crude oil prices and NYMEX WTI crude oil index prices.

We sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. As of December 31, 2021, 95% of our gross operated crude oil production was connected to gathering systems, which originate at the wellhead and reduce the need to transport barrels by truck from the wellhead. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Expansions of both rail and pipeline facilities in the Williston Basin has reduced prior constraints on crude oil takeaway 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 operations in the Consolidated Statement of Operations for the year ended December 31, 2021 (Successor). Prior periods have been recast so that the basis of presentation is consistent with that of the 2021 consolidated financial statements. See “Item 8. Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for additional information.

In addition, we emerged from bankruptcy on November 19, 2020 (the “Emergence Date”) and adopted fresh start accounting, which resulted in us becoming a new entity for financial reporting purposes. Accordingly, the consolidated financial statements on or after November 19, 2020 are not comparable to the consolidated financial statements prior to that date. References to “Successor” relate to our financial position and results of operations as of and subsequent to the Emergence Date. References to “Predecessor” relate to our financial position prior to, and our results of operations through and including, the Emergence Date.

Highlights

During the year ended December 31, 2021 (Successor):

•Production volumes averaged 58,032 Boepd (64% oil).

•Lease operating expenses were $9.63 per Boe, compared to $9.27 per Boe during the period from November 20, 2020 through December 31, 2020 (Successor) and $7.55 per Boe during the period from January 1, 2020 through November 19, 2020 (Predecessor).

•E&P and other capital expenditures, excluding capitalized interest and acquisition capital, were $168.4 million.

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•Estimated net proved reserves were 250.9 MMBoe as of December 31, 2021, with a Standardized Measure of $2.7 billion and PV-10 of $3.1 billion.

•Paid regular cash dividends of $1.625 per share of common stock and a special dividend of $4.00 per share of common stock.

•Completed $100.0 million share repurchase program.

Revenues

Our crude oil and natural gas revenues are derived from the sale of crude oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result 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 oil and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil and natural gas sales and purchases are recorded on a gross basis when we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

Our other services revenues are derived from equipment rentals, and also included revenues for well completion services and product sales prior to our transition of our well fracturing services from Oasis Well Services LLC (“OWS”), a wholly-owned subsidiary, to a third-party provider during the first quarter of 2020 (the “Well Services Exit”). Substantially all of our other services revenues are from services provided to our operated wells. Intercompany revenues for work performed for our ownership interests are eliminated in consolidation, and only the revenues related to non-affiliated interest owners and other third-party customers are included in other services revenues.

The following table summarizes our revenues for the periods presented (in thousands):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","","","Year Ended December 31, 2019"],["Revenues"],["Crude oil revenues","$","910,381","","","$","69,075","","","","$","522,812","","","","","$","1,261,413"],["Natural gas revenues","289,875","","","17,070","","","","78,698","","","","","146,396"],["Purchased oil and gas sales","378,983","","","20,633","","","","237,111","","","","","481,014"],["Other services revenues","687","","","215","","","","6,836","","","","","41,974"],["Total revenues","$","1,579,926","","","$","106,993","","","","$","845,457","","","","","$","1,930,797"]]
[[/GREPCENT_TABLE]]

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The following table summarizes the changes in production and average realized prices for the periods presented:

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020"],["Production data"],["Crude oil (MBbls)","13,489","","","1,593","","","","14,226"],["Natural gas (MMcf)","46,157","","","5,008","","","","42,199"],["Oil equivalents (MBoe)","21,182","","","2,428","","","","21,258"],["Average daily production (Boepd)","58,032","","","57,809","","","","65,612"],["Average sales prices"],["Crude oil (per Bbl)"],["Average sales price","$","67.49","","","$","43.36","","","","$","36.75"],["Effect of derivative settlements(1)","(18.94)","","","\u2014","","","","11.38"],["Average realized price after the effect of derivative settlements(1)","$","48.55","","","$","43.36","","","","$","48.13"],["Natural gas (per Mcf)(2)"],["Average sales price","$","6.28","","","$","3.41","","","","$","1.86"],["Effect of derivative settlements(1)","(0.32)","","","(0.01)","","","","\u2014"],["Average realized price after the effect of derivative settlements(1)","$","5.96","","","$","3.40","","","","$","1.86"]]
[[/GREPCENT_TABLE]]

__________________

(1)The effect of derivative settlements includes the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented, but does not include proceeds from derivative liquidations or payments for derivative modifications. Our commodity derivatives do not qualify for 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 $676.3 million increase due to higher crude oil and natural gas sales prices, partially offset by a $163.8 million decrease due to lower crude oil and natural gas production sold. During the year ended December 31, 2021 (Successor), our crude oil and natural gas revenues were positively impacted by higher commodity prices compared to the previous year due largely to higher energy demand as a result of increased economic activity following severe COVID-19 restrictions during 2020. Excluding the effect of derivative settlements, average crude oil sales prices increased 80%, and average natural gas sales prices, which include the value for natural gas and NGLs, increased 209% year over year. Average daily production sold decreased by 6,685 Boepd year over year, primarily driven by a decrease of 5,353 Boepd due to the divestiture of our upstream assets in the Permian Basin on June 29, 2021. We closed the Williston Basin Acquisition on October 21, 2021, and average daily production from the Williston Basin Acquisition asset between the close date to December 31, 2021 was 21,226 Boepd. During the year ended December 31, 2021 (Successor), we completed and placed on production 22.3 total net operated wells in the Williston Basin.

Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily 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 ended December 31, 2021 (Successor), primarily due to higher crude oil sales prices period over period, partially offset by lower crude oil volumes purchased and then subsequently sold.

Other services revenues. Other services revenues decreased by $6.4 million to $0.7 million during the year ended December 31, 2021 (Successor), which was primarily attributable to a decrease in well completion revenues due to the Well Services Exit in the first quarter of 2020.

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Expenses and other income

The following table summarizes our operating expenses, gain (loss) on sale of properties, other income and expenses, income tax benefit, net income (loss) from continuing operations, income from discontinued operations attributable to Oasis, net of income tax and net income (loss) attributable to Oasis for the periods presented (in thousands, except per Boe of production):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","Year Ended December 31, 2019"],["Operating expenses"],["Lease operating expenses","$","203,933","","","$","22,517","","","","$","160,406","","","$","288,690"],["Other services expenses","47","","","\u2014","","","","6,658","","","28,761"],["Gathering, processing and transportation expenses","122,614","","","13,198","","","","117,884","","","174,026"],["Purchased oil and gas expenses","379,972","","","20,278","","","","229,056","","","474,914"],["Production taxes","76,835","","","5,938","","","","45,439","","","112,592"],["Depreciation, depletion and amortization","126,436","","","13,789","","","","271,002","","","771,640"],["Exploration expenses","2,760","","","\u2014","","","","2,748","","","6,658"],["Rig termination","\u2014","","","\u2014","","","","1,279","","","384"],["Impairment","3","","","\u2014","","","","4,825,530","","","10,257"],["General and administrative expenses","80,688","","","14,803","","","","144,700","","","128,595"],["Litigation settlement","\u2014","","","\u2014","","","","22,750","","","20,000"],["Total operating expenses","993,288","","","90,523","","","","5,827,452","","","2,016,517"],["Gain (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","\u2014","","","\u2014","","","","83,867","","","4,312"],["Reorganization items, net","\u2014","","","\u2014","","","","665,916","","","\u2014"],["Other income (expense)","(1,010)","","","(401)","","","","1,271","","","569"],["Total 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","","","32,715"],["Net income (loss) from continuing operations","188,960","","","(67,108)","","","","(3,865,854)","","","(318,180)"],["Income from discontinued operations attributable to Oasis, net of income tax","130,642","","","17,196","","","","225,526","","","189,937"],["Net income (loss) attributable to Oasis","$","319,602","","","$","(49,912)","","","","$","(3,640,328)","","","$","(128,243)"],["Costs and expenses (per Boe of production)"],["Lease operating expenses","$","9.63","","","$","9.27","","","","$","7.55","","","$","8.98"],["Gathering, processing and transportation expenses","5.79","","","5.44","","","","5.55","","","5.41"],["Production taxes","3.63","","","2.45","","","","2.14","","","3.50"]]
[[/GREPCENT_TABLE]]

Lease operating expenses. Lease operating expenses (“LOE”) increased $21.0 million year over year to $203.9 million for the year ended December 31, 2021 (Successor). This increase was due to a $32.0 million increase in the Williston Basin 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 offset by a decrease of $11.0 million for LOE in the Permian Basin due to the divestiture 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 primarily attributable to a decrease in well completion expenses due to the Well Services Exit in the first quarter of 2020.

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Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses decreased $8.5 million year over year, which was attributable to a $3.4 million decrease in natural gas gathering and processing expenses and a $2.2 million decrease in crude oil gathering and transportation expenses, both related to a decrease in our production volumes. In addition, there was a decrease of $2.8 million related to non-cash valuation adjustments for 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 represent the crude oil purchased primarily to optimize transportation costs, for blending to 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 to higher crude oil and natural gas revenues. The production tax rate as a percentage of crude oil and natural gas sales was 6.4% for the year ended December 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 January 1, 2020 through November 19, 2020 (Predecessor). The production tax rate decreased year over year primarily due to a lower crude oil production mix in the Williston Basin.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense decreased $158.4 million, or 56%, year over year to $126.4 million for the year ended December 31, 2021 (Successor). This decrease was primarily due to a decrease in DD&A related to oil and gas properties in the Williston Basin of $136.5 million, of which $133.8 million was due to a lower average unit-of-production rate and $2.7 million was due to lower production volumes. In the Williston Basin, the average unit-of-production DD&A rate decreased $6.55 per Boe, or 56%, in 2021 as compared to 2020 primarily due to 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 of depletion expense on our Permian Basin properties that were sold in June of 2021. These decreases were offset by an increase in depreciation expense related to our fixed assets of $9.9 million due to a higher book basis in well fracturing equipment as a result of fresh start accounting fair value adjustments made in November 2020.

Rig termination. There were no rig termination expenses recorded during the year ended December 31, 2021 (Successor) or for the period from November 20, 2020 through December 31, 2020 (Successor). We recorded $1.3 million of rig termination expenses for the period from January 1, 2020 through November 19, 2020 (Predecessor) to early terminate certain drilling rig contracts in the Permian Basin.

Impairment. Impairment expenses were immaterial for the year ended December 31, 2021 (Successor). There were no impairment expenses for the period from November 20, 2020 through December 31, 2020 (Successor). We recorded impairment expenses of $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 the Williston Basin and $637.3 million in the Permian Basin for the period ended November 19, 2020, primarily due to a significant decline in commodity prices.

•Unproved oil and gas properties. The Predecessor recorded impairment losses on its unproved oil and gas properties of $401.1 million for the period ended November 19, 2020 as a result of leases expiring or expected to expire, as well as 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 year ended December 31, 2021 (Successor). This decrease was primarily due to lower employee compensation expenses due to a 21% decrease in employee headcount year over 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 ended December 31, 2021 (Successor), compared to $5.04 per Boe during the period from November 20, 2020 through December 31, 2020 (Successor) and $4.52 per Boe during the period from January 1, 2020 through November 19, 2020 (Predecessor). For a definition of Cash G&A and a reconciliation of G&A to Cash G&A, see “Non-GAAP Financial Measures” below.

Litigation settlement. There were no litigation settlement expenses recorded during the year ended December 31, 2021 (Successor) or for the period from November 20, 2020 through December 31, 2020 (Successor). During the period from January 1, 2020 through November 19, 2020 (Predecessor), we recorded a loss accrual of $22.8 million for the remaining settlement of legal proceedings with Mirada Energy, LLC and certain related parties. See “Item 8. Financial Statements and Supplementary Data—Note 22—Commitments and Contingencies” for more information.

Gain (loss) on sale of properties. For the year ended December 31, 2021 (Successor), we recognized a $222.8 million net gain on sale of properties primarily related to the Permian Basin Sale. For the period from January 1, 2020 through November 19,

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2020 (Predecessor), we recognized a $10.4 million net gain on sale of properties primarily related to the sale of certain oil and gas properties in the Williston Basin. For more information on our divestitures, see “Item 8. Financial Statements and Supplementary Data—Note 13—Acquisitions and Divestitures”.

Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip commodity price changes, we recognize gains or losses on our derivative instruments for the change in their fair value during the period. During the year ended December 31, 2021 (Successor), we recorded a $589.6 million net loss on derivative instruments, primarily due to an unrealized loss of $319.5 million and a realized loss of $270.1 million. The unrealized loss includes a loss of $331.5 million related to our commodity derivative contracts, partially offset by a gain of $12.0 million related to the Permian Basin Sale Contingent Consideration. The realized loss includes $255.5 million related to settlement payments on crude oil derivative contracts and $14.7 million related to settlement payments on natural gas derivative contracts. During the 2020 Successor Period, we recognized an $84.6 million loss on derivative instruments, including net cash settlement payments of $0.1 million, for the decrease in the fair value of our derivative contracts as a result of an increase in forward commodity prices during the period. During the 2020 Predecessor Period, we recognized a $233.6 million gain on derivative instruments, including net cash settlement receipts of $224.4 million, of which $62.6 million was received for derivative contracts liquidated prior to their maturities.

Interest expense, net of capitalized interest. Interest expense decreased $113.1 million year over year to $30.8 million for the year ended December 31, 2021 (Successor). The decrease was primarily due to interest expense related to the Predecessor’s senior unsecured notes of $92.5 million and the Predecessor’s revolving credit facility of $21.0 million that were recorded during the period from January 1, 2020 through November 19, 2020 (Predecessor), coupled with a specified default interest charge of $30.3 million that was incurred during the period from January 1, 2020 through November 19, 2020 (Predecessor) and was subsequently waived on the Emergence Date. These decreases were offset by interest expense recorded during the year ended December 31, 2021 (Successor) related to the Oasis Senior Notes (defined below) of $13.7 million and the Oasis Credit 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 senior secured second lien facility. The senior secured second lien facility was terminated prior to being drawn and was replaced with financing from the Oasis Senior Notes (defined below).

For the year ended December 31, 2021 (Successor), the weighted average debt outstanding under the Oasis Credit Facility (defined below) was $65.5 million, and the weighted average interest rate incurred on outstanding borrowings under the Oasis Credit Facility (defined below) was 4.2%. Interest capitalized during the year ended December 31, 2021 (Successor) was $2.1 million.

Gain on extinguishment of debt. There was no extinguishment of debt during the year ended December 31, 2021 (Successor). During the period from January 1, 2020 through November 19, 2020 (Predecessor), we repurchased an aggregate principal amount 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 from January 1, 2020 through November 19, 2020 (Predecessor), we recorded $665.9 million of net reorganization items related to our emergence from bankruptcy, consisting of (i) gains on the settlement of obligations under the Predecessor senior unsecured notes, (ii) fresh start accounting fair value adjustments, (iii) professional fees, (iv) the write-off of unamortized deferred financing costs and an unamortized debt discount and (v) fees associated with a debtor-in-possession credit facility. See “Item 8. Financial Statements and Supplementary Data—Note 3—Fresh Start Accounting” for more information on amounts recorded to reorganization items, net.

Income tax benefit. Our income tax benefit for the year ended December 31, 2021 (Successor) was recorded at (0.3)% of pre-tax income. Our income tax benefit for the period from January 1, 2020 through November 19, 2020 (Predecessor) and the period from November 20, 2020 through December 31, 2020 (Successor) was recorded at 6.6% and 7.0% of pre-tax loss, respectively. Our effective tax rate for the year ended December 31, 2021 (Successor) was lower than the effective tax rate for the previous year primarily due to the impacts of the change in the valuation allowance, reorganization impacts and the impacts of non-controlling interests.

Income from discontinued operations attributable to Oasis, net of income tax. Income from discontinued operations attributable to Oasis, net of income tax decreased $112.1 million year over year to $130.6 million during the year ended December 31, 2021 (Successor). The decrease was primarily due to $120.9 million of reorganization items recorded during the period from January 1, 2020 through November 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 with higher midstream expenses of $68.5 million due to an increase in natural gas purchase costs and higher depreciation expense of $9.5 million, offset by higher midstream revenues of $61.6 million due to an increase in natural gas revenues and higher intercompany eliminations for LOE and GPT of $29.2 million.

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Liquidity and Capital Resources

Our primary sources of liquidity during the period covered by this report have been cash flows from operations, proceeds from the Permian Basin Sale, the issuance of the Oasis Senior Notes and OMP Senior Notes and proceeds from the OMP Equity Offering. Our primary uses of cash have been for net principal payments under the OMP Credit Facility (defined below), payments for derivative settlements and modifications, acquisition and development of oil and gas properties, interest payments on our long-term debt, dividends paid to our shareholders, payments to repurchase common stock under our share repurchase program and distributions to non-controlling interests. Upon closing of the OMP Merger on February 1, 2022, the OMP Senior Notes (defined below) were assumed by Crestwood and the OMP Credit Facility (defined below) was paid in full by Crestwood. In addition, following the OMP Merger, we will no longer make distributions to non-controlling interests, which represented the minority interest ownership of OMP. Crestwood has historically declared cash distributions to its common unitholders, and we expect to receive cash distributions from Crestwood of approximately $54 million in 2022.

We have announced a plan to return $280 million of capital to shareholders over the next year (approximately $70 million per quarter) through a combination of a base dividend (approximately $45 million), variable dividends and share repurchases. This return of capital plan represents a balanced approach that reflects our strategic goals of exercising capital discipline while delivering both return on and return of capital to shareholders. The Board of Directors has increased the quarterly base dividend by 17% from $0.50 per share of common stock to $0.585 per share of common stock and expects to pay an aggregate base dividend of $11.3 million per quarter during 2022. We expect to return capital proportionately each quarter through 2022. After the end of each quarter, we expect to announce a variable dividend based on $70 million less cash utilized to pay the base dividend and repurchase shares during the prior quarter.

Our cash flows depend on many factors, including the price of crude oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in crude oil and natural gas prices on our production, thereby mitigating our exposure to crude oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising crude oil and natural gas prices. During 2021, we entered into a series of transactions with derivative counterparties to modify the strike price of certain crude oil swap contracts. We modified the strike price on our 2022 crude oil swap contracts covering total notional volumes of 6,935 MBbls to a NYMEX WTI price of $70.00 per barrel from a weighted average price of $40.89 per barrel. In addition, we modified the strike price on our 2023 crude oil swap contracts covering total notional volumes of 5,110 MBbls to a NYMEX WTI price of $50.00 per barrel from a weighted average price of $43.68 per barrel. As of December 31, 2021, our derivative contracts in place cover 22,495 MBbls of our crude oil production from 2022 through 2023. For additional information on the impact of changing prices and our derivative arrangements on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” as well as “Part I, Item 1A. Risk Factors”.

Our material cash requirements from known obligations include repayment of outstanding principal and interest payment obligations under the Oasis Senior Notes, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and payment obligations pursuant to our operating and finance leases. There were no borrowings outstanding under the Oasis Credit Facility (defined below) as of December 31, 2021; however, on a quarterly basis, we pay a commitment fee of 0.5% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

We have contracts which include provisions for the delivery, transport, or purchase of a minimum volume of crude oil, natural gas, NGLs and water within specified time frames, the majority of which are ten years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were approximately $547.7 million as of December 31, 2021. We recorded a liability as of December 31, 2021 on the Consolidated Balance Sheet of $11.9 million related to unfavorable contracts assumed in connection with the Williston Basin Acquisition where we determined it was probable we would not meet the minimum volume commitment. The future commitments related to these contracts are included in the above total estimable future commitments as of December 31, 2021.

We believe we have adequate liquidity to fund our capital expenditures and to meet our obligations during the next 12 months and the foreseeable future. As of December 31, 2021, we had $619.7 million of liquidity available, including $172.1 million in cash and cash equivalents and $447.6 million of aggregate unused borrowing capacity available under the Oasis Credit Facility (defined below).

Oasis Credit Facility. We have a reserves-based credit agreement (the “Oasis Credit 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 of December 31, 2021. The Oasis Credit Facility matures on May 19, 2024.

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As of December 31, 2021, we had no borrowings outstanding and $2.4 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $447.6 million. As of December 31, 2020, we had $260.0 million and $6.8 million of outstanding letters of credit issued under the Oasis Credit Facility. For the year ended December 31, 2021 (Successor), the weighted average interest rate incurred on borrowings under the Oasis Credit Facility was 4.2%, compared to 3.6% for the period from January 1, 2020 through November 19, 2020 (Predecessor) and 4.6% for the period from November 20, 2020 through December 31, 2020 (Successor).

During the year ended December 31, 2021, the Company entered into various amendments to the Oasis Credit Facility which, among other things, removed a requirement for the Company to enter into hedges covering minimum production volumes, provide for increased flexibility of restricted payments to shareholders, removed a cap on cash netting in the calculation of the leverage ratio if no borrowings are outstanding under the Oasis Credit Facility (other than letters of credit) and otherwise increased the cap on cash netting to $90.0 million 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 Facility at December 31, 2021. See “Item 8. Financial Statements and Supplementary Data—Note 14—Long-Term Debt” for more information.

Oasis Senior Notes. On June 9, 2021, we issued in a private placement $400.0 million of 6.375% senior unsecured notes due June 1, 2026 (the “Oasis Senior Notes”). The Oasis Senior Notes were issued at par and resulted in net proceeds of $391.6 million. We used the proceeds from the Oasis Senior Notes offering to fund a portion of the Williston Basin Acquisition. Interest is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements 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 OMP Credit Facility was paid in full by Crestwood at the closing of the OMP Merger and has been classified as held for sale on the Consolidated Balance Sheets. As of December 31, 2021, OMP had $203.0 million of borrowings and $5.5 million of letters of credit outstanding under the OMP Credit Facility. See “Item 8. Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for more information.

OMP Senior Notes. On March 30, 2021, OMP issued in a private placement $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). The OMP Senior Notes were issued at par and resulted in net proceeds of $442.1 million. Interest on the OMP Senior Notes is payable semi-annually on April 1 and October 1 of each year. The OMP Senior Notes were assumed by Crestwood at closing of the OMP Merger and have been classified as held for sale on the Consolidated Balance Sheets. See “Item 8. Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for more information.

Cash flows

The Consolidated Statements of Cash Flows have not been recast for discontinued operations, therefore the discussion below concerning cash flows from operating activities, investing activities and financing activities includes the results of both continuing operations and discontinued operations. See “Item 8. Financial Statements and Supplementary Data—Note 6—Discontinued Operations” for disclosure of cash flow impacts attributable to discontinued operations.

The following table summarizes our change in cash flows (in thousands):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","","","Year Ended December 31, 2019"],["Net cash provided by operating activities","$","914,136","","","$","95,255","","","","$","202,936","","","","","$","892,853"],["Net cash used in investing activities","(920,769)","","","(9,881)","","","","(92,403)","","","","","(828,756)"],["Net cash provided by (used in) financing activities","161,190","","","(85,702)","","","","(109,998)","","","","","(66,268)"],["Net change in cash and cash equivalents","$","154,557","","","$","(328)","","","","$","535","","","","","$","(2,171)"]]
[[/GREPCENT_TABLE]]

Cash flows provided by operating activities

Net cash provided by operating activities increased during the year ended December 31, 2021 (Successor) primarily due to higher oil and gas revenues, coupled with lower interest expense related to the cancellation of the Predecessor senior unsecured notes and lower general and administrative expenses. Refer to “Results of Operations” above for more information on the

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impact of volumes and prices on revenues and for more information on increases and decreases in certain expenses between periods.

Working capital. Our working capital fluctuates primarily as a result of changes in commodity prices and production volumes, capital spending to fund our development program and the impact of our outstanding derivative instruments. Excluding the effects of assets held for sale from discontinued operations, we had a working capital surplus of $60.6 million at December 31, 2021, compared to a working capital deficit of $73.8 million at December 31, 2020. Our working capital increased year over year due to increases in cash and cash equivalents and accounts receivable, offset by increases in revenues and production taxes payable, accrued liabilities and current derivative liabilities.

Cash flows used in investing activities

Net cash used in investing activities increased during the year ended December 31, 2021 (Successor) primarily due to an increase in payments for derivative settlements, coupled with payments to modify the terms of outstanding derivative contracts. In addition, we paid total cash consideration (excluding transaction costs) of $585.8 million for the Williston Basin Acquisition. See “Item 8. Financial Statements and Supplementary Data—Note —13—Acquisitions and Divestitures” for more information.

Cash flows provided by (used in) financing activities

Net cash provided by financing activities increased during the year ended December 31, 2021 (Successor) primarily due to the issuance of the Oasis Senior Notes and OMP Senior Notes, partially offset by cash payments for dividends to shareholders and share repurchases.

Capital expenditures

Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table (in thousands):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","","","Year Ended December 31, 2019"],["Capital expenditures"],["E&P","$","168,189","","","$","14,839","","","","$","194,004","","","","","$","594,217"],["Other capital expenditures(1)","2,277","","","179","","","","7,071","","","","","15,760"],["Total E&P and other capital expenditures","170,466","","","15,018","","","","201,075","","","","","609,977"],["Acquisitions","586,030","","","\u2014","","","","\u2014","","","","","21,010"],["Total capital expenditures from continuing operations","756,496","","","15,018","","","","201,075","","","","","630,987"],["Discontinued operations(2)","49,123","","","3,054","","","","24,266","","","","","212,381"],["Total capital expenditures(3)","$","805,619","","","$","18,072","","","","$","225,341","","","","","$","843,368"]]
[[/GREPCENT_TABLE]]

__________________ 

(1)Other capital expenditures includes administrative capital and capitalized interest.

(2)Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations. See “Recent Developments—OMP Merger” for additional information.

(3)Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in 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, a decrease of 21% as compared to 2020. The decrease was primarily due to a reduction in capital expenditures for drilling and completions in the Permian Basin 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 drilling and completions in the Williston Basin of $40.0 million due to higher activity compared to 2020 when we temporarily suspended drilling and completions activity. As of December 31, 2021, we had two operated rigs running. In addition, midstream capital expenditures, which have been classified as discontinued operations, increased $21.8 million primarily due to an increase in capital expenditures for gathering infrastructure.

Our planned 2022 E&P capital expenditures are expected to approximate $295 million. We expect to run two operated rigs during 2022 and plan to complete 40 to 42 gross operated wells with an average working interest of approximately 72%.

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The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Furthermore, we actively review acquisition opportunities on an ongoing basis. If we acquire additional acreage, our capital expenditures may be higher than planned. However, our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

We believe that cash on hand, cash flows from operating activities, including cash settlement receipts or payments under our derivative contracts, and availability under the Oasis Credit Facility should be sufficient to fund our 2022 capital expenditure plan and to meet our future obligations.

Dividends

During 2021, we paid regular cash dividends of $1.625 per share of common stock totaling $32.3 million and a special dividend of $4.00 per share of common stock totaling $80.0 million. On February 9, 2022, we declared a dividend of $0.585 per share of common stock ($2.34 per share annualized) payable on March 4, 2022 to shareholders of record as of February 21, 2022.

We recently announced an updated return of capital plan and expect to pay a base dividend 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 variable dividend after each quarter based on $70 million less cash utilized to pay the base 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 contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

In March 2021, the Board of Directors authorized a share-repurchase program covering up to $100.0 million of the Company's common stock. During the year ended December 31, 2021, we repurchased 871,018 shares of common stock at a weighted average price of $114.79 per common share for a total cost of $100.0 million.

The Board of Directors has authorized a new $150.0 million share repurchase program, which replaces the $100.0 million share repurchase program that was fully utilized in 2021. The $150.0 million share repurchase program will be in place through the end of 2022 and is part of the Company’s plan to return $280 million of capital to shareholders over the next year.

Tax Benefits Preservation Plan

Upon emergence from bankruptcy in November 2020, the Company experienced an “ownership change” as defined by Section 382 of the Code. Under Section 382 of the Code, the Company’s Tax Benefits are potentially subject to various limitations 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 from the limitation that would otherwise be imposed under Section 382 of the Code. In August 2021, the Board of Directors adopted a Tax Benefits Preservation Plan (the “Tax Plan”) designed to protect the availability of the Company’s Tax Benefits. Adopting the Tax Plan reduced the likelihood that changes in the Company’s investor base would limit the Company’s future use of its Tax Benefits. On February 1, 2022, the Company announced the termination of the Tax Plan after the Board of Directors determined the Tax Plan was no longer necessary 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 operations are based upon our audited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation

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of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in preparation of our consolidated financial statements below. See “Item 8. Financial Statements and Supplementary Data—Note 4—Summary of Significant Accounting Policies” for a discussion of additional accounting policies and estimates made by management as well as the expected impact of recent accounting pronouncements on our consolidated financial statements.

Method of accounting for oil and gas properties

Crude oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value.

The provision for DD&A of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of 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 an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate in which case a gain or loss is recognized currently.

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in our Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Crude oil and natural gas reserve quantities and Standardized Measure of discounted future net cash flows

Our independent reserve engineers and technical staff prepare our estimates of crude oil and natural gas reserves and associated future net revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC’s rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent reserve engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

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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-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Crude oil, natural gas and NGL revenues from our interests in producing wells are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Substantially all of our crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and our NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for crude oil, natural gas and NGL, we sell the majority of our production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

Our purchased crude oil and natural gas sales are derived from the sales of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with Accounting Standards Codification 845, Nonmonetary Transactions.

Impairment of proved properties

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties by field and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to our judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, our estimated undiscounted future cash flows and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.

Impairment of unproved properties

The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for 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 the lease term has expired or sooner based on management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties:

•the remaining amount of unexpired term under our leases;

•our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;

•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

•our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

•our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin by us or by other operators in areas adjacent to or near our unproved properties.

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Asset retirement obligations

We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The asset retirement obligation (“ARO”) represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statements of Operations.

We determine the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future revisions, which could result in an increase to the existing ARO liability and could ultimately result in a higher potential impact on our operations and cash flows for settlement charges. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. The significant inputs used to estimate fair value are crude oil and natural gas prices, volatility, skew, discount rate and the contract terms of the derivative instruments. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. We have not designated any derivative instruments as hedges for accounting purposes, and we do not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported under other income (expense) in our Consolidated Statements of Operations. Our cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on our derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in our Consolidated Statements of Cash Flows.

Equity-based compensation

We grant various types of equity-based awards, including restricted stock awards, restricted stock units, performance share units, phantom units, and other awards under any long-term incentive plan then in effect to employees and non-employee directors. We determine the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. Cash-settled awards are classified as liabilities. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured 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 previously recognized for awards that were forfeited during the period.

The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte 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-Based Compensation” for additional information regarding our equity-based compensation.

Income taxes

Our provision for taxes includes both federal and state income taxes. We record our income taxes in accordance with ASC 740, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

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We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly 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 financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being 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 are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for G&A expenses, interest expense, net income (loss), or net cash provided by (used in) operating activities or any other measures prepared under GAAP. Because these non-GAAP financial measures exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.

Cash G&A

We define Cash G&A as total G&A expenses less G&A expenses attributable to discontinued operations, G&A expenses attributable to shared service allocations to our midstream operations, non-cash equity-based compensation expenses and other non-cash charges. Cash G&A is not a measure of G&A expenses as determined by GAAP. Management believes that the presentation of Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers without regard to G&A expenses that were allocated to our midstream operations, equity-based compensation programs and other non-cash items, which can vary substantially from company to company.

The following table presents a reconciliation of the GAAP financial measure of G&A expenses to the non-GAAP financial measure of Cash G&A for the periods presented (in thousands):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","Year Ended December 31, 2019"],["General and administrative expenses","$","84,881","","","$","14,224","","","","$","145,294","","","$","123,506"],["Less: General and administrative expenses attributable to discontinued operations","4,193","","","(579)","","","","594","","","(5,089)"],["General and administrative expenses attributable to continuing operations","80,688","","","14,803","","","","144,700","","","128,595"],["G&A expenses attributable to shared services","(19,443)","","","(2,569)","","","","(18,881)","","","(19,648)"],["Equity-based compensation expenses","(14,663)","","","\u2014","","","","(29,794)","","","(32,755)"],["Other non-cash adjustments","(371)","","","\u2014","","","","\u2014","","","\u2014"],["Cash G&A","$","46,211","","","$","12,234","","","","$","96,025","","","$","76,192"]]
[[/GREPCENT_TABLE]]

Cash Interest

We define Cash Interest as interest expense less interest expense attributable to discontinued operations plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt to finance our E&P activities, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.

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The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented (in thousands):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020(1)","","","Year Ended December 31, 2019"],["Interest expense","$","67,751","","","$","3,168","","","","$","181,484","","","","$","176,223"],["Less: Interest expense attributable to discontinued operations","36,945","","","1,148","","","","39,648","","","","16,936"],["Interest expense attributable to continuing operations","30,806","","","2,020","","","","141,836","","","","159,287"],["Capitalized interest","2,077","","","128","","","","6,106","","","","11,270"],["Amortization of deferred financing costs(2)","(13,727)","","","(152)","","","","(6,865)","","","","(7,886)"],["Amortization of debt discount","\u2014","","","\u2014","","","","(8,317)","","","","(12,164)"],["Cash Interest","$","19,156","","","$","1,996","","","","$","132,760","","","","$","150,507"]]
[[/GREPCENT_TABLE]]

___________________

(1)For the period from January 1, 2020 through November 19, 2020 (Predecessor), interest expense and cash interest include a specified default interest charge of $30.3 million attributable to continuing operations. In addition, for the period from January 1, 2020 through November 19, 2020 (Predecessor), interest expense includes a specified default interest charge of $28.0 million attributable to discontinued operations. These specified default interest charges were waived on the Emergence Date.

(2)For the year ended December 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, income taxes, DD&A, exploration expenses and other similar non-cash or non-recurring charges. We define Adjusted EBITDA from continuing operations as Adjusted EBITDA less Adjusted EBITDA attributable to discontinued operations, plus distributions from OMP. We define Adjusted Free Cash Flow as Adjusted EBITDA from continuing operations less Cash Interest and E&P and other capital expenditures (excluding capitalized 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 the presentation of Adjusted EBITDA and Adjusted Free Cash Flow provides useful additional information to investors and analysts for assessing our results of operations, financial performance, ability to generate cash from our business operations without regard to our financing methods or capital structure and our ability to maintain compliance with our debt covenants.

The following table presents reconciliations of the GAAP financial measures of net income (loss) including non-controlling interests and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted Free Cash Flow for the periods presented (in thousands):

[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","","Year Ended December 31, 2019"],["Net income (loss) including non-controlling interests","$","355,298","","","$","(45,962)","","","","$","(3,724,611)","","","","$","(90,647)"],["(Gain) loss on sale of properties","(222,806)","","","(11)","","","","(10,396)","","","","4,455"],["Gain on extinguishment of debt","\u2014","","","\u2014","","","","(83,867)","","","","(4,312)"],["Net (gain) loss on derivative instruments","589,641","","","84,615","","","","(233,565)","","","","106,314"],["Derivative settlements","(270,118)","","","(76)","","","","224,416","","","","19,098"],["Interest expense, net of capitalized interest","67,751","","","3,168","","","","181,484","","","","176,223"],["Depreciation, depletion and amortization","158,304","","","16,094","","","","291,115","","","","787,192"],["Impairment","5","","","\u2014","","","","4,937,143","","","","10,257"],["Rig termination","\u2014","","","\u2014","","","","1,279","","","","384"],["Exploration expenses","2,760","","","\u2014","","","","2,748","","","","6,658"]]
[[/GREPCENT_TABLE]]

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[[GREPCENT_TABLE]]
[["","Successor","","","Predecessor"],["","Year Ended December 31, 2021","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020","","","Year Ended December 31, 2019"],["Equity-based compensation expenses","15,476","","","270","","","","31,315","","","","33,607"],["Litigation settlement","\u2014","","","\u2014","","","","22,750","","","","20,000"],["Reorganization items, net","\u2014","","","\u2014","","","","(786,831)","","","","\u2014"],["Income tax benefit","(956)","","","(3,447)","","","","(262,962)","","","","(32,715)"],["Other non-cash adjustments","123","","","468","","","","2,324","","","","3,035"],["Adjusted EBITDA","695,478","","","55,119","","","","592,342","","","","1,039,549"],["Adjusted EBITDA attributable to discontinued operations","(216,540)","","","(22,309)","","","","(173,457)","","","","(241,226)"],["Cash distributions from OMP and DevCo Interests","71,781","","","7,734","","","","123,057","","","","150,388"],["Adjusted EBITDA from continuing operations","550,719","","","40,544","","","","541,942","","","","948,711"],["Cash 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 to DevCo Interests","\u2014","","","(1,173)","","","","(6,147)","","","","(14,353)"],["Capitalized interest","2,077","","","128","","","","6,106","","","","11,270"],["Adjusted Free Cash Flow","$","363,174","","","$","22,485","","","","$","208,066","","","","$","185,144"],["Net cash provided by operating activities","$","914,136","","","$","95,255","","","","$","202,936","","","","$","892,853"],["Derivative settlements","(270,118)","","","(76)","","","","224,416","","","","19,098"],["Interest expense, net of capitalized interest","67,751","","","3,168","","","","181,484","","","","176,223"],["Rig termination","\u2014","","","\u2014","","","","1,279","","","","384"],["Exploration expenses","2,760","","","\u2014","","","","2,748","","","","6,658"],["Deferred financing costs amortization and other","(12,991)","","","(6,824)","","","","(41,811)","","","","(27,263)"],["Current tax (benefit) expense","21","","","\u2014","","","","(36)","","","","(16)"],["Changes in working capital","(6,204)","","","(36,872)","","","","(25,953)","","","","(51,423)"],["Litigation settlement","\u2014","","","\u2014","","","","22,750","","","","20,000"],["Cash paid for reorganization items","\u2014","","","\u2014","","","","22,205","","","","\u2014"],["Other non-cash adjustments","123","","","468","","","","2,324","","","","3,035"],["Adjusted EBITDA","695,478","","","55,119","","","","592,342","","","","1,039,549"],["Adjusted EBITDA attributable to discontinued operations","(216,540)","","","(22,309)","","","","(173,457)","","","","(241,226)"],["Cash distributions from OMP and DevCo Interests","71,781","","","7,734","","","","123,057","","","","150,388"],["Adjusted EBITDA from continuing operations","550,719","","","40,544","","","","541,942","","","","948,711"],["Cash 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 to DevCo Interests","\u2014","","","(1,173)","","","","(6,147)","","","","(14,353)"],["Capitalized interest","2,077","","","128","","","","6,106","","","","11,270"],["Adjusted Free Cash Flow","$","363,174","","","$","22,485","","","","$","208,066","","","","$","185,144"]]
[[/GREPCENT_TABLE]]

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