# Chord Energy Corp (CHRD) FY 2022 MD&A

Verbatim Item 7 Management's Discussion and Analysis from Chord Energy Corp's 10-K for fiscal year 2022.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1486159/000148615923000004/chrd-20221231.htm
Accession: 0001486159-23-000004
Filing date: 2023-02-28
Report date: 2022-12-31
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/
Previous year: /company/CHRD/mda/fy2021/ (FY 2021)
Next year: /company/CHRD/mda/fy2023/ (FY 2023)

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 13—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 year ended December 31, 2021 (Successor) compared to the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), 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, 2021, filed with the SEC on February 25, 2022.

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 responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.

Recent Developments

Return of Capital Plan

On August 3, 2022, we introduced a return of capital plan designed to provide peer-leading, sustainable stockholder returns. The return of capital plan includes a base dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $300 million share-repurchase program. We plan to return capital through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases.

We expect to return a certain percentage of adjusted free cash flow (“Adjusted FCF”) each quarter, with the targeted percentage based on free cash flow generated during the previous quarter and leverage under the following framework:

[[GREPCENT_TABLE]]
[["\u2022Below 0.5x leverage:","75%+ of Adjusted FCF"],["\u2022Below 1.0x leverage:","50%+ of Adjusted FCF"],["\u20221.0x leverage:","Base dividend+ ($5.00 per share annualized)"]]
[[/GREPCENT_TABLE]]

The variable dividend will be calculated using the framework noted above to establish the minimum percentage of Adjusted FCF to be returned less share repurchases completed during the quarter and the base dividend.

Whiting Merger

On March 7, 2022, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Whiting to combine in a merger of equals transaction. Whiting was an independent oil and gas company engaged in the development, production and acquisition of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. The Merger was unanimously approved by the respective Boards of Directors of both companies, and the proposals relating to the Merger were approved by the stockholders of both companies on June 28, 2022. The Merger was completed on July 1, 2022, and in connection therewith, we changed our name from Oasis Petroleum Inc. to Chord Energy Corporation.

Under the terms of the Merger Agreement, holders of Whiting common stock, par value $0.001 per share, were entitled to receive 0.5774 shares of Chord common stock, par value $0.01 per share, and $6.25 per share in cash in exchange for each share of Whiting common stock. Upon completion of the Merger on July 1, 2022, we issued 22,671,871 shares of Chord common stock and paid $245.4 million in cash to Whiting stockholders.

59

Table of Contents

Also in connection with the Merger, on June 16, 2022, the Board of Directors of Oasis declared a special dividend of $15.00 per share of common stock (the “Special Dividend”) that was paid on July 8, 2022 to stockholders of record as of June 29, 2022.

OMP Merger

On February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP LLC, OMP’s general partner (“OMP GP”) with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) and, in exchange for the interests in OMP and OMP GP owned by us, we received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood (the “OMP Merger”). In connection with the closing of the OMP Merger, we executed a director nomination agreement with Crestwood, pursuant to which we designated two directors to the Board of Directors of Crestwood Equity GP LLC, a Delaware limited liability company and the general partner of Crestwood (“Crestwood GP”).

On September 12, 2022, we sold an aggregate 16,000,000 common units of Crestwood in separate transactions and received pre-tax net proceeds of $428.2 million. On September 15, 2022, in connection with such transactions and pursuant to the terms of the previously executed director nomination agreement, both of our director designees resigned from the Board of Directors of Crestwood GP.

The OMP Merger represented a strategic shift for us and qualified for reporting as a discontinued operation. See “Item 8. Financial Statements and Supplementary Data—Note 12—Divestitures” for additional information.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders 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, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. Commodity prices increased during 2022 due to a combination of factors, including disruptions to global commodity markets resulting from the Russian invasion of Ukraine, continued restraint of supply by OPEC+ and domestic oil and gas producers in the United States and higher demand as a result of increased global economic activity levels due to easing of restrictions associated with the COVID-19 pandemic.

While our operating and financial results in 2022 were positively impacted by higher commodity prices, this was partially offset by an increase in the costs of labor, materials and services due to a combination of factors, including supply chain disruptions, a tight labor market and an increase in the demand for drilling and completion services relative to available supply (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information on inflationary impacts). In an effort to reduce inflationary pressures, central banks aggressively raised interest rates in 2022 and have continued to raise interest rates in 2023. Higher interest rates generally reduce economic activity levels, which could result in lower commodity prices due to reduced demand for crude oil, NGLs and natural gas. The uncertainties resulting from potential economic outcomes of monetary policy decisions of central banks, coupled with geopolitical risks associated with the continued Russian invasion of Ukraine make it difficult to predict future impacts to commodity prices.

In addition, while we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services. See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties” for additional information.

In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical 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.”

60

Table of Contents

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

[[GREPCENT_TABLE]]
[["","2022","","Year ended December 31, 2022"],["","Q1","","Q2","","Q3","","Q4"],["Average Realized Crude Oil Prices ($/Bbl)(1)","$","95.34","","","$","111.79","","","$","93.13","","","$","83.74","","","$","92.98"],["Average Price Differential ($/Bbl)(2)","$","1.22","","","$","2.82","","","$","1.63","","","$","0.99","","","$","1.52"],["Average Price Differential Percentage(2)","1.3","%","","2.5","%","","1.8","%","","1.2","%","","1.6","%"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","2021","","Year ended December 31, 2021"],["","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)","2.8","%","","0.9","%","","0.6","%","","0.3","%","","1.0","%"]]
[[/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.

We sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 2022, substantially all of our gross operated crude oil production was connected to gathering systems. 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

Comparability of Financial Statements

The results of operations presented below relate to the periods ended December 31, 2022 and 2021. The Merger was accounted for as of July 1, 2022. Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022 and the results of Chord (including legacy Whiting) from July 1, 2022 through December 31, 2022, unless otherwise noted.

As of the completion of the Merger on July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. For the periods prior to July 1, 2022, we reported crude oil and natural gas, which included NGLs, on a two-stream basis. This change impacts the comparability with prior periods.

In addition, 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 period from January 1, 2022 to February 1, 2022 (the closing date of the OMP Merger). Prior periods have been recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements. See “Item 8. Financial Statements and Supplementary Data—Note 13—Discontinued Operations” for additional information.

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2021 (Successor) compared to the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), 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, 2021, filed with the SEC on February 25, 2022.

61

Table of Contents

Operational and Financial Highlights

During the year ended December 31, 2022:

•Production volumes averaged 119,785 Boepd (58% oil), including average daily production of 171,880 Boepd for the period subsequent to the Merger.

•Lease operating expenses were $10.14 per Boe, including $9.88 per Boe for the period subsequent to the Merger.

•E&P and other capital expenditures were $503.1 million, including $394.1 million for the period subsequent to the Merger.

•Estimated net proved reserves were 655.6 MMBoe as of December 31, 2022, with a Standardized Measure of $11.5 billion and PV-10 of $14.5 billion.

•TIL’d 73 gross (54 net) operated wells.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL 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 revenues for the year ended December 31, 2022 increased primarily due to the Merger, which significantly expanded our operations in the Williston Basin. Our purchased oil and gas sales are 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 generally recorded on a gross basis, as 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 counterparty. 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.

The following table summarizes our revenues for the periods presented:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021"],["","(In thousands)"],["Revenues"],["Crude oil revenues","$","2,366,995","","","$","910,381"],["NGL revenues(1)","184,288","","","\u2014"],["Natural gas revenues(1)","425,013","","","289,875"],["Purchased oil and gas sales","670,174","","","378,983"],["Other services revenues","324","","","687"],["Total revenues","$","3,646,794","","","$","1,579,926"]]
[[/GREPCENT_TABLE]]

__________________

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting revenues, production data and average sales prices. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.

62

Table of Contents

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

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021"],["Production data"],["Crude oil (MBbls)","25,457","","","13,489"],["NGLs (MBbls)(1)","7,026","","","\u2014"],["Natural gas (MMcf)(1)","67,428","","","46,157"],["Oil equivalents (MBoe)","43,722","","","21,182"],["Average daily production (Boepd)","119,785","","","58,032"],["Average daily crude oil production (Bopd)","69,746","","","36,956"],["Average sales prices"],["Crude oil (per Bbl)"],["Average sales price","$","92.98","","","$","67.49"],["Effect of derivative settlements(2)","(19.48)","","","(18.94)"],["Average realized price after the effect of derivative settlements(2)","$","73.50","","","$","48.55"],["NGLs (per Bbl)(1)"],["Average sales price","$","26.23","","","$","\u2014"],["Effect of derivative settlements(2)","0.71","","","\u2014"],["Average realized price after the effect of derivative settlements(2)","$","26.94","","","$","\u2014"],["Natural gas (per Mcf)(1)"],["Average sales price","$","6.30","","","$","6.28"],["Effect of derivative settlements(2)","(1.04)","","","(0.32)"],["Average realized price after the effect of derivative settlements(2)","$","5.26","","","$","5.96"]]
[[/GREPCENT_TABLE]]

__________________

(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting revenues, production data and average sales prices. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.

(2)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.

Crude oil revenues. Our crude oil revenues increased $1.5 billion to $2.4 billion for the year ended December 31, 2022. This increase was primarily driven by a $852.8 million increase due to our expanded operations after the Merger. Excluding the impacts attributable to the Merger, our crude oil revenues increased $603.8 million due to an increase of $389.8 million due to higher crude oil realized prices and $214.0 million due to higher crude oil production volumes sold year-over-year. Average crude oil sales prices, without derivative settlements, increased by $25.49 per barrel year-over-year to an average of $92.98 per barrel for the year ended December 31, 2022. Crude oil production volumes of 69,746 Bopd for the year ended December 31, 2022 included 43,041 Bopd from legacy Oasis assets and 95,992 Bopd for the period subsequent to the Merger. Crude oil production volumes increased 6,085 Bopd year-over-year on our legacy Oasis assets due primarily to an increase in TILs.

Our crude oil production volumes in 2022 were negatively impacted by winter storms in the Williston Basin in April 2022 and December 2022, which resulted in a temporary curtailment of a portion of our production, delays in drilling and completion of wells, and other operational constraints. We subsequently restored our production and resumed normal operations.

63

Table of Contents

NGL and natural gas revenues. Our NGL and natural gas revenues increased $319.4 million to $609.3 million for the year ended December 31, 2022 primarily driven by a $184.8 million increase due to our expanded operations after the Merger. Excluding the impacts attributable to the Merger, our natural gas and NGL sales increased $134.7 million due to an increase of $126.8 million due to higher natural gas and NGL sales volumes year-over-year, coupled with an increase of $7.9 million due to higher natural gas and NGL prices year-over-year. Natural gas production volumes of 184,735 Mcfpd for the year ended December 31, 2022 included 126,341 Mcfpd from legacy Oasis assets and 226,205 Mcfpd for the period subsequent to the Merger. Our NGL sales volumes are reported on a prospective basis upon the conversion to three-stream reporting and were 38,187 Bpd for the period from July 1, 2022 through December 31, 2022. For the year ended December 31, 2022, on a barrel of oil equivalent basis, our natural gas and NGL production volumes were 30,048 Boepd on our legacy Oasis assets compared to 21,076 Boepd for the year ended December 31, 2021. This increase was primarily due to an increase in TILs year-over-year. Our NGL and natural gas production volumes were also negatively impacted by the winter storms that occurred during 2022 discussed above.

During the year ended December 31, 2022, average natural gas sales prices, without derivative settlements, were $6.30 per Mcf and average NGL sales prices, without derivative settlements, were $26.23 per barrel. During the year ended December 31, 2021, average natural gas sales prices, without derivative settlements, were $6.28 per Mcf. Effective July 1, 2022 we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. Prior to this, we reported on a two-stream basis and NGLs were reported with the natural gas stream. Accordingly, the natural gas sales prices for the periods prior to three-stream reporting were higher compared to the periods subsequent to three-stream reporting since the natural gas sales price included the value of NGLs. The conversion to three-stream reporting did not impact our total reported revenues.

Purchased oil and gas sales. Purchased oil and gas sales increased $291.2 million to $670.2 million for the year ended December 31, 2022. This increase was primarily due to higher crude oil prices year-over-year and an increase in crude oil volumes purchased and then subsequently sold.

64

Table of Contents

Expenses and other income (expense)

The following table summarizes our operating expenses, gain on sale of assets, net other expenses, income tax benefit, net income from continuing operations, income from discontinued operations attributable to Chord, net of income tax and net income attributable to Chord for the years presented:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021"],["","(In thousands, except per Boe of production)"],["Operating expenses"],["Lease operating expenses","$","443,373","","","$","203,933"],["Other services expenses","187","","","47"],["Gathering, processing and transportation expenses","141,644","","","122,614"],["Purchased oil and gas expenses","671,935","","","379,972"],["Production taxes","229,571","","","76,835"],["Depreciation, depletion and amortization","369,659","","","126,436"],["Exploration and impairment","2,204","","","2,763"],["General and administrative expenses","209,299","","","80,688"],["Total operating expenses","2,067,872","","","993,288"],["Gain on sale of assets, net","4,867","","","222,806"],["Operating income","1,583,789","","","809,444"],["Other income (expense)"],["Net loss on derivative instruments","(208,128)","","","(589,641)"],["Net gain from investment in unconsolidated affiliate","34,366","","","\u2014"],["Interest expense, net of capitalized interest","(29,349)","","","(30,806)"],["Other income (expense)","2,901","","","(1,010)"],["Total other expense, net","(200,210)","","","(621,457)"],["Income from continuing operations","1,383,579","","","187,987"],["Income tax benefit","46,884","","","973"],["Net income from continuing operations","1,430,463","","","188,960"],["Income from discontinued operations attributable to Chord, net of income tax","425,696","","","130,642"],["Net income attributable to Chord","$","1,856,159","","","$","319,602"],["Costs and expenses (per Boe of production)"],["Lease operating expenses","$","10.14","","","$","9.63"],["Gathering, processing and transportation expenses","3.24","","","5.79"],["Production taxes","5.25","","","3.63"]]
[[/GREPCENT_TABLE]]

Lease operating expenses. Lease operating expenses (“LOE”) increased $239.4 million to $443.4 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. This increase was primarily due to a $169.3 million increase from our expanded operations after the Merger. Excluding the effects of the Merger, LOE increased $70.1 million primarily due to higher fixed costs of $45.2 million, higher workover costs of $24.6 million and an increase in non-operated LOE of $7.9 million, partially offset by $11.6 million of LOE costs incurred during the year ended December 31, 2021 on properties in the Permian Basin that were divested in June 2021. LOE per Boe increased $0.51 per Boe to $10.14 per Boe for the year ended December 31, 2022 primarily due to higher costs.

65

Table of Contents

Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $19.0 million to $141.6 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. GPT expenses increased $10.0 million from our expanded operations after the Merger, which included a $7.3 million non-cash gain attributable to the change in fair value of certain transportation derivative contracts acquired in the Merger that we did not elect the “normal purchase normal sale” exclusion. See “Item 8. Financial Statements and Supplementary Data—Note 7—Derivative Instruments” for additional information. Excluding the effects of the Merger, GPT expenses increased $9.0 million primarily due to higher crude oil gathering and transportation expenses of $14.4 million driven by an increase in volumes transported on DAPL, partially offset by lower natural gas gathering and processing expenses of $4.9 million and $2.5 million of GPT expenses incurred during the year ended December 31, 2021 on properties in the Permian Basin that were divested in June 2021. GPT expenses per Boe decreased $2.55 per Boe to $3.24 per Boe for the year ended December 31, 2022 due to higher production volumes and other decreases described above.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $292.0 million to $671.9 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021 primarily due to higher crude oil prices year-over-year and an increase in crude oil volumes purchased.

Production taxes. Production taxes increased $152.7 million to $229.6 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. This increase was primarily due to an $82.6 million increase from our expanded operations after the Merger. Excluding the effects of the Merger, production taxes increased $70.1 million due to increased crude oil sales year-over-year, coupled with an increase in the crude oil extraction tax in North Dakota from 5% to 6% from June 1, 2022 to November 30, 2022 due to a crude oil price trigger adjustment. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 7.7% for the year ended December 31, 2022, compared to 6.5% for the year ended December 31, 2021. This increase was primarily due to the impact of divesting properties in the Permian Basin in June 2021, which were subject to lower production tax rates in Texas, as compared to North Dakota.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expenses increased $243.2 million to $369.7 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily due to a $153.1 million increase in DD&A expenses attributable to our expanded operations after the Merger. Excluding the effects of the Merger, depletion expense increased $101.3 million driven by a $109.8 million increase in the Williston Basin attributable to an increase in production and a higher depletion rate year-over-year, partially offset by $8.5 million of depletion expense incurred during the year ended December 31, 2021 on properties in the Permian Basin that were divested in June 2021. The depletion rate increased $3.11 per Boe to $8.10 per Boe for the year ended December 31, 2022 due to higher costs attributable to the oil and gas properties acquired in the Merger. Fixed DD&A expense decreased $11.2 million primarily due to well service equipment that has been fully depreciated.

Exploration and impairment expenses. Exploration and impairment expenses were $2.2 million for the year ended December 31, 2022, which was consistent with the year ended December 31, 2021.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $128.6 million to $209.3 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. This increase was primarily due to $97.7 million of merger-related costs, including $39.7 million of costs related to employee severance benefits, $33.5 million of advisory, legal and other transaction-related costs and $17.8 million attributable to the acceleration of equity-based compensation expenses due to terminations of certain officers upon closing of the Merger. The remaining $30.8 million increase in G&A year-over-year was primarily attributable to increased compensation and other costs associated with a larger organization.

Gain on sale of assets, net. For the year ended December 31, 2022, we recognized a net $4.9 million gain on the sale of certain non-core assets. For the year ended December 31, 2021, we recognized a $222.8 million gain on sale of assets primarily related to the divestiture of upstream assets in the Permian Basin. See “Item 8. Financial Statements and Supplementary Data—Note 12—Divestitures” for additional information.

Derivative instruments. We recorded a $208.1 million net loss on derivative instruments for the year ended December 31, 2022, which included a net loss of $224.2 million associated with our contracts to manage commodity price risk, offset by an unrealized gain of $16.1 million associated with an embedded derivative related to the contingent consideration included within the 2021 agreement to sell our upstream assets in the Permian Basin. The net loss of $224.2 million associated with our contracts to manage commodity price risk was comprised of a loss of $561.1 million from settled contracts, partially offset by an unrealized gain of $336.9 million. During the year ended December 31, 2021, we recorded a $589.6 million net loss on derivative instruments, which included a loss of $601.6 million associated with our contracts to manage commodity price risk, offset by an unrealized gain of $12.0 million associated with an embedded derivative related to the contingent consideration included within the 2021 agreement to sell our upstream assets in the Permian Basin. The loss of $601.6 million associated with

66

Table of Contents

our contracts to manage commodity price risk was comprised of an unrealized loss of $331.5 million and a loss of $270.1 million from settled contracts.

Investment in unconsolidated affiliate. We recorded a $34.4 million net gain related to our investment in Crestwood for the year ended December 31, 2022, including a gain of $43.9 million due to cash distributions received from Crestwood during the year and a gain of $43.0 million attributable to the sale of 16,000,000 common units in September 2022, partially offset by an unrealized loss of $52.5 million due to a decrease in the fair value of the investment during the year. As of December 31, 2022, we owned less than 5% of Crestwood’s issued and outstanding common units.

Interest expense, net of capitalized interest. Interest expense was $29.3 million for the year ended December 31, 2022, which was consistent with the year ended December 31, 2021. Interest capitalized during the year ended December 31, 2022 and 2021 was $4.6 million and $2.1 million, respectively. For the year ended December 31, 2022, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.6%, compared to 4.2% for the year ended December 31, 2021.

Other income (expense). For the year ended December 31, 2022, we recognized $2.9 million of other income compared to $1.0 million of other expense for the year ended December 31, 2021. This $3.9 million increase in other income was primarily due to an increase in interest income year-over-year associated with higher balances in certain of our money market accounts.

Income tax benefit. Our income tax benefit was recorded at (3.4)% of pre-tax income from continuing operations for the year ended December 31, 2022 and (0.5)% of pre-tax income from continuing operations for the year ended December 31, 2021. Our effective tax rate for the year ended December 31, 2022 was lower than the effective tax rate for the year ended December 31, 2021 primarily due to the impact of releasing a substantial majority of the valuation allowance on our net deferred tax assets in 2022, coupled with 2021 restructuring impacts.

Income from discontinued operations attributable to Chord, net of income tax. Income from discontinued operations attributable to Chord, net of income tax for the year ended December 31, 2022 represents income from OMP for the period prior to the completion of the OMP Merger on February 1, 2022. We recorded income from discontinued operations attributable to Chord, net of income tax of $425.7 million for the year ended December 31, 2022. This was primarily comprised of a gain on sale of $518.9 million and midstream revenues of $23.3 million, offset by income tax expense of $101.1 million, midstream expenses of $13.2 million and interest expense of $3.7 million. Income from discontinued operations attributable to Chord, net of income tax was $130.6 million for the year ended December 31, 2021, which included midstream revenues of $254.2 million, offset by midstream expenses of $122.0 million.

Liquidity and Capital Resources

As of December 31, 2022, we had $1,586.8 million of liquidity available, including $593.2 million in cash and cash equivalents and $993.6 million of aggregate unused borrowing capacity available under our senior secured revolving credit facility. Our primary sources of liquidity are cash on hand, cash flows from operations, the sale of non-core or non-strategic assets and available borrowing capacity under our senior secured revolving credit facility.

Our primary liquidity requirements consist of capital expenditures for the development of oil and gas properties, dividend payments, share repurchases, cash payments associated with the Merger and working capital requirements. 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.

Our cash flows depend on many factors, including the price of crude oil, NGL 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 impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. For example, during the year ended December 31, 2022, crude oil, NGL and natural gas prices generally increased relative to the strike price in our outstanding commodity derivative contracts, thus resulting in a net cash outflow for the settlement of these contracts.

In connection with the Merger, Whiting’s commodity derivative contracts were novated to us. These contracts included fixed-price swaps and two-way collars to mitigate price risk associated with a certain portion of our crude oil, NGL and natural gas production. In addition, we were novated natural gas basis swap contracts which provide for a fixed differential between the NYMEX Henry Hub price index and the Northern Natural Gas Ventura price index. See “Item 8. Financial Statements and Supplementary Data—Note 9—Derivative Instruments” for additional information.

As of December 31, 2022, our commodity derivative contracts cover 14,106 MBbls of our crude oil production, 7,560 gallons of our NGL production and 10,599 MMBtu of our natural gas production for 2023. In addition, as of December 31, 2022, we had outstanding natural gas basis swaps that cover notional volumes of 5,920 MMBtu for 2023. As of December 31, 2022, we did not have any commodity derivative contracts that cover production volumes in 2024. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” as well as “Part I, Item 1A. Risk Factors” for additional information.

67

Table of Contents

Whiting Merger

In connection with the consummation of the Merger on July 1, 2022, we paid cash consideration of $245.4 million, or $6.25 per share of Whiting common stock, to Whiting stockholders. In addition, we paid the Special Dividend on July 8, 2022 to stockholders of record as of June 29, 2022.

We incurred certain costs directly attributable to the Merger for advisory, legal, severance and other third-party fees which were recorded to general and administrative expenses on the Consolidated Statements of Operations. For the year ended December 31, 2022, we recognized total merger-related costs of $97.7 million, including $39.7 million related to employee severance benefits, transaction costs of $33.5 million and $17.8 million related to the acceleration of unamortized stock compensation expense as a result of certain officer terminations upon completion of the Merger. At December 31, 2022, we had a remaining liability of $21.3 million for the payment of employee severance benefits which was included in accrued liabilities on the Consolidated Balance Sheet.

Whiting had a reserves-based credit facility with a syndicate of banks. Upon consummation of the Merger, the Whiting credit facility was terminated, and the Company paid the remaining outstanding accrued interest and other fees of approximately $2.2 million to satisfy and discharge in full all such outstanding obligations that were owed under the Whiting credit facility.

OMP Merger

Upon closing of the OMP Merger on February 1, 2022, OMP’s outstanding 8.00% senior unsecured notes due April 1, 2029 were assumed by Crestwood, and OMP’s senior secured revolving credit facility was paid in full by Crestwood. As a result, we no longer have access to these liquidity sources as of December 31, 2022; however, we do not expect the loss of these liquidity sources to materially impact our liquidity or financial position due to our ability to generate cash flows from operations and our strong balance sheet.

Material cash requirements

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, severance benefits payable to employees terminated in connection with the Merger, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases. There were no borrowings outstanding under the Credit Facility (defined below) as of December 31, 2022; however, on a quarterly basis, we pay a commitment fee 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 also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas 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 (excluding deliveries from future production and applicable volume credits) were $519.5 million as of December 31, 2022. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGLs and natural gas from third parties to satisfy our minimum volume commitments.

Long-term debt

Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements and $400.0 million of 6.375% senior unsecured notes.

Senior secured revolving line of credit. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and elected commitments of $1.0 billion that is due July 1, 2027. As of December 31, 2022, we had no borrowings outstanding and $6.4 million of outstanding letters of credit, resulting in an unused borrowing capacity of $993.6 million.

On July 1, 2022, we entered into the Amended and Restated Credit Agreement to, among other things: (i) increase the aggregate maximum credit amount to $3.0 billion, (ii) increase the borrowing base to $2.0 billion, (iii) increase the aggregate amount of elected commitments to $800.0 million, (iv) extend the maturity date to July 1, 2027, (v) reduce the margin on outstanding borrowings by 125 basis points and (vi) increase the consolidated total leverage ratio financial covenant to 3.50x.

68

Table of Contents

On August 8, 2022, we entered into the First Amendment to the Amended and Restated Credit Agreement to provide additional flexibility for SOFR borrowings. In addition, on October 31, 2022, we completed the semi-annual borrowing base redetermination and entered into our Second Amendment to Amended and Restated Credit Agreement to increase the aggregate amount of elected commitments to $1.0 billion and increase the borrowing base to $2.75 billion. We expect the next semi-annual redetermination to be completed in or around April 2023.

For the year ended December 31, 2022, the weighted average interest rate incurred on borrowings under the Credit Facility was 4.6%, compared to 4.2% for the year ended December 31, 2021.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2022. See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” for additional information.

Senior unsecured notes. As of December 31, 2022, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026. Interest on the senior unsecured notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements and Supplementary Data—Note 15—Long-Term Debt” 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 13—Discontinued Operations” for disclosure of cash flow impacts attributable to discontinued operations. For a discussion on cash flows for the year ended December 31, 2021 (Successor) compared to the period from November 20, 2020 through December 31, 2020 (Successor) and the period from January 1, 2020 through November 19, 2020 (Predecessor), refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2021 Annual Report on Form 10-K filed with the SEC on February 25, 2022 under the subheading “Cash flows.”

The following table summarizes our change in cash flows:

[[GREPCENT_TABLE]]
[["","Year Ended December 31,"],["","2022","","2021"],["","(In thousands)"],["Net cash provided by operating activities","$","1,924,026","","","$","914,136"],["Net cash used in investing activities","(682,562)","","","(920,769)"],["Net cash provided by (used in) financing activities","(823,096)","","","161,190"],["Increase in cash and cash equivalents","$","418,368","","","$","154,557"]]
[[/GREPCENT_TABLE]]

Cash flows provided by operating activities

Net cash provided by operating activities was $1,924.0 million for the year ended December 31, 2022. The increase in net cash provided by operating activities of $1,009.9 million from the year ended December 31, 2021 was due primarily to higher revenues from crude oil, NGL and natural gas sales due to higher commodity prices and our expanded operations following the Merger. See “Results of Operations” above for additional information on the impact of volumes and prices on revenues and for additional 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 development of our oil and gas properties and the settlement of outstanding commodity derivative contracts. At December 31, 2022, we had a working capital surplus of $121.2 million, compared to a working capital surplus of $60.6 million at December 31, 2021 (excluding current assets/liabilities held for sale).

We believe we have adequate liquidity to meet our working capital requirements. The Credit Facility includes a requirement that the Company maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $993.6 million as of December 31, 2022, and excludes current hedge assets, which were $23.7 million as of December 31, 2022. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $341.5 million as of December 31, 2022.

69

Table of Contents

Cash flows used in investing activities

Net cash used in investing activities was $682.6 million for the year ended December 31, 2022. The decrease in net cash used in investing activities of $238.2 million from the year ended December 31, 2021 was primarily due to a decrease of (i) $442.0 million related to acquisitions, which included cash consideration of $585.8 million for the acquisition of oil and gas properties in the Williston Basin from Diamondback Energy Inc. in 2021 compared to $245.4 million of cash consideration paid to Whiting stockholders in connection with the Merger in 2022, and (ii) $220.9 million associated with payments to modify the terms of outstanding derivative contracts in 2021. In addition, we received $428.2 million in proceeds from the sale of our investment in Crestwood in September 2022 and cash distributions for our ownership of Crestwood common units of $43.9 million during the year ended December 31, 2022. These reductions to net cash used in investing activities were offset by an increase of (i) $362.9 million for cash payments to settle commodity derivative contracts and (ii) $318.5 million in capital expenditures related to the development of our oil and gas properties. In addition, there was a decrease of $206.9 million in proceeds from divested assets whereby we received net proceeds from divestitures of $376.1 million during the year ended December 31, 2021 primarily related to the sale of our upstream assets in the Permian Basin, compared to $160.0 million in connection with the completion of the OMP Merger in February 2022. See “Capital expenditures” below for additional information on our capital expenditures in 2022 and our outlook for 2023.

Cash flows provided by (used in) financing activities

Net cash used in financing activities of $823.1 million for the year ended December 31, 2022 was primarily attributable to dividends paid to stockholders of $654.7 million, payments of $152.0 million to repurchase common stock and payments of $41.8 million for income tax withholdings on vested equity-based compensation awards. These uses of cash were partially offset by proceeds of $19.8 million from the exercise of outstanding warrants. Net cash provided by financing activities for the year ended December 31, 2021 of $161.2 million was primarily attributable to OMP’s issuance of $450.0 million in aggregate principal amount of senior notes, coupled with our issuance of the Senior Notes in June 2021.

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,","","Period from November 20, 2020 through December 31, 2020","","","Period from January 1, 2020 through November 19, 2020"],["","2022","","2021"],["Capital expenditures"],["E&P","$","495,947","","","$","168,189","","","$","14,839","","","","$","194,004"],["Other capital expenditures(1)","11,771","","","2,277","","","179","","","","7,071"],["Total E&P and other capital expenditures","507,718","","","170,466","","","15,018","","","","201,075"],["Acquisitions(2)","(2,275)","","","586,030","","","\u2014","","","","\u2014"],["Total capital expenditures from continuing operations","505,443","","","756,496","","","15,018","","","","201,075"],["Discontinued operations(3)","3,396","","","49,123","","","3,054","","","","24,266"],["Total capital expenditures(4)","$","508,839","","","$","805,619","","","$","18,072","","","","$","225,341"]]
[[/GREPCENT_TABLE]]

__________________ 

(1)Other capital expenditures includes items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $4.6 million for the year ended December 31, 2022 (Successor), $2.1 million for the year ended December 31, 2021 (Successor), $0.1 million for the period from November 20, 2020 through December 31, 2020 (Successor) and $6.4 million for the period from January 1, 2020 through November 19, 2020 (Predecessor).

(2)Excludes amounts attributable to the Merger.

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

(4)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.

70

Table of Contents

In 2022, our total E&P and other capital expenditures were $507.7 million, an increase of $337.3 million as compared to 2021. The increase was primarily due to an increase of $223.7 million associated with capital expenditures on assets acquired in the Merger, including capital expenditures of $189.2 million on drilling and completion activities and $28.4 million on workover activities from July 1, 2022 through December 31, 2022. On our legacy assets, our E&P capital expenditures were $278.3 million, which was an increase of $110.1 million as compared to 2021. This increase was primarily driven by an increase in capital expenditures of $88.6 million on drilling and completion activities and $21.4 million on workover activities. The increase in capital expenditures for drilling and completion activities on our legacy assets was primarily due to an increase in net operated well completions and higher costs associated with drilling longer lateral lengths on our operated wells. We completed 26.8 net operated wells associated with our legacy assets in 2022, compared to 22.3 net operated wells in 2021. Additionally, the increase in capital expenditures for workover activities was primarily due to an increase in the number of workover projects year-over-year. Our capital expenditures were also impacted as a result of inflationary impacts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information on inflationary impacts.

Our planned 2023 E&P capital expenditures are expected to be approximately $825 million to $865 million. We expect to run four operated rigs during 2023 and plan to complete 90 to 94 gross operated wells with an average working interest of approximately 73%.

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 may 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.

Dividends

During the year ended December 31, 2022, we declared base plus variable cash dividends of $12.03 per share of common stock, or $373.0 million in aggregate, and a special cash dividend of $15.00 per share of common stock, or $307.4 million in aggregate. On February 22, 2023, we declared a base cash dividend of $1.25 per share of common stock and a variable cash dividend of $3.55 per share of common stock. The dividends will be payable on March 21, 2023 to shareholders of record as of March 7, 2023. As of December 31, 2022, we had dividends payable of $30.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $5.9 million that was recorded under accrued liabilities and $24.8 million that was recorded under other liabilities on the Consolidated Balance Sheet.

During the year ended December 31, 2021, we declared base cash dividends of $1.625 per share of common stock or $32.3 million in aggregate and a special cash dividend of $4.00 per share of common stock, or $80.0 million in aggregate.

See “Recent Developments—Return of Capital Plan” for additional information regarding our strategy on future dividend payments. 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 February 2022, our Board of Directors authorized a share-repurchase program covering up to $150.0 million of our common stock, which replaced the $100.0 million share repurchase program that was fully utilized in 2021. We repurchased $124.8 million of shares of common stock under this program in 2022.

In August 2022, our Board of Directors authorized a new share-repurchase program covering up to $300.0 million of our common stock, which resulted in the expiration of the $150.0 million share-repurchase program. We repurchased $27.1 million shares of common stock under this program in 2022.

In total, we repurchased 1,378,070 shares of common stock at a weighted average price of $110.24 per common share for a total cost of $151.9 million under both of these programs in 2022.

See “Recent Developments—Return of Capital Plan” for additional information on our strategy for future share repurchases.

71

Table of Contents

Critical accounting policies and estimates

Our consolidated financial statements 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. See “Item 8. Financial Statements and Supplementary Data—Note 4—Summary of Significant Accounting Policies” for the significant accounting policies and estimates made by management as well as the expected impact of recent accounting pronouncements on our consolidated financial statements. The following are the accounting policies, estimates and judgments used in preparation of our consolidated financial statements which we consider most critical:

Method of accounting for oil and gas properties

GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method. These two accounting methods differ in a number of ways, including the treatment of the costs of exploratory dry holes and geological and geophysical costs which are charged against earnings during the period incurred under the successful efforts method and capitalized within a pool of assets under the full cost method. We account for oil and gas properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 4—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information.

Estimated quantities of reserves

Our independent reserve engineers prepare our estimates of crude oil, NGL and natural gas reserves. 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. Estimates of reserve quantities and the related estimates of future net cash flows are used as inputs into the calculation of the fair value of oil and gas properties in a business combination, the assessment of whether sufficient future taxable income will be generated to realize deferred tax assets, the calculation of depletion expense, the evaluation of proved oil and gas properties for impairment and the Standardized Measure.

Estimates of reserves are prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. Crude oil, NGL and natural gas reserves 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, changes to Company’s anticipated five-year development plan, changes to commodity 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, NGL and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, and if such revisions are significant, they could significantly affect future depletion expense, the carrying amount of our proved oil and gas properties, the realizability of our deferred tax assets and the Standardized Measure. See “Item 1. Business—Exploration and Production Operations—Estimated net proved reserves” for additional information on the revisions to our estimated net proved reserves.

Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas for the year ended December 31, 2022. We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 9.5 MMBoe and decrease the PV-10 by $2.2 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 7.5 MMBoe and increase the PV-10 by $2.2 billion.

Business combinations

We account for business combinations under the acquisition method of accounting. Under the acquisition method of accounting, we recognize amounts for identifiable assets acquired and liabilities assumed measured at their estimated acquisition date fair values. Any excess of the purchase price consideration over the estimated acquisition date fair value of assets acquired and liabilities assumed is recorded as goodwill, while any deficit of the purchase price consideration under the estimated acquisition date fair value of assets acquired and liabilities assumed is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. Transaction and integration costs associated with business combinations are expensed as incurred. We may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.

72

Table of Contents

The Merger was accounted for as a business combination under the acquisition method of accounting. The purchase price consideration of $2.8 billion was allocated to the assets acquired and liabilities assumed based upon their estimated acquisition date fair values and resulted in no goodwill or bargain purchase. The most significant assumptions related to the measurement of the fair value of oil and gas properties, which was $3.2 billion as of the acquisition date on July 1, 2022. The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgement and assumptions, including future production volumes based upon estimates of reserves prepared by our reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate.

The estimated fair value assigned to the assets acquired and liabilities assumed can have a significant effect on our future operating results. For example, a higher fair value measurement of oil and gas properties increases the likelihood of future impairment charges if reserves quantities and/or commodity prices are lower, or operating and/or development costs are higher, than those which were used to measure the fair value on the acquisition date. In addition, a higher fair value measurement of oil and gas properties results in higher depletion expense in future periods which reduces our future earnings.

Impairment of proved oil and gas properties

We review proved oil and gas properties for impairment whenever events and circumstances indicate that their carrying value may not be recoverable. We estimate the expected undiscounted future cash flows by field and compare such undiscounted amounts to the carrying amount to determine if the asset is recoverable. If the carrying amount is not recoverable, we will recognize an impairment by adjusting the carrying amount of the oil and gas properties to fair value. We estimate the fair value of proved oil and gas properties using an income approach that converts future cash flows to a single discounted amount.

The factors used to determine the undiscounted future cash flows and fair value require significant judgment and assumptions, including future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. These factors are generally consistent with those used in the planning and budgeting processes. Future production is based upon a combination of inputs and assumptions, including the timing and pace of our development plans, as well as estimates of reserve quantities. When discounting future cash flows to estimate fair value, cash flows realized later in the projection period are less valuable compared to those realized earlier in the projection period due to the time value of money. Future commodity prices are estimated by using a combination of quoted forward market prices adjusted for geographical location and quality differentials based upon assumptions that are developed by reviewing historical realized prices, market supply and demand factors, and other relevant factors. Future operating and development costs are generally estimated using inputs including authorizations for expenditures, review of historical data and forecasts developed during the budgeting and planning processes. In addition, estimates of future operating and development costs may be impacted by market supply and demand factors, including inflation expectations and the availability of materials, labor and services. To calculate fair value, future cash flows are discounted using a discount rate that is based on rates utilized by market participants and is commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

A substantial or extended decline in commodity prices could result in future impairment charges which would negatively impact our future operating results. However, because of the uncertainty inherent in the factors described above, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. Our most recent impairment was recorded for $4.4 billion during the period from January 1, 2020 through November 19, 2020 (Predecessor) as a result of the significant decline in expected future commodity prices in the first quarter of 2020.

Income taxes

Our provision for taxes includes both federal and state income taxes. We record our income taxes in accordance with ASC 740, Income Taxes, 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. 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.

73

Table of Contents

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. As of December 31, 2022 and 2021, we had no unrecognized tax benefits.

Deferred tax assets are recognized for items such as temporary differences that will be deductible in future years’ tax returns, NOLs and tax credit carryforwards. As of each reporting date, we assess the available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to realize the deferred tax assets. As of December 31, 2022, our consolidated balance sheet includes a net deferred tax asset of $200.2 million, which was reduced by a valuation allowance of $9.6 million for certain state NOLs. As of December 31, 2021, substantially all of our deferred tax assets were reduced by a valuation allowance. During 2022, we decreased the valuation allowances against our deferred tax assets from $399.8 million as of December 31, 2021 to $9.6 million as of December 31, 2022 based upon our assessment of (i) cumulative income earned during the periods subsequent to our emergence from bankruptcy, (ii) the indefinite lives for many of our deferred tax assets and (iii) projections of future taxable income. Significant judgment is involved in this determination, including assumptions required to assess our future taxable income such as future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. See “Item 8. Financial Statements and Supplementary Data—Note 17—Income Taxes” for additional information.

An estimate of the sensitivity to changes in our assumptions resulting in future income calculations is not practical, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the assumptions would likely be offset by favorable adjustments in other assumptions.

74

Table of Contents