Chord Energy Corp (CHRD)

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. 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, 2023 compared to the year ended December 31, 2022, 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, 2023, filed with the SEC on February 26, 2024.

Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, natural gas liquids (“NGL”) and natural gas primarily in 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

Enerplus Arrangement

On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement ”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, we agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”). Enerplus was an independent North American oil and gas E&P company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The Arrangement was completed on May 31, 2024.

Upon completion of the Arrangement on May 31, 2024, we issued 20,680,097 shares of common stock and paid $375.8 million in cash to Enerplus shareholders. Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock, par value $0.01 per share, and $1.84 per share in cash in exchange for each share of Enerplus they owned at closing.

Divestitures

On October 25, 2024, we completed the sale of certain of our non-core properties located in the DJ Basin in Colorado that were classified as assets held for sale as of September 30, 2024, for total net cash proceeds (including preliminary purchase price adjustments) of $36.4 million, resulting in a $0.6 million gain on asset divestment.

In addition, during the year ended December 31, 2024, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds (subject to purchase price adjustments) of $25.0 million.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders depend substantially on factors beyond our control, such as economic, geopolitical, 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 due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas. Commodity prices remained low throughout 2024 due to a combination of factors, including slowing demand growth as a result of decreased global economic activity levels and higher levels of production from domestic oil and gas producers in the United States and other non-OPEC+ countries.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022. After peaking in 2023, interest rates began to trend downward during 2024. Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGLs and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties

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resulting from the potential economic outcomes of monetary policy decisions of central banks as well as tariff and trade policy decisions of the U.S. or other governments, coupled with the geopolitical risks associated with the continued military conflicts in the Red Sea Region and the wars between Russia and Ukraine and Hamas and Israel, make it difficult to predict future impacts to commodity prices.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties or goodwill 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 and goodwill 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 and goodwill” 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.”

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

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(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, 2024, 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.

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Results of Operations

Comparability of Financial Statements

The results of operations presented below relate to the periods ended December 31, 2024 and 2023. The results reported for the year ended December 31, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus beginning on May 31, 2024 and the 2023 acquisition of acreage in the Williston Basin, while the results reported for the year ended December 31, 2023 reflect the consolidated results of Chord, including the 2023 acquisition of acreage in the Williston Basin beginning on June 30, 2023, and excluding the impact from the business combination with Enerplus, unless otherwise noted.

For a discussion of the changes related to the financial condition and results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, 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, 2023, filed with the SEC on February 26, 2024.

Operational and Financial Highlights

•Production volumes averaged 232,737 Boepd (57% oil) for the year ended December 31, 2024.

•Lease operating expenses (“LOE”) were $9.68 per Boe for the year ended December 31, 2024.

•E&P and other capital expenditures were $1.2 billion for the year ended December 31, 2024.

•Net cash provided by operating activities was $2.1 billion and net income was $848.6 million for the year ended December 31, 2024.

•Estimated net proved reserves were 883.0 MMBoe as of December 31, 2024, with a Standardized Measure of $8.4 billion and PV-10 of $10.3 billion.

•TIL’d 142 gross (93 net) operated wells for the year ended December 31, 2024.

Shareholder Return Highlights

•Paid $10.15 per share base-plus-variable cash dividend for the year ended December 31, 2024.

•Repurchased $442.8 million of common stock during the year ended December 31, 2024 with $592.6 million remaining under the new $750 million share repurchase program authorized by the Board of Directors in October 2024.

•On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to stockholders of record as of March 11, 2025.

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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 and/or changes in commodity prices. Our revenues for the year ended December 31, 2024 increased due to the Arrangement, which expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGLs 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, NGL 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, production and average realized prices for the periods presented:

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(1)For the year ended December 31, 2024, natural gas production volume from the Marcellus Shale was 24,727 MMcf. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $1.78 per Mcf.

(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. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

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Crude oil revenues. Our crude oil revenues increased $735.4 million to $3.6 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. Our crude oil revenues increased $837.3 million due to higher total crude oil production volumes sold, primarily due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, crude oil revenues decreased $124.9 million due to lower crude oil realized prices, partially offset by an increase of $23.0 million due to higher crude oil production volumes sold year-over-year. Average crude oil sales prices, without derivative settlements, decreased by $4.18 per barrel year-over-year to an average of $73.67 per barrel for the year ended December 31, 2024 due to decreases in NYMEX WTI and widening in-basin differentials.

NGL revenues. Our NGL revenues decreased $15.7 million to $162.1 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to lower NGL realized prices year-over-year resulting in a $48.3 million decrease, partially offset by an increase of $32.6 million due to higher NGL production volumes primarily as a result of the Arrangement. Average NGL sales prices, without derivative settlements, decreased by $3.70 per barrel period over period to an average of $9.92 per barrel for the year ended December 31, 2024 primarily due to wider differentials on incremental production volumes primarily as a result of the Arrangement.

Natural gas revenues. Our natural gas revenues decreased $16.0 million to $102.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to lower natural gas realized prices year-over-year resulting in a $49.0 million decrease, offset by an increase in total natural gas production volumes sold of $33.0 million, primarily due to our expanded operations as a result of the Arrangement. Average natural gas sales prices, without derivative settlements decreased by $0.59 per Mcf period over period to $0.84 per Mcf for the year ended December 31, 2024 primarily due to a decrease in natural gas index prices, coupled with the impact of incurring fixed fees and related fee escalations for the majority of our natural gas marketing contracts beginning in the second quarter of 2023.

Purchased oil and gas sales. Purchased oil and gas sales increased $650.7 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year.

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Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:

Lease operating expenses. LOE increased $165.5 million to $824.4 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $181.3 million of additional LOE period over period. Excluding the increase from the Arrangement, LOE decreased $31.7 million due to lower workover costs, offset by an increase of $17.0 million due to higher variable costs period over period. LOE per Boe decreased $0.73 per Boe period over period to $9.68 per Boe for the year ended December 31, 2024 primarily due to higher production volumes and lower workover costs.

Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $87.3 million to $267.6 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $79.5 million of additional GPT period over period and lower fair value gains of $26.4 million attributable to the completion of certain derivative transportation contracts at the end of 2023 and during the first half of 2024. These increases were partially offset by a decrease of $19.5 million due to lower transportation rates, primarily due to several contracts expiring during the year ended December 31, 2024. These net increases resulted in an increase in GPT expenses of $0.29 per Boe period over period to $3.14 per Boe for the year ended December 31, 2024.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $651.0 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023 primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year.

Production taxes. Production taxes increased $73.4 million to $333.4 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $77.4 million of additional production tax, or $3.59 per Boe, for the year ended December 31, 2024.

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The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.7% for the year ended December 31, 2024 as compared to 8.3% for the year ended December 31, 2023. This rate increase year-over-year was primarily due to an increase in new wells with a higher associated oil production tax rate, coupled with decreased natural gas and NGL revenues as a result of lower realized prices.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $509.2 million to $1.1 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $281.1 million of additional DD&A expense period over period, an increase of $225.0 million due to a higher depletion rate period over period and an increase of $4.5 million due to higher production volumes year-over-year. The depletion rate increased $3.50 per Boe year-over-year to $12.70 per Boe for the year ended December 31, 2024 primarily due to the purchase consideration allocated to the fair value of oil and gas properties acquired in the Arrangement.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $79.3 million to $205.6 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, primarily due to increased merger-related costs of $79.6 million incurred in connection with the Arrangement and an increase in costs associated with a larger organization after the Arrangement of $26.7 million. These increases were partially offset by a decrease in stock-based compensation costs of $23.1 million due to the vesting of certain equity-based compensation awards year-over-year.

Exploration and impairment expenses. Exploration and impairment expenses decreased $18.3 million to $17.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. During the year ended December 31, 2024, we recorded an impairment expense of $9.8 million, which primarily included a $7.4 million lower of cost or net realizable value write-down of oil-in-tank inventory and a $2.5 million impairment expense related to the Denver office lease and related fixed assets acquired in connection with the Arrangement. During the year ended December 31, 2023, exploration and impairment expenses totaled $35.3 million, which was primarily due to impairment expenses of $29.0 million, including $17.5 million associated with the write-down of our Denver office lease acquired in 2022, $5.8 million associated with a lower of cost or net realizable value write-down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.

Gain (loss) on sale of assets, net. During the year ended December 31, 2024, we recorded a net gain on sale of assets of $17.1 million, primarily related to certain non-operated wellbore divestitures in the Williston Basin. During the year ended December 31, 2023, we recorded a net loss on sale of assets of $2.8 million, primarily related to divestitures of certain of our non-core properties located outside of the Williston Basin.

Derivative instruments. During the year ended December 31, 2024, we recorded a $12.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $7.5 million associated with our commodity derivative contracts and a net gain of $5.1 million associated with a contract that includes contingent consideration. The net gain of $7.5 million on commodity derivative contracts included an unrealized gain of $6.6 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, coupled with a realized gain of $0.9 million on settled commodity derivative contracts. During the year ended December 31, 2023, we recorded a $63.2 million net gain on derivative instruments, which was primarily comprised of a net gain of $56.4 million associated with our commodity derivative contracts and a net gain of $6.8 million associated with a contract that includes contingent consideration. The net gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts.

Investment in unconsolidated affiliate. We recorded a $51.3 million gain related to our investment in Energy Transfer for the year ended December 31, 2024, which included an unrealized gain of $42.0 million as a result of an increase in the fair value of the investment during the year and a realized gain of $9.3 million for cash distributions received. During the year ended December 31, 2023, we recorded a $21.3 million gain related to our investment in Energy Transfer, primarily related to a realized gain of $10.8 million for cash distributions received and an unrealized gain of $8.4 million as a result of an increase in the fair value of the investment during the year.

Interest expense, net of capitalized interest. Interest expense increased $27.9 million to $56.5 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase is primarily due to higher borrowings outstanding on our Credit Facility (defined below) during the year. For the year ended December 31, 2024, the weighted average borrowings outstanding under the Credit Facility were $362.2 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.3%. For the year ended December 31, 2023, the weighted average borrowings outstanding under the Credit Facility were $4.9 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.1%. Interest capitalized during the year ended December 31, 2024 and December 31, 2023 was $4.9 million and $4.1 million, respectively.

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Other income, net. For the year ended December 31, 2024, we recognized $5.0 million of other income, net as compared to $10.0 million for the year ended December 31, 2023. The $5.0 million decrease was primarily due to a decrease in interest income year-over-year associated with lower balances in our money market accounts.

Income tax expense. Our effective tax rate for the year ended December 31, 2024 was materially unchanged from our effective tax rate for the year ended December 31, 2023. Our income tax expense was recorded at 23.7% and 23.5% of pre-tax income for the year ended December 31, 2024 and December 31, 2023, respectively.

Liquidity and Capital Resources

As of December 31, 2024, we had $1.1 billion of liquidity available, including $37.0 million in cash and cash equivalents and $1.0 billion of aggregate unused borrowing base capacity available under our Credit Facility (defined below). During the first quarter of 2025, we expect to have approximately $1.6 billion of liquidity available after taking into account the increase in the aggregate amount of elected commitments to $2.0 billion. Our primary sources of liquidity were from cash on hand, cash flows from operations and available borrowing base capacity under our Credit Facility. Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments under our Credit Facility, share repurchases, cash consideration and transaction costs associated with the Arrangement, and working capital requirements.

Capital availability is affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of sustainability matters and other factors, many of which are beyond our control. The U.S. Federal Reserve recently decreased interest rates, however the potential for such rates to decrease further or to increase or remain elevated for an extended period of time creates additional economic uncertainty. Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

Enerplus Arrangement. In connection with the consummation of the Arrangement on May 31, 2024, we paid $375.8 million, or $1.84 per Enerplus common share, to Enerplus shareholders. In addition, we paid $395.0 million to settle Enerplus’ revolving bank credit facility balance and $102.4 million to settle all outstanding Enerplus equity-based compensation awards, as well as $5.9 million in retention bonuses paid to Enerplus employees.

We also incurred certain costs for advisory, legal and other third-party fees in connection with the Arrangement, which were recorded to G&A expenses on the Consolidated Statements of Operations. During the year ended December 31, 2024, we incurred merger-related costs of $89.3 million, primarily related to legal and advisory services and severance costs.

Our cash flows depend on many factors, including the price of crude oil, NGLs 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.

Commodity derivative contracts. As of December 31, 2024, our commodity derivative contracts cover 9,301 MBbls of our crude oil production and 8,902 MMBtu of our natural gas production for 2025, as well as 4,000 MBbls of our crude oil production and 10,475 MMBtu of our natural gas production for 2026. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.

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Subsequent to December 31, 2024, we entered into new commodity derivative contracts to manage risks related to changes in commodity prices. The following table summarizes these commodity derivative contracts:

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, 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. 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 five 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 $579.2 million as of December 31, 2024. 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 as of December 31, 2024.

Senior secured revolving line of credit. As of December 31, 2024, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $3.0 billion and an aggregate amount of elected commitments of $1.5 billion that is due July 1, 2027. We had $445.0 million in net borrowings outstanding, primarily made in connection with the Arrangement, and $30.8 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1.0 billion as of December 31, 2024. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. On November 4, 2024, we completed the semi-annual borrowing base redetermination, which affirmed the borrowing base of $3.0 billion and the aggregate amount of elected commitments of $1.5 billion and entered into the Sixth Amendment to the Amended and Restated Credit Agreement. In February 2025, we completed our semi-annual borrowing base redetermination, setting the borrowing base at $2.75 billion and increasing the aggregate amount of elected commitments to $2.0 billion.

For the year ended December 31, 2024, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.27%, compared to 7.13% for the year ended December 31, 2023.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2024. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.

Senior unsecured notes. As of December 31, 2024, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.

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Cash flows

The following table summarizes our changes in cash flows for the years presented:

For a discussion on cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2023 Annual Report on Form 10-K filed with the SEC on February 26, 2024 under the subheading “Cash flows.”

Cash flows provided by operating activities

Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $2.1 billion for the year ended December 31, 2024. The increase in net cash provided by operating activities of $277.4 million from the year ended December 31, 2023 was primarily due to an increase in oil revenues, offset by increases in LOE, merger-related costs, GPT costs and production taxes, as well as lower NGL and natural gas revenues and changes in our working capital. See “Results of Operations” above for additional information.

Working capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. During the years ended December 31, 2024 and 2023, changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $34.1 million and $91.9 million, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

The Credit Facility includes a requirement that we 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 $1.0 billion as of December 31, 2024, and excludes current hedge assets, which were $35.9 million as of December 31, 2024. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $1.2 million as of December 31, 2024.

Cash flows used in investing activities

For the year ended December 31, 2024, net cash used in investing activities of $1.8 billion was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1.2 billion and net cash paid for acquisitions of $655.0 million. The net cash paid for acquisitions primarily related to the Arrangement and included $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders and $102.4 million paid to settle Enerplus’ outstanding equity awards, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities during the year ended December 31, 2024 also included proceeds from divestitures of $60.7 million and the receipt of a 2023 contingent consideration earn-out payment of $25.0 million in connection with a 2021 divestiture of certain oil and gas properties. Net cash used in investing activities for the year ended December 31, 2023 of $1.4 billion was primarily attributable to $905.7 million of capital expenditures, $361.6 million paid for the 2023 acquisition of acreage in the Williston Basin and $268.9 million associated with the settlement of derivative contracts, partially offset by $54.4 million of proceeds from divestitures and $40.6 million of proceeds from the sale of Energy Transfer units.

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Cash flows used in financing activities

For the year ended December 31, 2024, net cash used in financing activities of $624.5 million was primarily attributable to dividends paid to stockholders of $529.9 million, payments made to repurchase common stock of $444.2 million, payments for income tax withholdings on vested equity-based compensation awards of $63.4 million and repayments on the Enerplus Senior Notes of $63.0 million. These uses of cash were partially offset by borrowings under the Credit Facility of $3.5 billion, offset by repayments of $3.1 billion, resulting in net borrowings under the Credit Facility of $445.0 million, primarily made in connection with the Arrangement, and proceeds from the exercise of outstanding warrants of $35.8 million. Net cash used in financing activities for the year ended December 31, 2023 of $664.7 million was primarily attributable to dividends paid to shareholders of $500.3 million, payments to repurchase our common stock of $239.3 million and payments for income tax withholdings on vested equity-based compensation awards of $14.6 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 million.

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:

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(1)For the year ended December 31, 2024, capital expenditures related to the Marcellus Shale were $8.9 million.

(2)Other capital expenditures include items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $4.9 million, $4.1 million and $4.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.

(3)Total capital expenditures for the year ended December 31, 2024 include approximately $25.2 million related to certain non-operated divested assets that are expected to be reimbursed.

(4)Excludes amounts attributable to the Arrangement, including cash consideration of $375.8 million, for the year ended December 31, 2024, and to the merger with Whiting Petroleum Corporation on July 1, 2022 (the “Merger”), including cash consideration of $245.4 million, for the year ended December 31, 2022.

(5)Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations related to the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP, OMP’s general partner, with and into a subsidiary of Crestwood Equity Partners LP (the “OMP Merger”).

(6)Total capital expenditures (including acquisitions) reflected in the table above differ 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 above 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.

For the year ended December 31, 2024, our total E&P and other capital expenditures increased $310.0 million to $1.2 billion primarily due to our expanded operations as a result of the Arrangement. We completed 93 net operated wells in 2024, compared to 69 net operated wells in 2023. Non-operated drilling and completion activities accounted for $135.9 million of our total E&P and other capital expenditures for the year ended December 31, 2024.

Additionally, on June 30, 2023, we completed the Williston Basin Acquisition for total cash consideration of $361.6 million. Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.

Our planned 2025 E&P capital expenditures are expected to be approximately $1.3 billion to $1.5 billion. We expect to run four to five operated rigs during the majority of 2025 and plan to TIL approximately 130 to 150 gross operated wells with an average working interest of approximately 78%.

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.

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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, 2024, we declared base-plus-variable cash dividends of $10.15 per share of common stock, or $507.6 million in aggregate. On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to shareholders of record as of March 11, 2025. At December 31, 2024, we had dividends payable of $16.7 million related to dividend equivalent rights accrued on equity-based compensation awards, including $16.1 million that was recorded under accrued liabilities and $0.6 million that was recorded under other liabilities on the Consolidated Balance Sheet.

During the year ended December 31, 2023, we declared base-plus-variable cash dividends of $11.88 per share of common stock, or $508.6 million in aggregate.

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 October 2024, our Board of Directors authorized a new share repurchase program covering up to $750 million of our common stock, which replaced the existing $750 million share repurchase program that was authorized in October 2023. We repurchased, and may repurchase in the future, shares pursuant to a Rule 10b5-1 trading plan under the Securities Exchange Act of 1934, as amended, which permits us to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require us to make purchases within a particular time frame.

During the year ended December 31, 2024, we repurchased 3,114,007 shares of common stock at a weighted average price of $142.20 per common share for a total cost of $442.8 million under both the October 2024 and October 2023 share repurchase programs. As of December 31, 2024, there was $592.6 million of capacity remaining under the existing $750 million program.

During the year ended December 31, 2023, the Company repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise taxes of $0.4 million under both the October 2023 and August 2022 share repurchase programs.

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 2—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 2—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information.

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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 our 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 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 $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas for the year ended December 31, 2024. 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 26.7 MMBoe and decrease the PV-10 by $2.0 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 21.4 MMBoe and increase the PV-10 by $2.0 billion.

Business combinations

We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. 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 judgment 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 market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of crude oil, NGL and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values 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.

The purchase price allocation recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available.

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See Note 9—Acquisitions of the Notes to Consolidated Financial Statements in this Annual Report for additional details regarding our business combinations, including further discussion of the estimated fair value of assets acquired and liabilities assumed in the Merger and the Arrangement as well as any significant changes in these estimates from the date of acquisition.

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.

Impairment of unproved oil and gas 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;

•our ability to make rental or extension payments to extend existing leases that may be closer 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 leasehold ownership in certain leases to other companies in exchange for their drilling of those leases;

•our ability to sell lease positions to other companies; and

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

Impairment of goodwill

Goodwill represents the excess of consideration paid over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of October 1 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired.

For the purpose of the goodwill impairment test, we first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value of the reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant

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events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions, as well as our share performance. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. Our single reportable business segment which is the exploration and production of crude oil, NGLs and natural gas, is the reporting unit that carries our goodwill balance as of December 31, 2024. The fair value of the reporting unit is estimated using an income approach. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of reserves prepared by our reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital rate.

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.

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.

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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 11—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, 2022 compared to the year ended December 31, 2021, 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, 2022, filed with the SEC on February 28, 2023.

Overview

Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, natural gas liquids (“NGL”) and natural gas in 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

Pending Acquisition

On February 21, 2024, we entered into an arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), pursuant to which, among other things, we have agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”), subject to satisfaction of certain closing conditions. The transaction will be effected by way of a plan of arrangement under the Business Corporations Act (Alberta) (the “Plan of Arrangement”).

Enerplus is an independent North American oil and gas exploration and production company. We believe that the combination of Chord and Enerplus will provide improving returns, capital efficiency, low-cost inventory, and a peer-leading balance sheet, all of which support sustainable free cash flow generation and meaningful shareholder returns. Under the terms of the Arrangement Agreement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing. The transaction is expected to close by mid-year 2024.

2023 Williston Basin Acquisition

During the year ended December 31, 2023, we completed the acquisition of approximately 62,000 net acres in the Williston Basin from XTO Energy Inc. and affiliates, subsidiaries of Exxon Mobil Corporation (collectively, “XTO”), for total cash consideration of $361.6 million, including customary purchase price adjustments (the “2023 Williston Basin Acquisition”). The effective date of the 2023 Williston Basin Acquisition was April 1, 2023. We funded the 2023 Williston Basin Acquisition with cash on hand.

Divestitures

During the year ended December 31, 2023, we entered into separate agreements with multiple buyers to sell a vast majority of our non-core properties located outside of the Williston Basin (the “Non-core Asset Sales”). As of December 31, 2023, we completed these Non-core Asset Sales and received total net cash proceeds (including purchase price adjustments) of $39.1 million, subject to customary post-closing adjustments.

In addition, during the year ended December 31, 2023, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million.

Market Conditions

Our revenue, profitability and ability to return cash to stockholders depend substantially on factors beyond our control, such as economic, geopolitical, political and regulatory developments as well as competition from other sources of energy. Prices for

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crude oil, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas. Commodity prices decreased during 2023 due to a combination of factors, including slowing demand growth as a result of decreased global economic activity levels and higher levels of production from domestic oil and gas producers in the United States and other non-OPEC+ countries.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022 and continued to raise interest rates during a portion of 2023. Although U.S. inflation rates have shown signs of moderating, 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 (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties resulting from the potential economic outcomes of monetary policy decisions of central banks, coupled with the geopolitical risks associated with the continued military conflicts between Russia and Ukraine and between Hamas and Israel, make it difficult to predict future impacts to commodity prices.

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.”

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

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(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, 2023, 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, 2023 and 2022. On July 1, 2022, we completed the merger of equals transaction with Whiting Petroleum Corporation (“Whiting”) (the “Merger”). Accordingly, the

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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, 2023, 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, on February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP, OMP’s general partner, with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) (the “OMP Merger”). 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. 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 11—Discontinued Operations” for additional information.

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021, 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, 2022, filed with the SEC on February 28, 2023.

Operational and Financial Highlights

•Production volumes averaged 173,425 Boepd (58% oil).

•Lease operating expenses (“LOE”) were $10.41 per Boe.

•E&P and other capital expenditures were $922.3 million.

•Estimated net proved reserves were 636.2 MMBoe as of December 31, 2023, with a Standardized Measure of $7.0 billion and PV-10 of $8.5 billion.

•TIL’d 94 gross (69 net) operated wells.

Shareholder Return Highlights

•Paid $11.88 per share base-plus-variable cash dividend for the year ended December 31, 2023.

•Repurchased $240.9 million of common stock with $683.0 million remaining under our $750 million share repurchase program.

•Declared a base-plus-variable cash dividend of $3.25 per share of common stock. These dividends will be payable on March 19, 2024 to stockholders of record as of March 5, 2024.

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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 purchased oil and gas sales are derived from the sale of crude oil, NGLs 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, production data and average realized prices for the periods presented:

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(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.

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Crude oil revenues. Our crude oil revenues increased $469.0 million to $2.8 billion for the year ended December 31, 2023 due to the Merger, which significantly expanded our operations in the Williston Basin. This increase was primarily driven by higher crude oil production volumes sold year-over-year of $854.0 million due to more wells TIL’d. The increase was partially offset by a decrease of $385.0 million driven by lower realized crude oil sales prices year-over-year. Average crude oil sales prices, without derivative settlements, decreased by $15.13 per barrel year-over-year to an average of $77.85 per barrel for the year ended December 31, 2023.

NGL and natural gas revenues. Our NGL and natural gas revenues decreased $312.9 million to $296.4 million for the year ended December 31, 2023. Our NGL and natural gas sales decreased primarily due to lower natural gas and NGL prices year-over-year of $407.8 million, partially offset by an increase of $95.0 million due to higher natural gas and NGL sales volumes year-over-year due to our expanded operations in the Williston Basin as a result of the Merger.

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. During the year ended December 31, 2023, average natural gas sales prices, without derivative settlements, were $1.43 per Mcf, and average NGL sales prices, without derivative settlements, were $13.62 per barrel. 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.

Purchased oil and gas sales. Purchased oil and gas sales increased $94.1 million to $764.2 million for the year ended December 31, 2023. This increase was primarily due to an increase in crude oil volumes purchased and then subsequently sold, partially offset by lower crude oil prices year-over-year.

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Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:

Lease operating expenses. Lease operating expenses increased $215.4 million to $658.9 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 primarily due to the Merger, which significantly expanded our operations in the Williston Basin. The increase in LOE included increases in workover costs of $86.7 million, fixed costs of $75.8 million and variable costs of $28.1 million. LOE per Boe increased $0.27 per Boe to $10.41 per Boe for the year ended December 31, 2023 primarily due to increases in workover costs of $0.58 per Boe, partially offset by decreases in fixed and variable costs of $0.28 per Boe.

Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $38.6 million to $180.2 million for the year ended December 31, 2023 due to the Merger, which significantly expanded our operations in the Williston Basin. This increase is attributable to higher production volumes of $62.1 million, offset by a decrease of $13.2 million due to the change in fair value of certain derivative transportation contracts and a decrease of $10.3 million due to lower rates. Our GPT expenses on a per Boe basis decreased $0.39 per Boe to $2.85 per Boe for the year ended December 31, 2023.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $89.4 million to $761.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 primarily due to an increase in crude oil volumes purchased, offset by lower crude oil prices year-over-year.

Production taxes. Production taxes increased $30.4 million to $260.0 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. This increase is primarily due to an increase in crude oil production taxes as a

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result of higher oil sales. The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.3% for the year ended December 31, 2023 as compared to 7.7% for the year ended December 31, 2022. This increase was primarily due to an increase in natural gas production volumes, coupled with lower average natural gas sales prices.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expenses increased $228.9 million to $598.6 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 due to the Merger, which significantly expanded our operations in the Williston Basin, and as a result, increased production volumes sold year-over-year due to more wells TIL’d. DD&A expenses increased $176.1 million attributable to increased production volumes and $51.9 million due to a higher depletion rate year-over-year. The depletion rate increased $1.10 per Boe to $9.20 per Boe year-over-year for the year ended December 31, 2023 due to higher costs.

Exploration and impairment expenses. Exploration and impairment expenses increased $33.1 million to $35.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. This increase was primarily due to impairment expenses of $29.0 million during the year ended December 31, 2023 and higher exploration expenses year-over-year of $3.8 million. Impairment expenses for the year ended December 31, 2023 included $17.5 million associated with the write-down of the right-of-use asset for our Denver office lease, $5.8 million associated with a lower of average cost or net realizable value write down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.

General and administrative expenses. Our general and administrative (“G&A”) expenses decreased $83.0 million to $126.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. This decrease is primarily attributable to a decrease in merger-related costs, partially offset by an increase in compensation and other costs associated with a larger organization after the Merger.

Derivative instruments. We recorded a $63.2 million net gain on derivative instruments for the year ended December 31, 2023, which was primarily comprised of a net gain of $56.4 million associated with our contracts to manage commodity price risk and a net gain of $6.8 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 gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts. During the year ended December 31, 2022, we recorded a $208.1 million net loss on derivative instruments, which included a net loss of $224.2 million associated with our commodity derivatives contracts, partially offset by an unrealized gain of $16.1 million associated with our contract that includes contingent consideration. The net loss of $224.2 million on commodity derivative contracts was comprised of a realized loss of $561.1 million on settled commodity derivative contracts, partially offset by an unrealized gain of $336.9 million related to the change in fair value of our commodity derivative contracts.

Investment in unconsolidated affiliate. On November 3, 2023, Energy Transfer LP (“Energy Transfer”) completed a merger with Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. No gain or loss was recorded as a result of this merger. For the year ended December 31, 2023, we recorded a $21.3 million gain related to our investment in Energy Transfer primarily related to a realized gain of $10.8 million for cash distributions received and an unrealized gain of $8.4 million as a result of an increase in the fair value of the investment during the year.

Other income, net. For the year ended December 31, 2023, we recognized $10.0 million of other income, net as compared to $2.9 million for the year ended December 31, 2022. The $7.1 million increase was primarily due to an increase in interest income year-over-year associated with higher balances in our money market accounts.

Income tax (expense) benefit. Our income tax expense was recorded at 23.5% of pre-tax income from continuing operations for the year ended December 31, 2023, and our income tax benefit was recorded at (3.4)% of pre-tax income from continuing operations for the year ended December 31, 2022. Our effective tax rate for the year ended December 31, 2023 was higher than the effective tax rate for the year ended December 31, 2022 primarily due to the impact of releasing substantially all of the remaining valuation allowance on our net deferred tax assets in 2022.

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 of $425.7 million represents income from OMP from January 1, 2022 to the completion of the OMP Merger on February 1, 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. There were no discontinued operations for the year ended December 31, 2023.

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Liquidity and Capital Resources

As of December 31, 2023, we had $1.3 billion of liquidity available, including $318.0 million in cash and cash equivalents and $991.1 million of aggregate unused borrowing capacity available under our Credit Facility (defined below). Our primary sources of liquidity are from cash on hand, cash flows from operations and available borrowing capacity under our Credit Facility. Our primary liquidity requirements are for capital expenditures for the development of oil and gas properties, dividend payments, share repurchases and working capital requirements. In addition, we completed the 2023 Williston Basin Acquisition on June 30, 2023 for total cash consideration of $361.6 million with cash on hand.

Capital availability will be affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of ESG matters and other factors, many of which are beyond our control. While the U.S. bank failures in March 2023 appear to be somewhat contained, risks to the financial sector remain as evidenced by recent publicity regarding New York Community Bancorp Inc. In addition, the Federal Reserve’s increases in interest rates and the potential for such rates to increase further or to remain elevated for an extended period of time have created additional economic uncertainty. Although we do not currently have a business relationship with the failed banking institutions and are unable to predict future interest rates, these disruptions to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual 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.

As of December 31, 2023, our commodity derivative contracts cover 5,762 MBbls of our crude oil production for 2024, as well as 2,457 MBbls of our crude oil production for 2025 and 651,600 MMBtu of our natural gas production for 2025. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.

Subsequent to December 31, 2023, we entered into the following commodity derivative contracts to manage risks related to changes in crude oil prices.

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, 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, 2023; 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 five 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 $391.6 million as of December 31, 2023. 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.

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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 $2.5 billion and elected commitments of $1.0 billion that is due July 1, 2027. As of December 31, 2023, we had no borrowings outstanding and $8.9 million of outstanding letters of credit, resulting in an unused borrowing capacity of $991.1 million. On October 31, 2023, we completed the semi-annual borrowing base redetermination, reaffirmed the borrowing base of $2.5 billion and maintained the aggregate amount of elected commitments of $1.0 billion. Additionally, the amendment permits us to incur term loans in addition to the revolving loans provided under the Amended and Restated Credit Agreement.

For the year ended December 31, 2023, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.1%, compared to 4.6% for the year ended December 31, 2022.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2023. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.

Senior unsecured notes. As of December 31, 2023, 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 13—Long-Term Debt” for additional 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 11—Discontinued Operations” for disclosure of cash flow impacts attributable to discontinued operations. For a discussion on cash flows for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2022 Annual Report on Form 10-K filed with the SEC on February 28, 2023 under the subheading “Cash flows.”

The following table summarizes our change in cash flows:

Cash flows provided by operating activities

Net cash provided by operating activities was $1,819.9 million for the year ended December 31, 2023. The decrease in net cash provided by operating activities of $104.2 million from the year ended December 31, 2022 was primarily due to an increase in operating expenses, partially offset by an increase in revenues from crude oil, NGL and natural gas sales. 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 operating expenses between periods.

Working capital.  Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $91.9 million and $46.6 million during the year ended December 31, 2023 and 2022, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.

Our Credit Facility includes a requirement that we 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 $991.1 million as of December 31, 2023, and excludes current hedge assets, which were $37.4 million as of December 31, 2023. For purposes of the Current Ratio, the Credit

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Facility’s definition of total current liabilities excludes current hedge liabilities, which were $14.2 million as of December 31, 2023.

Cash flows used in investing activities

Net cash used in investing activities was $1,430.3 million for the year ended December 31, 2023. The increase in net cash used in investing activities of $747.7 million from the year ended December 31, 2022 was primarily attributable to an increase of $374.3 million in capital expenditures incurred to develop our oil and gas properties and an increase in acquisitions of $213.5 million. During the year ended December 31, 2023, we paid cash consideration of $361.6 million for the 2023 Williston Basin Acquisition as compared to net cash consideration of $148.1 million paid to Whiting stockholders in connection with the Merger in 2022. In addition, we had a decrease in proceeds from the sale of our investment in Crestwood and cash distributions for our ownership of Crestwood’s common units of $420.7 million (see Note 12—Investment in Unconsolidated Affiliate). We had a decrease in proceeds from divestitures of $114.8 million year-over-year, whereby we received net proceeds from divestitures of $160.0 million in connection with the completion of the OMP Merger in February 2022 compared to $54.4 million primarily due to the sale of non-core properties and non-operated wellbore divestitures during year ended December 31, 2023. These increases in net cash used in investing activities were partially offset by a decrease of $364.1 million for cash payments to settle commodity derivative contracts.

Cash flows used in financing activities

For the year ended December 31, 2023, net cash used in financing activities of $664.7 million was primarily attributable to dividends paid to stockholders of $500.3 million and payments made to repurchase common stock of $239.3 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 million. For the year ended December 31, 2022, net cash used in financing activities of $823.1 million was primarily attributable to dividends paid to stockholders of $654.7 million, payments made to repurchase common stock of $152.0 million and payments for income tax withholdings on vested equity-based compensation awards of $41.8 million, partially offset by proceeds from the exercise of outstanding warrants of $19.8 million.

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:

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(1)Other capital expenditures includes items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $4.1 million for the year ended December 31, 2023, $4.6 million for the year ended December 31, 2022 and $2.1 million for the year ended December 31, 2021.

(2)Total E&P and other capital expenditures for the year ended December 31, 2023 includes $14.5 million related to divested non-operated assets that are expected to be reimbursed.

(3)Excludes amounts attributable to the Merger.

(4)Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations related to the OMP Merger.

(5)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 above 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.

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For the year ended December 31, 2023, our total E&P and other capital expenditures increased $418.7 million to $926.5 million as a result of the Merger, which significantly expanded our operations in the Williston Basin. This increase was primarily attributable to a $340.1 million increase in drilling and completion activities and higher costs associated with drilling longer lateral lengths on our operated wells, and a $68.4 million increase in workover activities driven by an increase in the number of workover projects year-over-year. We completed 69 net operated wells in 2023, compared to 54 net operated wells in 2022.

Additionally, on June 30, 2023, we completed the 2023 Williston Basin Acquisition for total cash consideration of $361.6 million. Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.

Our planned 2024 E&P capital expenditures are expected to be approximately $905 million to $945 million. We expect to run four operated rigs during the majority of 2024 and plan to TIL approximately 103 to 113 gross operated wells with an average working interest of approximately 75%.

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, 2023, we declared base-plus-variable cash dividends of $11.88 per share of common stock, or $508.6 million in aggregate. On February 21, 2024, we declared a base-plus-variable dividend of $3.25 per share of common stock. The dividends will be payable on March 19, 2024 to shareholders of record as of March 5, 2024. At December 31, 2023, we had dividends payable of $37.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $23.8 million that was recorded under accrued liabilities and $13.8 million that was recorded under other liabilities on the Consolidated Balance Sheet.

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.

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 October 2023, our Board of Directors authorized a new share repurchase program covering up to $750 million of our common stock, which replaced the existing $300 million share repurchase program that was authorized in August 2022.

During the year ended December 31, 2023, we repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise tax of $0.4 million, under both the August 2022 and October 2023 share repurchase programs. As of December 31, 2023, there was $683.0 million of capacity remaining under the existing $750 million program.

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 2—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:

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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 2—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 the 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 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 $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas for the year ended December 31, 2023. 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 21.7 MMBoe and decrease the PV-10 by $1.7 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 17.6 MMBoe and increase the PV-10 by $1.7 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.

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

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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.

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.

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.

The Merger

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 reserve 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.

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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:

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.

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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.”

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

__________________

(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.

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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:

__________________

(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.

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

__________________

(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.

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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.

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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:

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.

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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

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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.

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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.

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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:

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.

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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):

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(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.

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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.

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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.

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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.

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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.

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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:

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(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):

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

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(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):

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):

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):

__________________

(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):

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):