Chord Energy Corp (CHRD) FY 2023 MD&A

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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