Crescent Energy Co (CRGY)

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

Management's Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with the Consolidated Financial Statements and related Notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report and also with "Part I., Item 1A. Risk Factors" of this Annual Report. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the years ended December 31, 2024 and 2023. Refer to our 2023 Annual Report filed March 4, 2024 for discussion and analysis of the changes in results of operations between the years ended December 31, 2023 and 2022. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward- looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Annual Report , particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Business overview

Crescent is a differentiated U.S. energy company committed to delivering value for shareholders through a disciplined growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines stable cash flows from

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low-decline production with deep, high-quality development inventory. Our activities are focused in Texas and the Rocky Mountain region. Our Class A Common Stock trades on the NYSE under the symbol “CRGY.”

Geopolitical developments and economic environment

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility, impacted by the COVID-19 pandemic and recovery, Russia’s invasion of Ukraine and the related sanctions imposed on Russia, Hamas' attack against Israel and the ensuing conflict and escalation of tensions in the Middle East (including with Lebanon and Yemen), supply chain constraints, elevated interest rates and costs of capital and political and regulatory uncertainties, including any proposed tariffs. Furthermore, the United States has experienced, and may continue to experience, a significant inflationary environment, which began in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession in the United States in 2025 that has created further volatility. In December 2024, OPEC announced an extension of its production cuts of approximately 2.2 million barrels per day through the end of March 2025. The actions of OPEC with respect to oil production levels and announcements of potential changes in such levels, including agreement on and compliance with production cuts, may result in further volatility in commodity prices and the oil and natural gas industry generally. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

Certain of our non-operated assets in proved oil and natural gas properties, which have a carrying value of $264.8 million, have limited cushion between their carrying value and estimated undiscounted cash flows at the current forward commodity price curve as of December 31, 2024. A further decline of future commodity prices or a decrease in estimates of oil and natural gas reserves for these assets would likely result in an impairment charge. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, weighted-average cost of capital, operating cost estimates and future capital expenditures estimates. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022 and into 2023 and has remained relatively stable through 2024. Inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates in 2022, continuing through 2023. The U.S. Federal Reserve made cuts to benchmark interest rates in 2024 and it is currently anticipated that it will make additional cuts; however, there is no guarantee that such additional cuts will occur. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See Part I, Item 1A. Risk Factors—"Risks related to the oil and natural gas industry—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

In August 2022, the Inflation Reduction Act of 2022 (“IRA 2022”) was signed into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes a federal fee on the emission of greenhouse gases through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge is expected to be collected in 2025 based on calendar year 2024 emissions and the fee is based on certain thresholds established in

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the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See Part II, Item 1A. Risk Factors for additional information. The IRA 2022 also imposes a 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations, such as Crescent, after December 31, 2022.

On March 6, 2024, the SEC finalized rules to require certain climate-related disclosures in filings for public companies, beginning in fiscal year 2026 for accelerated filers. However, the rule has been subject to consolidated legal challenges in the U.S. Court of Appeals for the Eighth Circuit and the SEC has announced that it will not implement the rule while litigation is pending. While we are still assessing the rule’s potential impact on us, if the rule takes effect, we will be required to incur costs in order to comply.

Capital market transactions

2024 Senior Notes Offerings

In June 2024, we issued $750.0 million aggregate principal amount of 7.375% senior notes due 2033 (the "2033 Notes") at par (the "June 2024 Offering"). In September 2024, we issued an additional $250.0 million, aggregate principal amount of 2033 Notes at 101.000% of par (the "September 2024 Offering," and together with the June 2024 Offering, the "2033 Notes Offerings"). The aggregate proceeds from the 2033 Notes Offerings were approximately $982.1 million, after adjusting for premiums, the initial purchasers' discount and offering expenses. We used the aggregate net proceeds from the 2033 Notes Offerings to finance the majority of the SilverBow Merger, including (i) fund the cash paid to the SilverBow stockholders and holders of SilverBow restricted stock units in connection with the SilverBow Merger, and (ii) repay and extinguish SilverBow's existing indebtedness that was outstanding at the completion of the SilverBow Merger for $1.2 billion, including extinguishment costs. In connection with the repayment of SilverBow's debt we incurred a Loss on the extinguishment of debt of $36.5 million, inclusive of make whole fees.

All issuances of the 2033 Notes are treated as a single series of securities under the indenture governing the 2033 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.

In March 2024, we issued $700.0 million aggregate principal amount of 7.625% senior notes due 2032 (the "2032 Notes") at par (the “March 2024 Offering”). In December 2024, we issued an additional $400.0 million, aggregate principal amount of 2032 Notes at 100.250% of par (the "December 2024 Offering," and together with the March 2024 Offering, the "2032 Notes Offerings"). The aggregate proceeds from the 2032 Notes Offering were approximately $1,080.7 million, after deducting the initial purchasers' discount and offering expenses. We used the net proceeds to finance the majority of the consideration of the Tender Offer and Redemption (each term as defined below) of all of the aggregate principal amount of the 2026 Notes outstanding for $714.8 million after including extinguishment costs, as discussed further below. We used the proceeds from the December 2024 Offering to repay the amounts outstanding under our Revolving Credit Facility.

All issuances of the 2032 Notes are treated as a single series of securities under the indenture governing the 2032 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.

2024 Equity Transactions

In December 2024, we conducted an underwritten public offering of 24.7 million shares of Class A Common Stock at a price to the public of $14.00 per share (not including underwriter discounts and commissions) (the "December 2024 Equity Issuance"). This included 3.2 million shares of Class A Common Stock that were issued upon the underwriters exercise of their 30-day option to purchase additional shares to cover over-allotments pursuant to the related underwriting agreement. We received net proceeds of approximately $329.3 million from the 2024 Equity Issuance, after deducting underwriting fees and expenses.

On April 1, 2024, Independence Energy Aggregator L.P., the entity through which certain private investors in affiliated KKR entities held their interests in us, exercised its redemption right with respect to 6.0 million OpCo Units, and such OpCo Units were exchanged for an equivalent number of shares of Class A Common Stock and a corresponding number of shares of Class B Common Stock were cancelled (the "April 2024 Class A Redemption"). The shares of Class A Common Stock were subsequently sold by Independence Energy Aggregator L.P. at a price per share of $10.74, pursuant to Rule 144, through a broker-dealer. We did not receive any proceeds or incur any material expenses related to the April 2024 Class A Redemption.

In March 2024, 16.1 million OpCo Units were acquired from Independence Energy Aggregator L.P. and we cancelled a corresponding number of shares of Class B Common Stock (the "March 2024 Redemption"). Of the total OpCo Units acquired, 13.8 million were exchanged for shares of Class A Common Stock, which were subsequently sold in an underwritten public offering at a price to the public of $10.50 per share, or a net price of $9.87 per share after deducting the underwriters' discounts

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and commissions, from which we did not receive any proceeds, nor incur any material expenses with respect to such acquisition. In connection with the underwritten public offering, we repurchased 2.3 million OpCo Units from Independence Energy Aggregator L.P. for $22.7 million in cash and we cancelled a corresponding number of shares of Class B Common Stock (the "March 2024 Repurchase," together with the March 2024 Redemption, the "March 2024 Equity Transactions").

2023 Class A Redemption

During 2023, an affiliate of KKR exercised its redemption right with respect to approximately 30.6 million OpCo Units, and such OpCo Units were exchanged for an equivalent number of shares of Class A Common Stock and a corresponding number of shares of Class B Common Stock were cancelled (the "2023 Class A Redemption"). Approximately 27.6 million of those shares of Class A Common Stock were subsequently distributed to certain of its legacy investors in privately-managed funds and accounts. The remaining 3.0 million shares of Class A Common Stock were subsequently sold by affiliates of KKR at a price per share of $10.90, pursuant to Rule 144, through a broker-dealer. We did not receive any proceeds or incur any material expenses associated with the 2023 Class A Redemption.

September 2023 Underwritten Public Offering

In September 2023, we conducted an underwritten public offering of 12.7 million shares of Class A Common Stock at a price to the public of $12.25 per share (not including underwriter discounts and commissions). This included 1.7 million shares of Class A Common Stock that were issued upon the underwriters exercise of their 30-day option to purchase additional shares to cover over-allotments pursuant to the related underwriting agreement. We received net proceeds of $145.7 million from the Equity Issuance (the "2023 Equity Issuance," and together with the 2024 Equity Issuance, the "Equity Issuances"), after deducting underwriting fees and expenses.

2023 Senior Notes Offerings

On February 1, 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "Original 2028 Notes") at par. In July 2023, we issued an additional $300.0 million aggregate principal amount of 9.250% senior notes due 2028 at 98.000% of par (the "July 2028 Notes"); in September 2023, we issued an additional $150.0 million aggregate principal amount of 9.250% senior notes due 2028 at 101.125% of par (the "September 2028 Notes"); and in December 2023, we issued an additional $150.0 million aggregate principal amount of 9.250% senior notes due 2028 at 102.125% of par (the "December 2028 Notes," and together with the Original 2028 Notes, the July 2028 Notes and the September 2028 Notes, the "2028 Notes"). These four issuances of the 2028 Notes are treated as a single series of securities under the indenture governing the Original 2028 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price. The 2028 Notes interest is payable on February 15 and August 15 of each year and mature on February 15, 2028.

Acquisitions, divestitures and related reorganization

Acquisitions and related reorganization

Ridgemar Acquisition

On December 3, 2024, we entered into the Membership Interest Purchase Agreement (the “Ridgemar Acquisition Agreement”) pursuant to which we acquired all of the outstanding equity interests in Ridgemar (Eagle Ford) LLC (“Ridgemar”). In connection with the closing of the Ridgemar Acquisition in the first quarter of 2025, we paid $819 million in cash and issued 5.5 million shares of our Class A Common Stock to former Ridgemar owners, before any customary post closing adjustments (the "Ridgemar.Acquisition"). In addition, we agreed to pay up to $170.0 million in earn-out consideration paid quarterly in fiscal years 2026 and 2027 based on the quarterly NYMEX WTI price of crude oil in fiscal years 2026 and 2027 (collectively, the "Ridgemar Consideration”).

SilverBow Merger

On July 30, 2024, we consummated the SilverBow Merger. See “—NOTE 3 – Acquisitions and Divestitures. Immediately following the SilverBow Merger, Crescent Energy Company completed a series of internal transactions following which the assets of SilverBow Resources, Inc. ("SilverBow") and its subsidiary became held by subsidiaries of Crescent Energy Finance LLC. In connection with the SilverBow Merger, Crescent issued 51.6 million shares of Class A Common Stock and paid

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$382.4 million in cash to former SilverBow shareholders, including amounts payable in respect of outstanding SilverBow equity awards. In connection with the closing of the SilverBow Merger, we repaid all of SilverBow’s outstanding indebtedness.

Other Acquisitions

In January 2025, we acquired from unaffiliated third parties additional interests in Crescent operated oil and gas properties, rights and related assets located in Webb County, Texas for aggregate consideration of approximately $21.2 million, subject to customary post closing adjustments.

In October 2024, we acquired from unaffiliated third parties certain interests in oil and gas properties, rights and related assets located in Atascosa, Frio, La Salle and McMullen Counties, Texas for aggregate consideration of approximately $156.0 million, including certain customary purchase price adjustments.

In February 2024, we acquired a portfolio of oil and natural gas mineral interests located in the Karnes Trough of the Eagle Ford Basin from an unrelated third-party (the "Eagle Ford Minerals Acquisition") for total cash consideration of approximately $25.0 million, including customary purchase price adjustments. The purchase price was funded using borrowings under our Revolving Credit Facility.

In October 2023, we consummated the unrelated acquisition contemplated by the Purchase and Sale Agreement, dated as of August 22, 2023, between our subsidiary and an unaffiliated third party, pursuant to which we agreed to acquire certain incremental working interests in oil and natural gas properties (the "October Western Eagle Ford Acquisition," and together with the July Western Eagle Ford Acquisition, the "Western Eagle Ford Acquisitions") in certain of our existing Western Eagle Ford assets from the seller for aggregate cash consideration of approximately $235.1 million, including certain customary purchase price adjustments.

In July 2023, we consummated the acquisition contemplated by the Purchase and Sale Agreement, dated as of May 2, 2023, between our subsidiary and Comanche Holdings, LLC ("Comanche Holdings") and SN EF Maverick, LLC ("SN EF Maverick," and together with Comanche Holdings, the "Seller"), pursuant to which we agreed to acquire operatorship and incremental working interests (the "July Western Eagle Ford Acquisition") in certain of our existing Western Eagle Ford assets from the Seller for aggregate cash consideration of approximately $592.7 million, including capitalized transaction costs and certain final purchase price adjustments.

Divestitures

During 2024, we sold non-core assets to unrelated third-party buyers for $54.8 million in aggregate cash proceeds and recorded a gain of approximately $29.4 million on the sale of these assets.

Stewardship

We seek to strategically improve assets we own and acquire to deliver enhanced financial returns, operations and stewardship. We believe that being a responsible operator will produce better outcomes, creating a net benefit for society and the environment, while delivering attractive returns for our investors. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate.

We are members of the Oil & Gas Methane Partnership 2.0 Initiative, or OGMP 2.0, and received Gold Standard pathway ratings in 2022, 2023 and 2024 for our credible plan to more accurately measure our methane emissions. OGMP 2.0 is the United Nations Environment Programme's flagship oil and gas reporting and mitigation program and the leading industry standard for methane emissions reporting. We also established a Sustainability Advisory Council, an outside council comprising leading exports across key sustainability topics, to advise management and our Board of Directors on sustainability-related issues. See additional materials on our website at www.crescentenergyco.com/sustainability. However, please note that the contents and other materials on our website in general, are not intended or deemed to be incorporated into this Annual Report by reference.

How we evaluate our operations

We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:

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•Production volumes sold;

•Commodity prices and differentials;

•Operating expenses;

•Adjusted EBITDAX (non-GAAP); and

•Levered Free Cash Flow (non-GAAP)

Development program and capital budget

Our development program, which consists of expenditures for drilling, completion and recompletion activities, is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.

We expect to fund our 2025 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that the majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Sources of revenues

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Pricing of commodities are subject to supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 5% or less of our total revenues for each of the years ended December 31, 2024, 2023 and 2022.

Production volumes sold

The following table presents historical sales volumes for our properties:

Total sales volume increased 19,104 MBoe during the year ended December 31, 2024 compared to 2023. The increase is primarily due to the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the second half of 2023.

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Commodity prices and differentials

Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations, either as a result of the COVID-19 pandemic and recovery, Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, the Israel-Hamas conflict and the broader conflict in the Middle East, actions taken by OPEC, sustained elevated inflation and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC’s actions, increased U.S. drilling, proposed tariffs, inflation and the armed conflicts in Ukraine and the Middle East. Additionally, market concern regarding the health of the global banking sector and any resultant recessionary effects contributed, among other factors, to increased volatility in the price for oil and natural gas.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:

The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:

(1)The realized price presented above does not include $60.8 million received from the settlement of acquired oil, gas and NGL derivative contracts for the year ended December 31, 2024. For the years ended December 31, 2023 and 2022, the realized price presented above does not include $61.5 million and $49.9 million paid for the settlement of acquired oil derivative contracts, respectively.

Results of operations:

Year ended December 31, 2024 compared to year ended December 31, 2023

Revenues

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The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:

Oil revenue. Oil revenue increased $379.5 million, or 22%, in 2024 compared to 2023. This increase was driven by a $407.9 million increase from higher sales volumes (15 MBbl/d, or 22%), partially offset by lower realized oil prices that resulted in a decrease of $28.4 million (a decline of 1% per Bbl). The increase in sales volumes was primarily driven the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the second half of 2023. The decrease in realized oil prices was due to lower index prices, which was partially offset by price realizations.

Natural gas revenue. Natural gas revenue decreased $21.2 million, or 6%, in 2024 compared to 2023. This decrease was driven by lower realized natural gas prices that resulted in a decrease of $170.6 million (a decline of 33% per Mcf), partially offset by a $149.4 million increase from higher sales volumes (143 MMcf/d, or 40%). The increase in sales volumes was primarily due to the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the second half of 2023. The decrease in realized natural gas prices was due to lower index prices and associated realizations.

NGL revenue. NGL revenue increased $124.1 million, or 64%, in 2024 compared to 2023. This increase was driven by a $106.5 million increase from higher sales volumes (13 MBbl/d, or 57%) and higher realized NGL prices that resulted in an increase of $17.6 million (an increase of 6% per Bbl). The increase in sales volumes was primarily driven by the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the second half of 2023.

Midstream and other revenue. Midstream and other revenue increased $66.0 million, or 97%, in 2024 compared to 2023, due to higher oil blending revenues in 2024.

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Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

*NM = Not meaningful.

Operating expense. Total operating expense increased $199.7 million, or 19%, in 2024 compared to 2023, driven primarily by the following factors:

(i)Lease and asset operating expenses increased $50.1 million, or 9%, in 2024 compared to 2023. Additionally, lease and asset operating expense per Boe decreased $2.09 per Boe from $10.67 per Boe to $8.58 per Boe. This $50.1 million increase was driven primarily by higher production from the SilverBow Merger and Western Eagle Ford Acquisitions, which closed in the second half of 2023, partially offset by cost reduction measures on our other assets. The additional costs from our acquisitions was more than offset on a per Boe basis with the additional volumes and cost reduction measures.

(ii)Gathering, transportation and marketing expense increased $77.8 million, or 33%, in 2024 compared to 2023. However, gathering, transportation and marketing expense per Boe decreased $0.06 per Boe from $4.31 per Boe to $4.25 per Boe. This increase in expense was driven primarily by the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the second half of 2023, but was more than offset by the additional volumes from these acquisitions.

(iii)Production and other taxes decreased $0.3 million, or 0%, in 2024 compared to 2023 and decreased $0.78 per Boe, or 26%, to $2.21 per Boe. This decrease was driven primarily by lower effective tax rates and increased gathering, transportation and marketing expense, which decreased the tax base upon which our production and other taxes are calculated.

(iv)Workover expense increased $1.9 million in 2024 compared to 2023, and decreased $0.25 per Boe from $1.07 per Boe to $0.82 per Boe. This increase was primarily caused by the SilverBow Merger.

(v)Midstream operating expense increased $70.3 million, or 177%, in 2024 compared to 2023, primarily due to increased crude oil blending expense. The additional crude oil blending expense was more than offset by additional oil blending revenue included as part of our Midstream and other revenue.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $273.7 million, or 41%, in 2024 compared to 2023, driven primarily by increased production from the SilverBow Merger and our Western Eagle Ford Acquisitions and an increased DD&A rate.

Impairment expense. During the years ended December 31, 2024 and 2023, we evaluated our Oil and natural gas properties and Investments in equity affiliates and determined that certain amounts were impaired. As a result of our evaluations, during the year ended December 31, 2024, we recorded an impairment expense of $161.5 million related to Oil and natural gas properties that were determined not to be recoverable. During the year ended December 31, 2023, we recorded an impairment expense of $153.5 million, including $149.6 million related to Oil and natural gas properties that were determined not to be recoverable and $3.9 million related to Investments in equity affiliates.

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General and administrative expense. General and administrative expense ("G&A") increased $195.3 million, or 139%, in 2024 compared to 2023, driven primarily by (i) an increase in equity-based compensation expense of $110.5 million (2024 and 2023 include additional catch up expense of $121.8 million and $30.4 million, respectively, due to change in estimate), (ii) $63.8 million higher transaction and nonrecurring related expenses primarily driven by the SilverBow Merger and (iii) higher recurring G&A, primarily driven by higher Manager Compensation expense. The increase in the Manager Compensation expense is due to an increase in public ownership of Class A Common Stock and a corresponding increase in ownership of OpCo as a result of (i) our equity issuances, and (ii) share redemptions for our Class A Common Stock.

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $22.2 million compared to 2023, primary driven by a $29.4 million higher gain on sale of assets recognized in 2024, partially offset by $7.3 million in higher exploration expenses.

Interest expense. In 2024, we incurred interest expense of $216.3 million, as compared to $145.8 million in 2023, a 48% increase. The increase was primarily driven by higher average debt balances driven by the SilverBow Merger and the Western Eagle Ford Acquisitions.

Loss on extinguishment of debt. In 2024, we incurred a loss on the extinguishment of debt of $59.1 million composed of (i) $22.6 million related our 2026 Notes, of which $14.8 million is associated with the premium and interest paid for the Tender Offer and Redemption and $7.8 million is related to the write-off of related outstanding deferred finance costs and (ii) $36.5 million related to the make whole provision and premium associated with the repayment of SilverBow’s Second Lien Notes.

Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenue. Our loss on commodity derivatives during 2024, changed by $281.3 million, or 168%, from a gain during 2023 primarily due to changes in commodity prices relative to our strike price.

Income tax benefit (expense). For the years ended December 31, 2024 and 2023 we recognized income tax benefit of $31.1 million and $23.2 million, respectively, for an effective tax rate of 18.4% and 6.7%, respectively. Our effective tax rate is typically lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests. Our effective tax rate increased in 2024 primarily due to our increased ownership of OpCo in 2024 and a corresponding decrease in the amount of income attributed to our noncontrolling and redeemable noncontrolling interests.

Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)

Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results and liquidity. See “—Non-GAAP financial measures” section below for their definitions and application.

The following tables present reconciliations of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss), and Levered Free Cash Flow (non-GAAP) to Net cash provided by operating activities, the most directly comparable financial measures, respectively, calculated in accordance with GAAP:

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(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflect Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo's ownership under management.

(2)Transaction and nonrecurring expenses of $82.5 million during the year ended December 31, 2024 were primarily related to the SilverBow Merger, capital markets transactions and integration expenses. Transaction and nonrecurring expenses of $22.6 million for the year ended December 31, 2023 were primarily related to the Western Eagle Ford Acquisitions and system integration expenses.

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(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflect Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo's ownership under management.

(2)Transaction and nonrecurring expenses of $82.5 million during the year ended December 31, 2024 were primarily related to the SilverBow Merger, capital markets transactions and integration expenses. Transaction and nonrecurring expenses of $22.6 million for the year ended December 31, 2023 were primarily related to the Western Eagle Ford Acquisitions and system integration expenses.

Adjusted EBITDAX (non-GAAP) increased by $575.6 million or 56% in 2024, compared to 2023, driven primarily by additional production generated by the SilverBow Merger and our Western Eagle Ford Acquisitions, which closed in the second half of 2023.

Levered Free Cash Flow (non-GAAP) increased by $320.0 million or 103% in 2024 compared to 2023, driven primarily by increased Adjusted EBITDAX of $575.6 million, partially offset by $166.9 million of increased capital expenditures, additional interest expense, a loss from extinguishment of debt and income taxes.

Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations, proceeds from equity and debt offerings and borrowings under a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the “Revolving Credit Facility") with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. Our primary expected uses of capital are for dividends to shareholders, our share repurchase program, debt repayment, development of our existing assets and acquisitions.

Our development program is designed to prioritize the generation of meaningful free cash flow and attractive risk-adjusted returns, and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. See “—Development program and capital budget” above for additional discussion of our capital program.

We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production generated by the capital investment as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to protect margins and corporate returns through commodity cycles. For information regarding risks related to our derivative program, see "Part I., Item 1A. Risk Factors".

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The following table presents our cash balances and outstanding borrowings at the end of each period presented:

In connection with the closing of the Ridgemar Acquisition in the first quarter of 2025, we paid in total $819 million in cash to former Ridgemar owners after customary purchase price adjustments. We funded the cash to close, less the initial deposit, with cash on hand and borrowings under our Revolving Credit Facility. Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our debt agreements. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to the various agreements subsequently described under the heading “Contractual obligations,” recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Cash flows

The following table summarizes our cash flows for the periods indicated:

Net cash provided by operating activities. Net cash provided by operating activities for the year ended December 31, 2024 increased by $287.3 million, or 31%, compared to 2023, primarily due to higher net income after adjusting for non-cash items, partially offset by working capital changes.

Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2024 decreased by $200.5 million, or 14%, compared to 2023. Our Acquisitions of oil and gas properties on the consolidated statements of cash flows of $558.6 million in 2024 was driven primarily by the SilverBow Merger, the Central Eagle Ford Acquisition and Eagle Ford Minerals Acquisition, while the 2023 acquisitions of $849.3 million was driven by our Western Eagle Ford Acquisitions. Our cash expenditures related to the Development of oil and natural gas properties on the consolidated statements of cash flows increased by $104.3 million, and we had $25.8 million higher proceeds from the sale of oil and natural gas properties.

Net cash provided by financing activities. Net cash provided by financing activities for the year ended December 31, 2024 was $207.4 million, a decrease of $249.1 million, driven by a $1.2 billion repayment of debt and a $75.0 million settlement of deferred acquisition consideration, both of which were acquired in the SilverBow Merger. These decreases were partially offset by additional net cash received of $866.9 million in our 2024 debt transactions compared to 2023 and additional cash received of $186.0 million from our 2024 equity issuances compared to 2023.

Debt agreements

Senior Notes

2033 Notes

In June 2024, we issued $750.0 million aggregate principal amount of 7.375% senior notes due 2033 (the "2033 Notes") at par (the "June 2024 Offering"). In September 2024, we issued an additional $250.0 million, aggregate principal amount of 2033 Notes at 101.000% of par (the "September 2024 Offering," and together with the June 2024 Offering, the "2033 Notes Offerings"). The aggregate proceeds from the 2033 Notes Offerings were approximately $982.1 million, after adjusting for premiums, the initial purchasers' discount and offering expenses. We used the aggregate net proceeds from the 2033 Notes Offerings to finance the majority of the SilverBow Merger, including (i) fund the cash paid to the SilverBow stockholders and holders of SilverBow restricted stock units in connection with the SilverBow Merger, and (ii) repay and extinguish SilverBow's

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existing indebtedness that was outstanding at the completion of the SilverBow Merger for $1.2 billion, including extinguishment costs. In connection with the repayment of SilverBow's debt we incurred a Loss on the extinguishment of debt of $36.5 million, inclusive of make whole fees.

All issuances of the 2033 Notes are treated as a single series of securities under the indenture governing the 2033 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.

The 2033 Notes bear interest at an annual rate of 7.375%, which is payable on January 15 and July 15 of each year, and mature on January 15, 2033. We may, at our option, redeem all or a portion of the 2033 Notes at any time on or after July 15, 2027 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2033 Notes before July 15, 2027 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of the 2033 Notes being redeemed, plus accrued and unpaid interest, in any, to, but excluding the redemption date, if at least 50% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. In addition, prior to July 15, 2027, we may redeem some or all of the 2033 Notes at a price equal to 100% of the principal amount thereof, plus a "make-whole" premium and accrued and unpaid interest, if any, to but excluding the redemption date.

2032 Notes

In March 2024, we issued $700.0 million aggregate principal amount of 7.625% senior notes due 2032 (the "2032 Notes") at par (the “March 2024 Offering”). In December 2024, we issued an additional $400.0 million, aggregate principal amount of 2032 Notes at 100.250% of par (the "December 2024 Offering," and together with the March 2024 Offering, the "2032 Notes Offerings"). The aggregate proceeds from the 2032 Notes Offering were approximately $1,080.7 million, after deducting the initial purchasers' discount and offering expenses. We used the net proceeds to finance the majority of the consideration of the Tender Offer and Redemption (each term as defined below) of all of the aggregate principal amount of the 2026 Notes outstanding for $714.8 million after including extinguishment costs, as discussed further below. We used the proceeds from the December 2024 Offering to repay the amounts outstanding under our Revolving Credit Facility.

All issuances of the 2032 Notes are treated as a single series of securities under the indenture governing the 2032 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price.

The 2032 Notes bear interest at an annual rate of 7.625%, which is payable on April 1 and October 1 of each year, and mature on April 1, 2032. We may, at our option, redeem all or a portion of the 2032 Notes at any time on or after April 1, 2027 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2032 Notes before April 1, 2027 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.625% of the principal amount of the 2032 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to April 1, 2027, we may redeem some or all of the 2032 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

2028 Notes

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes") at par. In July 2023, we issued an additional $300.0 million, aggregate principal amount of 2028 Notes at 98.000% of par. In September 2023, we issued an additional $150.0 million aggregate principal amount of 2028 Notes at 101.125% of par. In December 2023, we issued an additional $150.0 million aggregate principal amount of 2028 Notes at 102.125% of par. The aggregate proceeds from the offerings of the 2028 Notes were $977.4 million, after adjusting for discounts, premiums and offering expenses, but excluding accrued interest payable by purchasers of the 2028 Notes. We used the aggregate net proceeds to repay a portion of our outstanding balance under our Revolving Credit Facility (as defined herein) and to fund a portion of the Western Eagle Ford Acquisitions.

All issuances of the 2028 Notes are treated as a single series of securities under the indenture governing the 2028 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date, the issue price, and the first interest payment date.

The 2028 Notes bear interest at an annual rate of 9.250%, which is payable on February 15 and August 15 of each year and mature on February 15, 2028.

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2026 Notes

At December 31, 2023 we had $700.0 million outstanding aggregate principal amount of 7.250% senior notes due 2026 (the "2026 Notes") that were subject to the indenture dated May 6, 2021, as supplemented to the date hereof, between us and our trustee (the "2021 Indenture"). In March 2024, pursuant to a cash tender offer (the "Tender Offer") and redemption of any remaining 2026 Notes following the Tender Offer (the "Redemption"), we extinguished all of our 2026 Notes. After the Tender Offer and the Redemption, the 2021 Indenture was satisfied and discharged on March 26, 2024, and we have no further obligations under the 2021 Indenture at March 31, 2024. We repurchased all of the 2026 Notes at a blended price of 101.857% of par and thus incurred a Loss on the extinguishment of debt of $22.6 million, including the write-off of any remaining deferred financing costs.

After the completion of the Tender Offer and Redemption, the 2028 Notes, the 2032 Notes and 2033 Notes (collectively, the "Senior Notes") are our senior unsecured obligations and the Senior Notes and the related guarantees rank equally in right of payment with the borrowings under our Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee our Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

The indentures governing the Senior Notes contains covenants that, among other things, limit the ability of the our restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of its equity or redeem, repurchase or retire its equity or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from any non-Guarantor restricted subsidiary to it; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the notes in the future, on any securities exchange, and currently there is no public market for the notes.

Revolving Credit Facility

In connection with the issuance of the 2026 Notes in May 2021, Crescent Finance entered into the Revolving Credit Facility. The Revolving Credit Facility matures on April 10, 2029. At December 31, 2024, we had no amount of outstanding borrowings under the Revolving Credit Facility and $21.2 million in outstanding letters of credit, our elected commitment amount was $2.0 billion, and we had $2.0 billion of available borrowings.

Borrowings under the Revolving Credit Facility bear interest at either a (i) U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted secured overnight financing rate ("SOFR"), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments at December 31, 2024 is 0.375% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2023 was 9.75% and we had no borrowings outstanding under the Revolving Credit Facility as of December 31, 2024.

The borrowing base under the Revolving Credit Facility was $2.6 billion as of December 31, 2024. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

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The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of our and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by us and such guarantors. In connection with each redetermination of the borrowing base, we must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. Our domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such event of default, the lenders will be able to accelerate maturity and exercise other rights and remedies. At December 31, 2024, we were in compliance with each of the covenants under the Revolving Credit Facility and expect to remain in compliance with these covenants for the foreseeable future.

On April 10, 2024, we entered into the Seventh Amendment to the Revolving Credit Facility, which, among other things, the amendment included a reduction of the borrowing base to $1.7 billion from $2.0 billion, maintained elected commitments at $1.3 billion and extended the maturity date of any revolving loans under the Revolving Credit Facility to April 10, 2029. The amendment also modified the fee payable for the unused revolving commitments such that it is 0.375% or 0.50% per year based on utilization of the Revolving Credit Facility and maintained the applicable margin, so that the loans under the Revolving Credit Facility will continue to be priced based on SOFR plus 2.35% to 3.35% or an adjusted base rate plus 1.25% to 2.25%, in each case, based on utilization of the Revolving Credit Facility.

On May 24, 2024, we entered into the Eighth Amendment to the Revolving Credit Facility, which, among other things, increased the threshold amount for the incurrence of certain additional indebtedness from $500.0 million to $1.0 billion during the period beginning on May 24, 2024 and ending on the scheduled redetermination date for the October 1, 2024 scheduled borrowing base redetermination. As a result, during this period, the borrowing base will not be required to be reduced by 0.25x of the principal amount of such new debt incurrences so long as the principal amount of such indebtedness does not exceed the $1.0 billion aggregate threshold.

On June 14, 2024, we entered into the Ninth Amendment to the Revolving Credit Facility, which, among other things, (a) permits the issuance of the 2033 Notes as permitted additional debt under the Revolving Credit Facility and (b) excludes the proceeds of the 2033 Notes from the requirement to prepay the revolving loans under the Revolving Credit Facility with excess cash on a monthly basis until the earliest to occur of (i) the date of consummation of the SilverBow Merger, (ii) the date on which we redeem the 2033 Notes in full as a result of the occurrence of an event requiring special mandatory redemption and (iii) May 22, 2025.

On July 30, 2024, in connection with the closing of the SilverBow Merger, we entered into the Tenth Amendment to the Revolving Credit Facility in order to, among other things, increase the aggregate elected commitment amount of $2.0 billion and increase the borrowing base from $1.7 billion to $2.6 billion.

On December 17, 2024 we entered into the Eleventh Amendment to the Revolving Credit Facility, which, among other things, (i) reduced the applicable margin, so that the loans under the Credit Agreement, at Crescent Finance’s option, will be priced based on SOFR plus 2.00% to 3.00% or an adjusted based rate plus 1.00% to 2.00%, in each case, based on the utilization of the credit facility, (ii) removed the credit spread adjustment, and (iii) provides that the incurrence of up to $500.0 million of certain additional indebtedness during the period beginning on December 17, 2024 and ending on the scheduled redetermination date for the April 1, 2025 scheduled borrowing base redetermination will be excluded from the requirement for the borrowing base to be reduced by 0.25x of the principal amount of such new debt incurrences, so long such debt is incurred during such period and does not exceed the $500.0 million aggregate threshold. The borrowing base was maintained at $2.6 billion and the elected commitment amount was maintained at $2.0 billion.

Capital expenditures

Our acquisition and development expenditures consist of acquisitions of proved and unproved property, expenditures associated with the development of our oil and natural gas properties and other asset additions. Cash expenditures for drilling, completion

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and recompletion activities are presented as "Development of oil and natural gas properties" in investing activities on our consolidated statements of cash flows.

We expect to fund our 2025 capital program, excluding acquisitions through cash flow from operations. The amount and timing of capital expenditures on development of oil and natural gas properties is substantially within our control due to the held-by-production nature of our assets. We regularly review our capital expenditures throughout the year and could choose to adjust our investments based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related Standardized Measure. These risks could materially affect our business, financial condition and results of operations.

The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented:

The increase in our development of oil and natural gas properties costs in 2024 is primarily related to increased activity and well completions on our larger asset base resulting from the SilverBow Merger and Western Eagle Ford Acquisitions, partially offset by the timing of invoices. We used cash of $558.6 million in 2024 for the acquisitions of oil and natural gas properties, primarily related to the SilverBow Merger, the Central Eagle Ford Acquisition and the Eagle Ford Minerals Acquisition, as compared to $849.3 million in 2023, primarily related to the Western Eagle Ford Acquisitions. See “Notes to Consolidated Financial Statements—NOTE 3 – Acquisitions and Divestitures in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.

Contractual obligations

The following table presents our material contractual obligations at December 31, 2024:

(1)Long-term debt represents our outstanding borrowings as of December 31, 2024 consisting of our Senior Notes; (maturing on February 15, 2028, April 1, 2032 and January 15, 2033) and, if any, borrowings under our Revolving Credit Facility (maturing on April 10, 2029).

(2)Excludes variable rate debt interest payments and commitment fees related to the Company's Revolving Credit Facility.

(3)Amounts represent estimated discounted costs for future dismantlement and abandonment of our oil and natural gas properties. See "Notes to Consolidated Financial Statements—NOTE 9 - Asset Retirement Obligation" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for additional discussion of our asset retirement obligations.

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(4)Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our oil and natural gas production to market, as well as, pipeline, processing and storage capacity.

(5)Amounts shown represent contractual liquidation damages at December 31, 2024 for failure to drill and complete wells on certain leases.

General and Administrative Expense

Our general and administrative expense includes corporate overhead costs, professional service fees, insurance, software applications, fees for transaction expenses, expenses payable under the Management Agreement with KKR Energy Assets Manager LLC, incentive compensation award agreements granting profits interests, restricted stock units, performance stock units and other incentive awards granted to our employees and non-employee directors.

The incentive compensation portion relates to certain equity-classified and liability-classified profits interests awards issued by our subsidiaries (collectively, “Profits Awards”). These Profits Awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Compensation cost for these awards is presented within General and administrative expense on our consolidated statements of operations. As of December 31, 2024, (i) unrecognized compensation cost related to unvested equity-classified profits interest awards was $2.3 million, and (ii) we carried $4.5 million in Other long term liabilities on the consolidated balance sheet and had unrecognized compensation of $2.9 million related to unvested liability-classified profits interest awards. Actual amounts paid towards equity-classified profits interests awards in the future will be shown as distributions to non-controlling interests in our consolidated financial statements, and may differ from the amounts shown for unrecognized compensation cost related to unvested equity-classified profits interest awards.

For additional information, see "Notes to Consolidated Financial Statements—NOTE 13 – Equity-Based Compensation Awards" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.

Dividends

Our future dividends depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the indentures governing the Senior Notes.

We paid cash dividends of $0.48 per share of our Class A Common Stock to shareholders during the year ended December 31, 2024.

On February 26, 2025, the Board of Directors approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the fourth quarter of 2024. The quarterly dividend is payable on March 26, 2025 to shareholders of record as of the close of business on March 12, 2025. OpCo unitholders will also receive a distribution based on their pro rata ownership of OpCo Units.

The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividend on a quarterly basis.

Stock Repurchase Program

Our Board of Directors authorized a stock repurchase program on March 4, 2024 with an approved limit of $150.0 million and a two-year term. Repurchases may be of our Class A Common Stock or of OpCo Units (with the cancellation of a corresponding number of shares of our Class B Common Stock). We have approximately $119.5 million of repurchase authorization under such program remaining as of December 31, 2024. Such repurchases may be made by Crescent or by OpCo, as applicable, and may be made from time to time in the open market, in a privately negotiated transaction, through purchases made in accordance with the Rule 10b5-1 of the Exchange Act or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate us to repurchase any dollar amount or number of securities.

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The IRA 2022 provides for, among other things, the imposition of a 1% non-deductible U.S. federal excise tax on the fair market value of any stock repurchased by a publicly traded domestic corporation during any taxable year, with the fair market value of such repurchased stock reduced by the fair market value of certain stock issued by such corporation during such taxable year (such excise tax, the “Stock Buyback Tax”). In the past, there have been proposals to increase the amount of the Stock Buyback Tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect. The Stock Buyback Tax first applied to our stock repurchase program in the year ended December 31, 2023, and will continue to apply in subsequent taxable years.

Critical accounting estimates

Our significant accounting policies are described in "Notes to Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report. The Company's consolidated financial statements are prepared in accordance with GAAP. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion of the accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of our consolidated financial statements. These accounting policies, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of our control could have significant adverse impact to our financial condition, results of operations and cash flows.

Crude oil, natural gas and NGL reserves

One of the most significant estimates the Company makes is the estimate of proved crude oil, natural gas and NGL reserves. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Our crude oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Technologies used in our reserves estimation includes decline curve analysis, statistical analysis of production performance, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. In addition, periodic revisions of our estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, crude oil and natural gas prices, changes in costs, capital funding and drilling plans (including our five-year development plan), technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.

When determining the December 31, 2024 proved reserves for each property, the benchmark prices issued by the SEC were adjusted using price differentials that account for property-specific quality and location differences. If the future average crude oil prices are below the average prices used to determine proved reserves at December 31, 2024, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of proved reserves, see "Part I., Item 1A. Risk Factors."

Estimates of proved reserves are key components of our most significant financial estimates including the computation of depreciation, depletion and amortization ("DD&A") and impairment of proved oil and natural gas properties.

Oil and natural gas properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. See "Notes to Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for further discussion of the accounting policies applicable to the successful efforts method of accounting.

The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.

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Depreciation, depletion and amortization

DD&A of oil and natural gas producing properties is determined on a field-by-field basis using the units-of-production method. During the years ended December 31, 2024, 2023, and 2022, we recognized DD&A expense of $949.5 million, $675.8 million, and $532.9 million, respectively.

While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates, any reduction in proved reserves, could result in an acceleration of future DD&A expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.

Impairment of oil and natural gas properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include:

•Estimates of oil and natural gas reserves and expected timing of production. Our oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Reserve engineering is a subjective process, which requires assumptions associated with the underground accumulations of oil and natural gas, development costs, future commodity prices and the future regulatory and political environment. Any significant variance in these assumptions could materially affect the estimated quantity and value of the reserves, which would affect the fair value of our oil and natural gas properties. The estimates of our reserves help to inform our expectation of future oil and natural gas production, which will likely vary from our actual production.

•Future commodity prices, which are based on publicly available forward commodity prices for a period of time and then escalated thereafter. A decrease in estimated future commodity prices will decrease the fair value of our oil and natural gas properties.

•Future capital requirements, which are based on our internal forecasts and supported by the underlying cash flows generated from our oil and natural gas assets.

•Discount rate commensurate with the risk associated with realizing projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.

During the years ended December 31, 2024, 2023, and 2022, we determined that there were triggering events requiring an evaluation of whether the carrying value of our oil and natural gas properties was recoverable. Following an assessment of our oil and natural gas properties, during the years ended December 31, 2024, 2023, and 2022, we recorded impairment expense of $161.5 million, $149.6 million and $65.2 million, respectively. Certain of our non-operated assets in proved oil and natural gas properties, which have a carrying value of $264.8 million, have limited cushion between their carrying value and estimated undiscounted cash flows at the current forward commodity price curve as of December 31, 2024. A further decline of future commodity prices or a decrease in estimates of oil and natural gas reserves for these assets would likely result in an impairment charge. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, weighted-average cost of capital, operating cost estimates and future capital expenditures estimates. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

Properties acquired in business combinations

When sufficient market data is not available, we determine the fair values of proved and unproved oil and natural gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of

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crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.

Significant reductions in the proved reserves used to determine the fair value of the acquired properties could result in future impairments of the properties. See the discussion above under "Depreciation, depletion and amortization: on the practicability of a sensitivity analysis due to changes in our fair value calculations.

Income taxes

Crescent is a holding company, the sole material assets of which are OpCo Units. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. Crescent is subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo. The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We routinely assess potential uncertain tax positions and, if required, establish accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment and are reviewed and adjusted routinely based on changes in facts and circumstances. Although we consider our tax accruals adequate, material changes in these accruals may occur in the future, based on the impact of tax audits, changes in legislation and resolution of pending or future tax matters. Refer to "Notes to Consolidated Financial Statements—NOTE 11 – Income Taxes" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for more information.

New and revised accounting standards

See “Notes to Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies” in Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.

Non-GAAP financial measures

Our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes financial and liquidity measures that have not been calculated in accordance with U.S. GAAP. These non-GAAP measures include the following:

•Adjusted EBITDAX; and

•Levered Free Cash Flow.

These are supplemental non-GAAP financial and liquidity measures used by our management to assess our operating results and assist us make our investment decisions. We believe that the presentation of these non-GAAP measures provides investors with greater transparency with respect to our results of operations, as well as liquidity and capital resources, and that these measures are useful for period-to-period comparison of results.

We define Adjusted EBITDAX as net income (loss) before interest expense, loss from extinguishment of debt, income tax expense (benefit), depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivatives, impairment expense, equity-based compensation, (gain) loss on sale of assets, other (income) expense and transaction and nonrecurring expenses. Additionally, we further subtract certain redeemable noncontrolling interest distributions made by OpCo and settlement of acquired derivative contracts. We include “Certain-redeemable noncontrolling interest distributions made by OpCo" to reflect Manager Compensation as if 100% of OpCo were owned and managed by the Company, to reflect consistent earnings and liquidity measures not impacted by the amount of OpCo's ownership under management.

Adjusted EBITDAX is not a measure of performance as determined by GAAP. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending

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upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance.

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums, loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums and SilverBow Merger transaction related costs, current income tax benefit (expense), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions.

Levered Free Cash Flow is not a measure of liquidity as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP liquidity measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Levered Free Cash Flow is a useful liquidity measure because it allows for an effective evaluation of our operating and financial performance and the ability of our operations to generate cash flow that is available to reduce leverage or distribute to our equity holders. Levered Free Cash Flow should not be considered as an alternative to, or more meaningful than, Net cash flow provided by operating activities as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual liquidity, operating performance or investing activities. Our computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies.

Adjusted EBITDAX and Levered Free Cash Flow should be read in conjunction with the information contained in our consolidated financial statements prepared in accordance with GAAP. For a reconciliation of these non-GAAP measures to the nearest comparable GAAP measures, see “—Results of Operations—Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)” above.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with the Combined and Consolidated Financial Statements and related Notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report and also with "Part I., Item 1A. Risk Factors" of this Annual Report. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the years ended December 31, 2023 and 2022. Refer to our 2022 Annual Report filed March 7, 2023 for discussion and analysis of the changes in results of operations between the years ended December 31, 2022 and 2021. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward- looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Annual Report , particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Business overview

We are a differentiated U.S. energy company committed to delivering value for shareholders through a disciplined growth through acquisition strategy and consistent return of capital. Our portfolio of low-decline, cash-flow oriented assets comprises

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both mid-cycle unconventional and conventional assets with a long reserve life and deep inventory of low-risk, high-return development locations in the Eagle Ford and Uinta basins.

Our leadership is an experienced team of investment, financial and industry professionals that combines proven investment and operating expertise. For more than a decade, Crescent and its predecessors have executed on a consistent growth through acquisition strategy focused on cash flow, risk management and returns. Our Class A Common Stock trades on the NYSE under the symbol “CRGY.”

Geopolitical developments and economic environment

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility, impacted by the COVID-19 pandemic and recovery, Russia’s invasion of Ukraine and the related sanctions imposed on Russia, Hamas' attack against Israel and the ensuing conflict in the Middle East, supply chain constraints and rising interest rates and costs of capital. Furthermore, the United States experienced a significant inflationary environment in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession that has caused oil and gas prices to retreat from their earlier highs in 2022 and has created further volatility. In 2023, OPEC announced production cuts to reduce the global oil supply. The actions of OPEC with respect to oil production levels and announcements of potential changes in such levels, including agreement on and compliance with production cuts, may result in further volatility in commodity prices and the oil and natural gas industry generally. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

In 2023, market concern regarding the health of the global banking sector, in which two U.S. bank failures occurred and large national and international banks experienced significant declines in market value, and any resultant recessionary effects contributed, among other factors, to a significant decline in the price for oil and natural gas, with the posted price for WTI reaching a low of $66.61 in March 2023, a level not seen since December 2021. Uncertainty regarding the going concern of certain banks, including the inability of banking and other financial services firms to access liquidity, resulted in significant disruptions to global markets, lower commodity prices and volatility thereof and negatively impacted our financial condition.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022 and into 2023. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See "Part I., Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our operations—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

In August 2022, the IRA 2022 was signed into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes a federal fee on the emission of greenhouse gases through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge is expected to be collected in 2025 based on calendar year 2024 emissions and the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See "Part I., Item 1A. Risk Factors" for additional information. Finally, the IRA 2022 includes a new corporate alternative minimum tax of 15% on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period. We do not believe that the corporate alternative minimum tax will have a material impact on our near-term taxes.

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Equity transactions

2023 Class A Conversions

During 2023, an affiliate of KKR redeemed approximately 30.6 million OpCo Units in the aggregate (and we cancelled a corresponding number of shares of Class B Common Stock) for an equivalent number of shares of Class A Common Stock (the "2023 Class A Conversions"). Approximately 27.6 million of those shares of Class A Common Stock were distributed to certain of its legacy investors in privately-managed funds and accounts. The remaining 3.0 million shares of Class A Common Stock were sold at a price per share of $10.90, pursuant to Rule 144, through a broker-dealer. We did not receive any proceeds or incur any material expenses associated with the Class A Conversions.

September 2023 Underwritten Public Offering

In September 2023, we conducted an underwritten public offering of 12.7 million shares of Class A Common Stock at a price to the public of $12.25 per share (not including underwriter discounts and commissions). This included 1.7 million shares of Class A Common Stock that were issued upon the underwriters exercise of their 30-day option to purchase additional shares to cover over-allotments pursuant to the related underwriting agreement. We received net proceeds of $145.7 million from the Equity Issuance, after deducting underwriting fees and expenses.

2023 Senior Notes Offerings

On February 1, 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "Original 2028 Notes") at par. In July 2023, we issued an additional $300.0 million aggregate principal amount of 9.250% senior notes due 2028 at 98.000% of par (the "July 2028 Notes"); in September 2023, we issued an additional $150.0 million aggregate principal amount of 9.250% senior notes due 2028 at 101.125% of par (the "September 2028 Notes"); and in December 2023, we issued an additional $150.0 million aggregate principal amount of 9.250% senior notes due 2028 at 102.125% of par (the "December 2028 Notes," and together with the Original 2028 Notes, the July 2028 Notes and the September 2028 Notes, the "2028 Notes"). These four issuances of the 2028 Notes are treated as a single series of securities under the indenture governing the Original 2028 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price. The 2028 Notes interest is payable on February 15 and August 15 of each year and mature on February 15, 2028.

Acquisitions, divestitures and related reorganization

Acquisitions and related reorganization

In October 2023, we consummated the unrelated acquisition contemplated by the Purchase and Sale Agreement, dated as of August 22, 2023, between our subsidiary and an unaffiliated third party, pursuant to which we agreed to acquire certain incremental working interests in oil and natural gas properties (the "October Western Eagle Ford Acquisition," and together with the July Western Eagle Ford Acquisition, the "Western Eagle Ford Acquisitions") in certain of our existing Western Eagle Ford assets from the seller for aggregate cash consideration of approximately $235.1 million, including certain customary purchase price adjustments.

In July 2023, we consummated the acquisition contemplated by the Purchase and Sale Agreement, dated as of May 2, 2023, between our subsidiary and Comanche Holdings, LLC ("Comanche Holdings") and SN EF Maverick, LLC ("SN EF Maverick," and together with Comanche Holdings, the "Seller"), pursuant to which we agreed to acquire operatorship and incremental working interests (the "July Western Eagle Ford Acquisition") in certain of our existing Western Eagle Ford assets from the Seller for aggregate cash consideration of approximately $592.7 million, including capitalized transaction costs and certain final purchase price adjustments.

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the “Purchase Agreement” and the transactions contemplated therein, the “Uinta Transaction”) between certain of our subsidiaries, including OpCo, and Verdun Oil Company II LLC, a Delaware limited liability company, pursuant to which we purchased all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a Texas limited liability company that holds all development and production assets of, and certain obligations formerly held by EP Energy E&P Company, L.P. located in the State of Utah. Upon closing of the Uinta Transaction, we paid $621.3 million in cash consideration and

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transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility (as defined below).

Subsequent to the closing of the Uinta Transaction, we settled certain acquired oil commodity derivative positions and entered into new commodity derivative contracts for 2022 with a swap price of $75 per barrel for a net cost of $54.1 million, including restructuring fees, during the three months ended March 31, 2022.

Divestitures

In November 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. We closed the divestiture in December 2022 and recorded a loss of $0.9 million during the year ended December 31, 2022.

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro"), entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the year ended December 31, 2022, we received a distribution of $6.8 million primarily as a result of the sale.

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC ("Chama") in exchange for a 9.4% interest in Chama, which interest was valued at $3.8 million. As a result, we derecognized the assets and liabilities that were contributed to Chama from our consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to the producing assets we contributed to Chama.

Sustainability

We seek to strategically improve assets we own and acquire to deliver enhanced financial returns, operations and stewardship. We believe that being a responsible operator will produce better outcome, creating a net benefit for society and the environment, while delivering attractive returns for our investors. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate.

We are members of the Oil & Gas Methane Partnership 2.0 Initiative, or OGMP 2.0, and received Gold Standard pathway ratings in 2022 and 2023 for our credible plan to more accurately measure our methane emissions. OGMP 2.0 is the United Nations Environment Programme's flagship oil and gas reporting and mitigation program and the leading industry standard for methane emissions reporting. We also established a Sustainability Advisory Council, an outside council comprising leading exports across key sustainability topics, to advise management and our Board of Directors on sustainability-related issues. In November 2023, we released our third Sustainability Report which is available on Crescent’s website at https://www.crescentenergyco.com/#sustainability. However, please note that the contents of this Sustainability Report, and other materials on our website, are not incorporated into this Annual Report by reference.

How we evaluate our operations

We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:

•Production volumes sold;

•Commodity prices and differentials;

•Operating expenses;

•Adjusted EBITDAX (non-GAAP); and

•Levered Free Cash Flow (non-GAAP)

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Development program and capital budget

Our development program is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.

We expect to incur approximately $550 - $625 million, excluding acquisitions, for our 2024 capital program. The majority of our program is allocated to D&C, which approximately 90% is allocated to our operated assets primarily in the Eagle Ford and Uinta basins. We expect to fund our 2024 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Sources of revenues

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Pricing of commodities are subject to supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 4% or less of our total revenues for each of the years ended December 31, 2023, 2022 and 2021.

Production volumes sold

The following table presents historical sales volumes for our properties:

Total sales volume increased 4,146 MBoe during the year ended December 31, 2023 compared to 2022. The increase is primarily due to our Western Eagle Ford Acquisitions and our Uinta Transaction.

Commodity prices and differentials

Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations, impacted by the COVID-19 pandemic and recovery, Russia’s invasion of Ukraine and the associated sanctions imposed on Russia, the Israel-Hamas conflict, actions taken by OPEC, inflation and increased U.S.

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drilling activity. Uncertainty persists regarding OPEC’s actions, increased U.S. drilling, inflation and the armed conflicts in Ukraine and Israel. Additionally, natural gas prices have declined in 2023 due in part to relatively mild winter and extended downtime at a liquified natural gas export facility, which has caused high levels of U.S. gas storage compared with historical averages. Finally, growing market concern regarding the health of the global banking sector and any resultant recessionary effects have contributed, among other factors, to a significant decline in the price for oil and natural gas in 2023 as compared to the prior period.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:

The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:

(1)For the years ended December 31, 2023 and 2022, the realized price excludes $61.5 million and $49.9 million impact from the settlement of acquired derivative contracts, respectively. For the year ended December 31, 2021, the realized price excludes the impact of the settlement of certain of our outstanding derivative oil commodity contracts associated with calendar years 2022 and 2023 for $198.7 million in June 2021.

Results of operations:

Year ended December 31, 2023 compared to year ended December 31, 2022

Revenues

The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:

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Oil revenue. Oil revenue decreased $218.1 million, or 11%, in 2023 compared to 2022. This decrease was driven by lower realized oil prices that resulted in a decrease of $436.2 million (a decline of 20% per Bbl) and partially offset by a $218.1 million increase from higher sales volumes (7 MBbl/d, or 12%). The increase in sales volumes was primarily driven by our Western Eagle Ford Acquisitions and our Uinta Transaction.

Natural gas revenue. Natural gas revenue decreased $395.9 million, or 52%, in 2023 compared to 2022. This decrease was driven by lower realized natural gas prices that resulted in a decrease of $408.8 million (a decline of 52% per Mcf) and a $12.9 million increase from higher sales volumes (6 MMcf/d, or 2%). The increase in sales volumes was primarily due to our Western Eagle Ford Acquisitions and our Uinta Transaction but these increases were partially offset by natural decline and downtime at a natural gas processing plant in 2023.

NGL revenue. NGL revenue decreased $75.3 million, or 28%, in 2023 compared to 2022. This decrease was driven by lower realized NGL prices that resulted in a decrease of $126.8 million (a decline of 40% per Bbl) and a $51.5 million increase from higher sales volumes (4 MBbl/d, or 21%). The increase in sales volumes was primarily driven by our Western Eagle Ford Acquisitions.

Midstream and other revenue. Midstream and other revenue increased $14.9 million, or 28%, in 2023 compared to 2022, due to additional oil blending revenue in 2023.

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Expenses

The following table summarizes our expenses for the periods indicated and includes a presentation on a per Boe basis, as we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis:

*NM = Not meaningful.

Operating expense. Total operating expense increased $65.0 million, or 6%, in 2023 compared to 2022, driven primarily by the following factors:

(i)Lease and asset operating expenses increased $64.5 million, or 12%, in 2023 compared to 2022. Additionally, lease and asset operating expense per Boe increased $0.40 per Boe from $10.27 per Boe to $10.67 per Boe. This $64.5 million increase was driven primarily by (i) higher production from our Western Eagle Ford Acquisitions and our Uinta Transaction and (ii) higher-cost residue gas purchases related to increased natural gas prices in the west coast pricing market. Higher cost residue gas was more than offset by higher realized pricing.

(ii)Gathering, transportation and marketing expense increased $58.1 million, or 33%, in 2023 compared to 2022. Additionally, gathering, transportation and marketing expense per Boe increased $0.80 per Boe from $3.51 per Boe to $4.31 per Boe. This increase was driven primarily by our Western Eagle Ford Acquisitions and our Uinta Transaction.

(iii)Production and other taxes decreased $75.4 million, or 32%, in 2023 compared to 2022 and decreased $1.74 per Boe, or 37%, to $2.99 per Boe. This decrease was driven primarily by lower oil and natural gas revenues, which decreased the tax base upon which our production and other taxes are calculated.

(iv)Workover expense decreased $8.4 million in 2023 compared to 2022, and decreased $0.26 per Boe from $1.33 per Boe to $1.07 per Boe. This decrease was primarily caused by lower commodity price related activity.

(v)Midstream operating expense increased $26.3 million, or 195%, in 2023 compared to 2022, primarily due to increased crude oil blending expense. The additional crude oil blending expense is more than offset by additional oil blending revenue included as part of our Midstream and other revenue.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased $142.9 million, or 27%, in 2023 compared to 2022, driven primarily by increased production from our Western Eagle Ford Acquisitions and Uinta Transaction and increased production from new well completions.

Impairment expense. During the years ended December 31, 2023 and 2022, we evaluated our Oil and natural gas properties, Goodwill and Investments in equity affiliates and determined that certain amounts were impaired. As a result of our evaluations, we recorded impairment charges totaling $153.5 million in 2023, including $149.6 million related to Oil and natural gas properties and $3.9 million related to Investments in equity affiliates, and $142.9 million in 2022, including $77.7 million related to Goodwill and $65.2 million related to Oil and natural gas properties.

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General and administrative expense. General and administrative expense ("G&A") increased $55.9 million, or 66%, in 2023 compared to 2022, driven primarily by (i) an increase in non-cash equity-based compensation expense of $44.9 million (includes additional catch up expense of $30.4 million due to change in estimate) and (ii) higher expense payable under the Management Agreement with KKR Energy Assets Manager LLC, which is the pro-rata portion of the Manager Compensation borne by us. The increase in Manager Compensation and our non-cash equity-based compensation expense is due to an increase in public ownership of Class A Common Stock as a result of (i) our Equity Issuance, which also increased the annual Manager Compensation by $2.2 million to $55.5 million annually, and (ii) share redemptions for our Class A Common Stock completed in the second and fourth quarters of 2023 and the second half of 2022, which did not increase the overall Manager Compensation, but does increase the portion of the Manager Compensation borne by us. While only the portion of the Manager Compensation borne by us impacts our consolidated statements of operations, we include the full Manager Compensation in the calculation of Adjusted EBITDAX and Levered Free Cash Flow (the difference between the Manager Compensation and the amount presented in G&A is represented by “Certain-redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation”). These increases were partially offset by $2.0 million in lower transaction and nonrecurring expenses.

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs increased by $10.5 million compared to 2022, primary driven by a $4.6 million lower gain on sale of assets recognized in 2023, and $5.9 million in higher exploration expenses.

Interest expense. In 2023, we incurred interest expense of $145.8 million, as compared to $95.9 million in 2022, a 52% increase. The increase was primarily driven by higher average debt balances driven by the Western Eagle Ford Acquisitions and higher interest rates associated with the issuance of the 2028 Notes and our Revolving Credit Facility.

Gain (loss) on derivatives

We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and interest rate risks on our variable interest rate debt. The following table presents our total unrealized and realized gain (loss) on derivatives for the periods presented:

Our gain on commodity derivatives during 2023, changed by $843.9 million, or 125%, from a loss during 2022 primarily due to changes in commodity prices relative to our strike price.

Income from equity affiliates

Our income from equity method investments was $0.4 million in 2023 and $4.6 million in 2022. The decrease was primarily due to a gain on sale of substantially all of the oil and gas assets held by Exaro in 2022.

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Income tax benefit (expense)

For the years ended December 31, 2023 and 2022 we recognized income tax expense of $23.2 million and $36.3 million, respectively, for an effective tax rate of 6.7% and 7.0%, respectively. Our effective tax rate is lower than the U.S. federal statutory income tax rate of 21% primarily due to effects of removing income and losses related to our noncontrolling interests and redeemable noncontrolling interests. Our effective tax rate decreased in 2023 due to additional permanent items and an increased valuation allowance in 2022 offset by the increase to our ownership of OpCo in 2023.

Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)

Adjusted EBITDAX and Levered Free Cash Flow are supplemental non-GAAP financial measures used by our management to assess our operating results and liquidity. See “—Non-GAAP financial measures” section below for their definitions and application.

The following tables present reconciliations of Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP) to net income (loss), and Levered Free Cash Flow (non-GAAP) to Net cash provided by operating activities, the most directly comparable financial measures calculated in accordance with GAAP:

(1)Transaction and nonrecurring expenses of $22.6 million during the year ended December 31, 2023 were primarily related to the Western Eagle Ford Acquisitions and the Merger Transactions. Transaction and nonrecurring expenses of $34.1 million for the year ended December 31, 2022 were primarily related to (i) legal, consulting, transition service agreement costs, related restructuring of acquired derivative contracts and other fees incurred for the Uinta Transaction and Merger Transactions, (ii) severance costs subsequent to the Merger Transactions, (iii) merger integration costs and (iv) acquisition and debt transaction related costs.

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Adjusted EBITDAX decreased by $144.5 million or 12% in 2023, compared to 2022, driven primarily by lower realized prices, partially offset by additional production and Adjusted EBITDAX generated by the Western Eagle Ford Acquisitions and the Uinta Transaction.

Levered Free Cash Flow decreased by $123.8 million or 29% in 2023 compared to 2022, driven primarily by decreased Adjusted EBITDAX of $144.5 million, partially offset by $46.6 million of decreased capital expenditures. Our reinvestment rate was 65% in 2023 compared to a reinvestment rate of 59% during 2022.

Liquidity and capital resources

Our primary sources of liquidity are cash flow from operations, proceeds from equity and debt offerings and borrowings under a senior secured reserve-based revolving credit agreement (as amended, restated, amended and restated or otherwise modified to date, the “Revolving Credit Facility") with Wells Fargo Bank, N.A., as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. Our primary expected uses of capital are for dividends to shareholders, our share repurchase program, debt repayment, development of our existing assets and acquisitions.

Our development program is designed to prioritize the generation of meaningful free cash flow and attractive risk-adjusted returns, and is inherently flexible, with the ability to scale our capital program as necessary to react to the existing market environment and ongoing asset performance. See “—Development program and capital budget” above for additional discussion of our capital program.

We plan to continue our practice of entering into economic hedging arrangements to reduce the impact of the near-term volatility of commodity prices and the resulting impact on our cash flow from operations. A key tenet of our focused risk management effort is an active economic hedge strategy to mitigate near-term price volatility while maintaining long-term exposure to underlying commodity prices. Our commodity derivative program focuses on entering into forward commodity contracts when investment decisions regarding reinvestment in existing assets or new acquisitions are finalized, targeting economic hedges for a portion of expected production generated by the capital investment as well as adding incremental derivatives to our production base over time. Our active derivative program allows us to protect margins and corporate returns through commodity cycles. For information regarding risks related to our derivative program, see "Part I., Item 1A. Risk Factors".

The following table presents our cash balances and outstanding borrowings at the end of each period presented:

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Based on our planned capital spending, our forecasted cash flows and projected levels of indebtedness, we expect to maintain compliance with the covenants under our debt agreements. Further, based on current market indications, we expect to meet in the ordinary course of business other contractual cash commitments to third parties pursuant to the various agreements subsequently described under the heading “Contractual obligations,” recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Cash flows

The following table summarizes our cash flows for the periods indicated:

Net cash provided by operating activities. Net cash provided by operating activities for the year ended December 31, 2023 decreased by $76.6 million, or 8%, compared to 2022, primarily due to lower realized pricing partially offset by working capital changes. In addition, net cash provided by operating activity for the year ended December 31, 2022, was impacted by a $52.0 million restructuring of certain oil commodity derivative contracts acquired in connection with the Uinta Transaction.

Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2023 increased by $274.5 million, or 24%, compared to 2022. Our Acquisitions of oil and gas properties of $849.3 million in 2023 was driven primarily by our Western Eagle Ford Acquisitions while the 2022 acquisitions of $626.6 million was driven by the Uinta Transaction. Our cash expenditures related to the Development of oil and natural gas properties decreased by $11.4 million, and we had $64.3 million lower proceeds from the sale of oil and natural gas properties.

Net cash provided by financing activities. Net cash provided by financing activities for the year ended December 31, 2023 was $456.5 million, an increase of $464.3 million, driven by additional debt borrowings in 2023 of $233.4 million, $145.7 million from our Equity Issuance and $53.5 million higher cash outflow in 2022 related to redeemable NCI repurchases and tax distributions.

Debt agreements

Senior Notes

On February 1, 2023, we issued $400.0 million aggregate principal amount of the Original 2028 Notes at par. In July 2023 we issued an additional $300.0 million aggregate principal amount of the July 2028 Notes at 98.000% of par, in September 2023 we issued an additional $150.0 million aggregate principal amount of the September 2028 Notes at 101.125% of par, and in December 2023 we issued an additional $150.0 million aggregate principal amount of the December 2028 Notes at 102.125% of par. These four issuances of the 2028 Notes are treated as a single series of securities under the indenture governing the Original 2028 Notes, will vote together as a single class, and have substantially identical terms, other than the issue date and the issue price. The 2028 Notes interest is payable on February 15 and August 15 of each year and mature on February 15, 2028.

We may, at our option, redeem all or a portion of the 2028 Notes at any time on or after February 15, 2025 at certain redemption prices. We may also redeem up to 40% of the aggregate principal amount of the 2028 Notes before February 15, 2025 with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 109.250% of the principal amount of the 2028 Notes being redeemed, plus accrued and unpaid interest, if any, to, but excluding the redemption date. In addition, prior to February 15, 2025, we may redeem some or all of the 2028 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but excluding the redemption date.

On May 6, 2021, we issued $500.0 million aggregate principal amount of senior notes due 2026 at par (the "Original 2026 Notes"). In February 2022, we issued an additional $200.0 million aggregate principal amount of our senior notes due 2026 at 101% of par (the "Additional 2026 Notes" and, together with the Original 2026 Notes, the "2026 Notes"). Both issuances of the 2026 Notes are treated as a single series and vote together as a single class, and have identical terms and conditions, other than the issue date, the issue price and the first interest payment. The 2026 Notes bear interest at an annual rate of 7.250%, which is payable on May 1 and November 1 of each year and mature on May 1, 2026.

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We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after May 1, 2023 at certain redemption prices.

The Senior Notes are our senior unsecured obligations and the Senior Notes and the related guarantees rank equally in right of payment with the borrowings under the Revolving Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Senior Notes are guaranteed on a senior unsecured basis by each of our existing and future subsidiaries that will guarantee the Revolving Credit Facility. The Senior Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the Revolving Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Senior Notes.

The indentures governing the Senior Notes contain covenants that, among other things, limit the ability of our restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends or distributions in respect of its equity or redeem, repurchase or retire its equity or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from any non-Guarantor restricted subsidiary to it; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.

If we experience certain kinds of changes of control accompanied by a ratings decline, holders of the Senior Notes may require us to repurchase all or a portion of their notes at certain redemption prices. The Senior Notes are not listed, and we do not intend to list the Senior Notes in the future, on any securities exchange, and currently there is no public market for the Senior Notes.

Revolving Credit Facility

In connection with the issuance of the 2026 Notes in May 2021, Crescent Finance entered into the Revolving Credit Facility. The Revolving Credit Facility matures on September 23, 2027. At December 31, 2023, we had $23.5 million of outstanding borrowings under the Revolving Credit Facility and $14.4 million in outstanding letters of credit, our elected commitment amount was $1.3 billion, and we had $1,262.1 million of available borrowings.

Borrowings under the Revolving Credit Facility bear interest at either a (i) U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted secured overnight financing rate ("SOFR"), plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of the borrowers. The applicable margin varies based upon our borrowing base utilization then in effect. The fee payable for the unused revolving commitments is 0.50% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2023 and 2022 was 9.75% and 6.98%, respectively.

The borrowing base under the Revolving Credit Facility was $2.0 billion as of December 31, 2023. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1 and October 1 of each year, as well as (i) elective borrowing base interim redeterminations at our request not more than twice during any consecutive 12-month period or the required lenders not more than once during any consecutive 12-month period and (ii) elective borrowing base interim redeterminations at our request following any acquisition of oil and natural gas properties with a purchase price in the aggregate of at least 5.0% of the then effective borrowing base. The borrowing base will be automatically reduced upon (a) the issuance of certain permitted junior lien debt and other permitted additional debt, (b) the sale or other disposition of borrowing base properties if the aggregate net present value, discounted at 9% per annum (“PV-9”) of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (c) early termination or set-off of swap agreements (x) the administrative agent relied on in determining the borrowing base or (y) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.

The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of our and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by us and such guarantors. In connection with each redetermination of the borrowing base, we must maintain mortgages on at least 85% of the PV-9 of the oil and gas properties that constitute borrowing base properties. Our domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.

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The Revolving Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the adherence to certain financial covenants or the prior consent of our lenders. We are subject to (i) maximum leverage ratio and (ii) current ratio financial covenants calculated as of the last day of each fiscal quarter. The Revolving Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default, the lenders will be able to accelerate maturity and exercise other rights and remedies. We expect to remain in compliance with these covenants for the foreseeable future.

Capital expenditures

Our acquisition and development expenditures consist of acquisitions of proved and unproved property, expenditures associated with the development of our oil and natural gas properties and other asset additions. Cash expenditures for drilling, completion and recompletion activities are presented as "development of oil and natural gas properties" in investing activities on our combined and consolidated statements of cash flows.

We expect to fund our 2024 capital program, excluding acquisitions through cash flow from operations. The amount and timing of capital expenditures on development of oil and natural gas properties is substantially within our control due to the held-by-production nature of our assets. We regularly review our capital expenditures throughout the year and could choose to adjust our investments based on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related Standardized Measure. These risks could materially affect our business, financial condition and results of operations.

The table below presents our capital expenditures and related metrics that we use to evaluate our business for the periods presented:

The decrease in our development of oil and natural gas properties costs in 2023 is primarily related to the timing of our operations. We used cash of $849.3 million in 2023 for the acquisitions of oil and natural gas properties, primarily related to Western Eagle Ford Acquisitions, as compared to $626.6 million in 2022, primarily related to the Uinta Transaction. See “Notes to Combined and Consolidated Financial Statements—NOTE 3 - Acquisitions and Divestitures in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.

Contractual obligations

The following table presents our material contractual obligations at December 31, 2023:

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(1)Long-term debt represents our outstanding borrowings as of December 31, 2023 consisting of our Senior Notes; maturing on May 1, 2026 and February 15, 2028) and borrowings under our Revolving Credit Facility (maturing on September 23, 2027).

(2)Excludes variable rate debt interest payments and commitment fees related to the Company's Revolving Credit Facility.

(3)Amounts represent estimated discounted costs for future dismantlement and abandonment of our oil and natural gas properties. See "Notes to Combined and Consolidated Financial Statements—NOTE 9 - Asset Retirement Obligation" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for additional discussion of our asset retirement obligations.

(4)Amounts include payments which will become due under long-term agreements to purchase goods and services used in the normal course of business to secure transportation of our oil and natural gas production to market, as well as, pipeline, processing and storage capacity.

General and Administrative Expense

Our general and administrative expense includes corporate overhead costs, professional service fees, insurance, software applications, fees for transaction expenses, expenses payable under the Management Agreement with KKR Energy Assets Manager LLC, incentive compensation award agreements granting profits interests, restricted stock units, performance stock units and other incentive awards granted to our employees and non-employee directors.

The incentive compensation portion relates to certain equity-classified and liability-classified profits interests awards issued by our subsidiaries (collectively, “Profits Awards”). These Profits Awards contain different vesting conditions ranging from performance-based conditions that vest upon the achievement of certain return thresholds to time-based service requirements ranging from one year to four years. Compensation cost for these awards is presented within General and administrative expense on our combined and consolidated statements of operations. As of December 31, 2023, (i) unrecognized compensation cost related to unvested equity-classified profits interest awards was $63.1 million, and (ii) we carried $5.8 million in Other long term liabilities on the consolidated balance sheet and had unrecognized compensation of $3.8 million related to unvested liability-classified profits interest awards. Actual amounts paid towards equity-classified profits interests awards in the future will be shown as distributions to non-controlling interests in our consolidated financial statements, and may differ from the amounts shown for unrecognized compensation cost related to unvested equity-classified profits interest awards.

For additional information, see "Notes to Combined and Consolidated Financial Statements—NOTE 13 – Equity-Based Compensation Awards" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report

Dividends

Our future dividends depend on our level of earnings, financial requirements and other factors and will be subject to approval by our Board of Directors, applicable law and the terms of our existing debt documents, including the indentures governing the Senior Notes.

We paid cash dividends of $0.53 per share of our Class A Common Stock to shareholders during the year ended December 31, 2023.

On March 4, 2024, the Board of Directors approved a quarterly cash dividend of $0.12 per share, or $0.48 per share on an annualized basis, to be paid to shareholders of our Class A Common Stock with respect to the fourth quarter of 2023. The quarterly dividend is payable on March 28, 2024 to shareholders of record as of the close of business on March 15, 2024. OpCo unitholders will also receive a distribution based on their pro rata ownership of OpCo Units.

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The payment of quarterly cash dividends is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and approval by our Board of Directors. In light of current economic conditions, management will evaluate any future increases in cash dividend on a quarterly basis.

Stock Repurchase Program

Our Board of Directors authorized a stock repurchase program on March 4, 2024 with an approved limit of $150.0 million and a two-year term. Repurchases may be of our Class A Common Stock or of OpCo Units (with the cancellation of a corresponding number of shares of our Class B Common Stock). Such repurchase may be made by Crescent or by OpCo, as applicable, and may be made from time to time in the open market, in a privately negotiated transaction, through purchases made in accordance with the Rule 10b5-1 of the Exchange Act or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate us to repurchase any dollar amount or number of shares.

The IRA 2022 provides for, among other things, the imposition of a 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations, such as Crescent, after December 31, 2022. Accordingly, this excise tax will apply to our stock repurchase program. The Biden Administration has proposed increasing the amount of the excise tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect.

Critical accounting estimates

Our significant accounting policies are described in "Notes to Combined and Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report. The Company's combined and consolidated financial statements are prepared in accordance with GAAP. The preparation of combined and consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following is a discussion of the accounting policies, estimates and judgments that management believes are most significant in the application of GAAP used in the preparation of our combined and consolidated financial statements. These accounting policies, among others, may involve a high degree of complexity and judgment on the part of management. Further, these estimates and other factors, including those outside of our control could have significant adverse impact to our financial condition, results of operations and cash flows.

Crude oil, natural gas and NGL reserves

One of the most significant estimates the Company makes is the estimate of proved crude oil, natural gas and NGL reserves. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. Our crude oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Technologies used in our reserves estimation includes decline curve analysis, statistical analysis of production performance, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. In addition, periodic revisions of our estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, crude oil and natural gas prices, changes in costs, capital funding and drilling plans (including our five-year development plan), technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions.

When determining the December 31, 2023 proved reserves for each property, the benchmark prices issued by the SEC were adjusted using price differentials that account for property-specific quality and location differences. If the future average crude oil prices are below the average prices used to determine proved reserves at December 31, 2023, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of proved reserves, see "Part I., Item 1A. Risk Factors."

Estimates of proved reserves are key components of our most significant financial estimates including the computation of depreciation, depletion and amortization ("DD&A") and impairment of proved oil and natural gas properties.

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Oil and natural gas properties

Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. See "Notes to Combined and Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for further discussion of the accounting policies applicable to the successful efforts method of accounting.

The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties used for testing impairment, also in part, rely on estimates of quantities of net reserves.

Depreciation, depletion and amortization

DD&A of oil and natural gas producing properties is determined on a field-by-field basis using the units-of-production method. During the years ended December 31, 2023, 2022, and 2021, we recognized DD&A expense of $675.8 million, $532.9 million, and $312.8 million, respectively.

While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates, any reduction in proved reserves, could result in an acceleration of future DD&A expense. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. However, a sensitivity analysis is not practicable, given the numerous assumptions required to calculate proved reserves. In addition, any unfavorable adjustments to some of the above listed assumptions (e.g. commodity prices) would likely be offset by favorable adjustments in other assumptions (e.g. lower costs) as we have historically seen in our industry.

Impairment of oil and natural gas properties

Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. When a triggering event is identified, we compare the carrying amount of our oil and natural gas properties to the estimated undiscounted cash flows our oil and natural gas properties will generate to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted cash flows, we will write-down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include:

•Estimates of oil and natural gas reserves and expected timing of production. Our oil and natural gas reserves are based on a combination of proved reserves and risk-weighted probable reserves and require significant judgment. Reserve engineering is a subjective process, which requires assumptions associated with the underground accumulations of oil and natural gas, development costs, future commodity prices and the future regulatory and political environment. Any significant variance in these assumptions could materially affect the estimated quantity and value of the reserves, which would affect the fair value of our oil and natural gas properties. The estimates of our reserves help to inform our expectation of future oil and natural gas production, which will likely vary from our actual production.

•Future commodity prices, which are based on publicly available forward commodity prices for a period of time and then escalated thereafter. A decrease in estimated future commodity prices will decrease the fair value of our oil and natural gas properties.

•Future capital requirements, which are based on our internal forecasts and supported by the underlying cash flows generated from our oil and natural gas assets.

•Discount rate commensurate with the risk associated with realizing projected cash flows, which is based on a variety of factors, including market and economic conditions, as well as operational and regulatory risk.

During the years ended December 31, 2023 and 2022, we determined that there were triggering events requiring an evaluation of whether the carrying value of our oil and natural gas properties was recoverable. Following an assessment of our oil and natural gas properties, during the years ended December 31, 2023 and 2022, we recorded impairment expense of $149.6 million and $65.2 million, respectively. We did not incur any impairment expense during the year ended December 31, 2021. As of December 31, 2023, the carrying value of certain of our conventional assets in Wyoming in proved oil and natural gas properties was $214.5 million. At the current forward commodity price curve, these assets have limited cushion between their carrying value and estimated undiscounted cash flows. A further decline of future commodity prices or a decrease in estimates

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of oil and natural gas reserves for these assets would likely result in an impairment charge. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, weighted-average cost of capital, operating cost estimates and future capital expenditures estimates. An estimate of the sensitivity to changes in assumptions in our fair value calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices would likely be partially offset by lower costs.

Properties acquired in business combinations

When sufficient market data is not available, we determine the fair values of proved and unproved oil and natural gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values.

Significant reductions in the proved reserves used to determine the fair value of the acquired properties could result in future impairments of the properties. See the discussion above under "Depreciation, depletion and amortization: on the practicability of a sensitivity analysis due to changes in our fair value calculations.

Income taxes

Prior to the Merger Transactions, we were organized as Delaware limited liability companies and Delaware limited partnerships and were treated as flow-through entities for U.S. federal income tax purposes. As a result, our tax provision for the year ended December 31, 2021 was minimal. Subsequent to the Merger Transactions, we are subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo. The amount of income taxes recorded by the Company requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. We routinely assess potential uncertain tax positions and, if required, establish accruals for such amounts. The accruals for deferred tax assets and liabilities, including deferred state income tax assets and liabilities, are subject to significant judgment and are reviewed and adjusted routinely based on changes in facts and circumstances. Although we consider our tax accruals adequate, material changes in these accruals may occur in the future, based on the impact of tax audits, changes in legislation and resolution of pending or future tax matters. Refer to "Notes to Combined and Consolidated Financial Statements—NOTE 11 – Income Taxes" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for more information.

New and revised accounting standards

See “Notes to Combined and Consolidated Financial Statements—NOTE 2 – Summary of Significant Accounting Policies” in Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report.

Non-GAAP financial measures

Our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes financial and liquidity measures that have not been calculated in accordance with U.S. GAAP. These non-GAAP measures include the following:

•Adjusted EBITDAX; and

•Levered Free Cash Flow.

These are supplemental non-GAAP financial and liquidity measures used by our management to assess our operating results and assist us make our investment decisions. We believe that the presentation of these non-GAAP measures provides investors with greater transparency with respect to our results of operations, as well as liquidity and capital resources, and that these measures are useful for period-to-period comparison of results.

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We define Adjusted EBITDAX as net income (loss) before interest expense, income tax expense (benefit), depreciation, depletion and amortization, exploration expense, non-cash gain (loss) on derivatives, impairment expense, non-cash equity-based compensation, (gain) loss on sale of assets, other (income) expense and transaction and nonrecurring expenses. Additionally, we further subtract certain redeemable noncontrolling interest distributions made by OpCo related to Manager Compensation and settlement of acquired derivative contracts.

Adjusted EBITDAX is not a measure of performance as determined by GAAP. We believe Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of our operating performance when compared against our peers, without regard to our financing methods, corporate form or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be identical to other similarly titled measures of other companies. In addition, the Revolving Credit Facility and Senior Notes include a calculation of Adjusted EBITDAX for purposes of covenant compliance.

We define Levered Free Cash Flow as Adjusted EBITDAX less interest expense, excluding non-cash deferred financing cost amortization, current income tax benefit (expense), tax-related redeemable noncontrolling interest distributions made by OpCo and development of oil and natural gas properties. Levered Free Cash Flow does not take into account amounts incurred on acquisitions.

Levered Free Cash Flow is not a measure of liquidity as determined by GAAP. Levered Free Cash Flow is a supplemental non-GAAP liquidity measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Levered Free Cash Flow is a useful liquidity measure because it allows for an effective evaluation of our operating and financial performance and the ability of our operations to generate cash flow that is available to reduce leverage or distribute to our equity holders. Levered Free Cash Flow should not be considered as an alternative to, or more meaningful than, Net cash flow provided by operating activities as determined in accordance with GAAP, of which such measure is the most comparable GAAP measure, or as an indicator of actual liquidity, operating performance or investing activities. Our computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies.

Adjusted EBITDAX and Levered Free Cash Flow should be read in conjunction with the information contained in our combined and consolidated financial statements prepared in accordance with GAAP. For a reconciliation of these non-GAAP measures to the nearest comparable GAAP measures, see “—Results of Operations—Adjusted EBITDAX (non-GAAP) and Levered Free Cash Flow (non-GAAP)” above.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations is intended to provide the reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Company's operating results. The following discussion and analysis should be read in conjunction with the Combined and Consolidated Financial Statements and related Notes included in "Item 8. Financial Statements and Supplementary Data" of this Annual Report and also with "Part I., Item 1A. Risk Factors" of this Annual Report. The following information updates the discussion of our financial condition provided in our previous filings, and analyzes the changes in the results of operations between the years ended December 31, 2022 and 2021. Refer to our 2021 Annual Report filed March 10, 2022 for discussion and analysis of the changes in results of operations between the years ended December 31, 2021 and 2020. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward- looking statements. Factors that could cause or contribute to such differences include, but are not limited to, commodity price volatility, capital requirements and uncertainty of obtaining additional funding on terms acceptable to the Company, realized oil, natural gas and NGL prices, the timing and amount of future production of oil, natural gas and NGLs, shortages of equipment, supplies, services and qualified personnel, as well as those factors discussed below and elsewhere in this Annual Report , particularly under “Risk Factors” and “Cautionary Statement Regarding Forward Looking statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Business overview

We are a well-capitalized U.S. independent energy company with a portfolio of assets in key proven regions across the lower 48 states, focused in Texas and the Rockies.

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Our approach employs a unique business model that combines an investor mindset and deep operational expertise to pursue a cash flow-based investment mandate focused on operated working interests with an active risk management strategy. We pursue our strategy through the production, development and acquisition of oil, natural gas and NGL reserves.

Geopolitical developments and economic environment

During the last several years, prices of crude oil, natural gas and NGLs have experienced periodic downturns and sustained volatility. In particular, the global spread of the COVID-19 virus during 2020 and 2021 had a negative impact on the global demand for oil and natural gas and caused significant commodity market volatility. While the increase in domestic vaccination programs and reduced spread of the COVID-19 virus has contributed to an improvement in the economy and higher realized prices for commodities, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

In addition, in February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, have contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of over $120 per barrel in 2022. Such volatility may lead to a more difficult investing and planning environment for us and our customers. While the near-term impact of these events resulted in higher oil and gas prices in 2022, the geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. Furthermore, the United States has experienced a significant inflationary environment in 2022 that, along with international geopolitical risks, has contributed to concerns of a potential recession that has caused oil and gas prices to retreat from their earlier highs in 2022 and has created further volatility.

Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. The U.S. inflation rate has been steadily increasing since 2021. These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including oilfield services, labor costs and equipment if our drilling activity increases. Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher oil and natural gas prices and revenues, would negatively impact our business, financial condition and results of operations. See "Part I., Item 1A. Risk Factors—Risks related to the oil and natural gas industry and our operations—Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise."

In August 2022, IRA 2022 was signed into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for the oil and gas we produce and consequently materially and adversely affect our business and results of operations. In addition, the IRA 2022 imposes a federal fee on the emission of GHGs through a methane emissions charge, including onshore petroleum and natural gas production. The methane emissions charge will start in calendar year 2024 and the fee is based on certain thresholds established in the IRA 2022. The methane emissions charge could increase our operating costs and adversely affect our business and results of operations. See "Part I., Item 1A. Risk Factors" for additional information. Finally, the IRA 2022 includes a new corporate alternative minimum tax of 15% on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period. While we are evaluating the impact of the new corporate alternative minimum tax will have, we do not believe that it will have a material impact on our near-term taxes.

Equity transactions

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In September 2022, Independence Energy Aggregator L.P. ("Aggregator"), the entity through which certain affiliated entities hold their interests in us, exchanged 6.3 million units representing membership interests in OpCo (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock and agreed to sell 5.75 million shares of our Class A Common Stock (the "Offering") at a price to the public of $15.00 per share, or a net price of $14.10 per share after deducting the underwriters' discounts and commissions. We did not receive any cash proceeds from the Offering. Concurrent with the closing of the Offering, we repurchased an aggregate of approximately 2.6 million OpCo Units from PT Independence for $36.2 million and cancelled a corresponding number of shares of our Class B Common Stock (the "Concurrent OpCo Unit Purchase," and, together with the Offering, the "Equity Transactions"). As a result of the Equity Transactions, the total number of shares of our Class A Common Stock increased by 6.3 million shares, including 0.6 million shares of our Class A Common Stock that were not included as part of the Offering but rather issued in exchange for shares of Class B Common Stock and distributed in-kind by Aggregator. to affiliates, and the number of shares of our Class B Common Stock decreased by approximately 8.9 million. After the Equity Transactions, shares of our Class A Common Stock represent approximately 29% of the outstanding shares of Class A Common Stock and Class B Common Stock, taken together, and we own approximately 29% of the outstanding OpCo Units. Redeemable noncontrolling interests decreased by $158.1 million while APIC increased by $121.8 million as a result of the Equity Transactions and to reflect the new ownership of OpCo.

Other transactions

In February 2023, we issued $400.0 million aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes"). The estimated proceeds of the offering were $391.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds to repay a portion of outstanding borrowings under our revolving credit facility.

Acquisitions, divestitures and related reorganization

Acquisitions and related reorganization

In March 2022, we consummated the acquisition contemplated by the Membership Interest Purchase Agreement dated February 15, 2022 (the “Purchase Agreement” and the transactions contemplated therein, the “Uinta Transaction”) between certain of our subsidiaries, including OpCo, and Verdun Oil Company II LLC, a Delaware limited liability company, pursuant to which we purchased all of the issued and outstanding membership interests of Uinta AssetCo, LLC, a Texas limited liability company that holds all development and production assets of, and certain obligations formerly held by EP Energy E&P Company, L.P. located in the State of Utah. Upon closing of the Uinta Transaction, we paid $621.3 million in cash consideration and transaction fees and assumed certain commodity derivatives. The Uinta Transaction was funded with cash on hand and borrowings under our Revolving Credit Facility (as defined below). In connection with the closing of the Uinta Transaction, we entered into an amendment to our Revolving Credit Facility to, among other things, increase the borrowing base to $1.8 billion and the elected commitment amount to $1.3 billion (see NOTE 8 – Debt). We incurred financing costs of $13.4 million associated with this amendment, which are recorded as debt issuance costs within Other assets on the consolidated balance sheets.

Subsequent to the closing of the Uinta Transaction, we settled certain acquired oil commodity derivative positions and entered into new commodity derivative contracts for 2022 with a swap price of $75 per barrel for a net cost of $54.1 million, including restructuring fees, during the three months ended March 31, 2022.

In December 2021, we completed a series of transactions, pursuant to which the business of Contango and the business of Independence combined under a new publicly traded holding company named "Crescent Energy Company." Our Class A common stock, par value $0.0001 per share (“Class A Common Stock") is listed on the NYSE under the symbol “CRGY.” The combined company is structured as an “Up-C,” with all of our assets and operations (including those of Contango) indirectly held by our operating subsidiary, OpCo. Crescent Energy Company is a holding company, the sole material asset of which consists of OpCo Units, and is responsible for all operational, management and administrative decisions related to OpCo’s business. We are the sole managing member of OpCo. Crescent consolidates the financial results of OpCo and its subsidiaries. Former Contango shareholders own shares of Class A Common Stock, which have both voting and economic rights. The former owners of our predecessor, Independence Energy LLC, own economic, non-voting OpCo Units and corresponding shares of Class B common stock, par value $0.0001 per share ("Class B Common Stock," together with Class A Common Stock, the "Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights. OpCo Units may be redeemed or exchanged for Class A Common Stock or, at our election, cash on the terms and conditions set forth in the Amended and Restated Limited Liability Company Agreement of OpCo.

In connection with the Merger Transactions, we underwent a reorganization (the “Crescent Reorganization”), whereby Independence merged with and into OpCo (the “Isla Merger”). The financial statements include the accounts of Independence

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from the date of the Isla Merger, which is the date the Company obtained a controlling financial interest in Independence on a consolidated basis. Because the Isla Merger resulted in a change in the reporting entity, and in order to furnish comparative financial information prior to the Isla Merger, our financial statements have been retrospectively recast to reflect the historical accounts of Independence, our accounting predecessor (the "Predecessor"), on a combined basis.

In December 2021, we also acquired from an unrelated third-party certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico, with additional properties in the southwestern Permian and Powder River Basins, for total cash consideration of $60.4 million, including customary purchase price adjustments (the "Central Basin Platform Acquisition"). The purchase price was funded using cash on hand and borrowings under our Revolving Credit Facility (as defined in NOTE 8 – Debt).

In May 2021, certain of our consolidated subsidiaries redeemed the noncontrolling equity interests held in such subsidiaries by a third-party investor in exchange for the third-party investor’s proportionate share of the underlying oil and natural gas interests held by its consolidated subsidiaries (the "Noncontrolling Interest Carve-out"). Additionally, the third-party investor contributed cash of approximately $35.5 million to repay its proportionate share of the underlying debt outstanding under the revolving credit facilities of certain of our subsidiaries (the "Prior Credit Agreements") and other liabilities. The percentage ownership of these certain consolidated subsidiaries owned by the third-party investor ranges from 2.21% to 7.38%.

In April 2021, certain minority investors exchanged 100% of their interests in our Barnett basin natural gas assets for 9,508 of Class A units of our Predecessor, representing 0.77% of our consolidated ownership pursuant to the April 2021 Exchange. Since we already consolidate the results of these assets, this transaction was accounted for as an equity transaction and reflected as a reclassification from noncontrolling interests to members’ equity with no gain or loss recognized on the April 2021 Exchange.

In March 2021, we acquired a portfolio of oil and natural gas mineral assets located in the DJ Basin from an unrelated third-party operator for total consideration of $60.8 million (the "DJ Basin Acquisition"). The DJ Basin Acquisition was funded using cash on hand and borrowings under our Prior Credit Agreements. We accounted for the DJ Basin Acquisition as an asset acquisition.

In August 2020, we consummated the Titan Acquisition, pursuant to which we acquired of all of the outstanding membership interests in Liberty Energy LLC (and the oil and natural gas assets owned thereby) pursuant to the Contribution Agreement, dated as of July 19, 2020, by and among Independence Energy LLC, Liberty Energy Holdings, LLC (“Liberty Holdco”) and the other parties thereto, in consideration for the issuance of certain membership interests in Independence to an entity substantially owned by Liberty Holdco. Subsequent to the Titan Acquisition, we changed the name of Liberty Energy, LLC to Titan. Titan owns certain working interests in non-operated producing and non-producing oil and natural gas properties in the Permian, DJ and Eagle Ford Basins, which includes a 50% interest in the DJ Basin Erie Hub Gathering System. As a part of the Titan Acquisition, during the year ended December 31, 2020, we transferred $455.1 million of equity consideration in the form of 0.4 million Class A units of our Predecessor.

Divestitures

In November 2022, we entered into a definitive purchase and sale agreement with an unaffiliated third party to sell certain of our non-core producing properties and related oil and natural gas leases in Ector County in the Permian Basin in exchange for cash consideration, subject to customary purchase price adjustments, of $80.0 million. We closed the divestiture in December 2022 and recorded a loss of $0.9 million during the year ended December 31, 2022.

In April 2022, our equity method investment, Exaro Energy III, LLC ("Exaro"), entered into a purchase and sale agreement to sell its operations in the Jonah Field in Wyoming. During the year ended December 31, 2022, we received a distribution of $6.8 million primarily as a result of the sale.

In February 2022, we contributed all of the assets and prospects in the Gulf of Mexico formerly owned by Contango to Chama Energy LLC ("Chama") in exchange for a 9.4% interest in Chama, which interest was valued at $3.8 million. As a result, we derecognized the assets and liabilities that were contributed to Chama from our consolidated balance sheets and recorded an equity method investment for our interest in Chama, as well as a $4.5 million gain related to the deconsolidation of these assets and liabilities. John Goff, the Chairman of our Board of Directors, holds an approximate interest of 17.5% in Chama, and the remaining interests are held by other investors. Pursuant to the Limited Liability Company Agreement of Chama, we may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to the producing assets we contributed to Chama.

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In December 2021, we entered into a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in Claiborne Parish, Louisiana in exchange for cash consideration, net of closing adjustments, of $4.3 million.

In May 2021, we executed a purchase and sale agreement with an unaffiliated third-party that encompassed the sale of certain producing properties and oil and natural gas leases in the Arkoma Basin in exchange for cash consideration, net of closing adjustments, of $22.1 million. We recognized a $8.8 million gain on sale of assets in our combined and consolidated statements of operations for the year ended December 31, 2021, as a result of the transaction.

Stewardship

We strive to be good stewards of others’ assets: our investors’ capital, the environment and the communities in which we operate. We believe that this stewardship, and our success, requires an alignment with the interests of our stakeholders including our employees, investors, customers, suppliers and society at large. We view exceptional sustainability performance as an opportunity to differentiate Crescent from its peers, mitigate risks and strengthen operational performance as well as benefit our stakeholders and the communities in which we operate. In September 2022, we released our 2021 ESG report. The report included benchmarks for measuring future performance, consistent with Crescent's commitment to aligning with the SASB and Task Force on Climate-related Financial Disclosures frameworks, noted the progress of our key ESG priorities and detailed our goals to reduce GHG emissions in support of an economy-wide transition to a net-zero world. We are working to reduce Scope 1 GHG and methane emissions by implementing ambitious targets and eliminating routine flaring, among other initiatives. In February 2022, we joined the Oil & Gas Methane Partnership ("OGMP") 2.0 Initiative to enhance reporting of methane emissions. Our inaugural OGMP 2.0 submission was rated the highest-level, "Gold Standard."We also established an ESG Advisory Council to advise management and our Board on ESG-related issues.

How we evaluate our operations

We use a variety of financial and operational metrics to assess the performance of our oil, natural gas and NGL operations, including:

•Production volumes sold;

•Commodity prices and differentials;

•Operating expenses;

•Adjusted EBITDAX (non-GAAP); and

•Levered Free Cash Flow (non-GAAP)

Development program and capital budget

Our development program is designed to prioritize the generation of attractive risk-adjusted returns and meaningful free cash flow and is inherently flexible, with the ability to modify our capital program as necessary to react to the current market environment.

We expect to incur approximately $575 million to $650 million, excluding acquisitions, for our 2023 capital program. The majority of our program is allocated to D&C, which approximately 85% is allocated to our operated assets primarily in the Eagle Ford and Uinta basins. We expect to fund our 2023 capital program through cash flow from operations. Due to the flexible nature of our capital program and the fact that majority of our acreage is held by production, we could choose to defer a portion or all of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil, gas and NGLs and resulting well economics, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Sources of revenues

Our revenues are primarily derived from the sale of our oil, natural gas and NGL production and are influenced by production volumes and realized prices, excluding the effect of our commodity derivative contracts. Pricing of commodities are subject to

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supply and demand as well as seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table illustrates our production revenue mix for each of the periods presented:

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 6% or less of our total revenues for each of the years ended December 31, 2022, 2021 and 2020.

Production volumes sold

The following table presents historical sales volumes for our properties:

Total sales volume increased 16,142 MBoe during the year ended December 31, 2022 compared to 2021. The increase is primarily due to the Merger Transactions, DJ Basin Acquisition and Central Basin Platform Acquisition (collectively, the "2021 Acquisitions") and our Uinta Transaction, which contributed an additional 10,777 MBoe and 7,740 MBoe, respectively. Sales volumes from our other assets decreased by 2,375 during the year ended December 31, 2022 compared to 2021, primarily as a result of the natural decline from our existing asset base, partially offset by new operated Eagle Ford well completions in 2022.

Commodity prices and differentials

Our results of operations depend upon many factors, particularly the price of commodities and our ability to market our production effectively.

The oil and natural gas industry is cyclical and commodity prices can be highly volatile. In recent years, commodity prices have been subject to significant fluctuations. The outbreak of the COVID-19 virus followed by certain actions taken by OPEC caused crude oil prices to decline significantly beginning in the first half of 2020 and prices remained below pre-pandemic levels for a prolonged period of time, finally recovering to pre-pandemic levels during 2021 and into 2022. Commodity prices were higher in 2022, compared to 2021, reflecting the ongoing recovery in the oil and gas industry in 2022 due to increasing demand as more states and countries re-open and national and global economies recover from the global COVID-19 pandemic and a premium due to the reduction in crude oil supply resulting from sanctions imposed on Russia in response to its large-scale invasion of Ukraine in February 2022. Although commodity prices have increased substantially in 2022, uncertainty persists regarding OPEC’s actions, increased U.S. drilling, the continued effect from the COVID-19 pandemic, inflation and the armed conflict in Ukraine.

In order to reduce the impact of fluctuations in oil and natural gas prices on revenues, we regularly enter into derivative contracts with respect to a portion of the estimated oil, natural gas and NGL production through various transactions that fix the future prices received. We plan to continue the practice of entering into economic hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and corporate returns and maintain our liquidity.

The following table presents the percentages of our production that was economically hedged through the use of derivative contracts:

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The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented: