EDGAR 10-K Filing

Company CIK: 1866175
Filing Year: 2025
Filename: 1866175_10-K_2025_0001866175-25-000024.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
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 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.”
Our free cash flow-focused portfolio includes a balanced set of oil and natural gas assets in proven onshore U.S. basins with substantial existing production, a low decline rate and an acreage position that is 96% held by production as of December 31, 2024. As a result of this overall low decline profile, we require relatively minimal capital expenditures to maintain our production and cash flows. We have a robust inventory of attractive operated undeveloped locations, providing for optimal flexibility to maintain or grow our production base. While many operators in our industry have historically focused on the capital intensive pursuit of high production growth rates, our management team has a track record of selectively acquiring cash flow oriented assets, operating them more profitably and making disciplined, returns focused reinvestment decisions to drive free cash flow generation. Our portfolio is enhanced and complemented by our additional interests in mineral acreage and midstream infrastructure, which provide operational benefits and enhance our cash flow margins.
We have built a portfolio of assets with substantial reserves, production, cash flows and reinvestment opportunities. Our portfolio of assets:
•at December 31, 2024 consisted of 709.3 net MMBoe of proved reserves, of which approximately 63% were liquids, reflecting $5.7 billion in Standardized Measure and $6.5 billion and $4.9 billion, respectively, in net proved and net proved developed ("PD") present value discounted at a 10% discount rate;
•during the year ended December 31, 2024 produced 201 net MBoe/d; and
•during the year ended December 31, 2024, generated $137.7 million of net loss, $1,223.1 million of net cash provided by operating activities, $1,598.3 million of Adjusted EBITDAX and $630.2 million of levered free cash flow;
See “-Non-GAAP financial measures” and "-Results of Operations" in "Part II., Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for definitions of Adjusted EBITDAX and Levered Free Cash Flow and reconciliations to the nearest comparable GAAP metrics.
The following diagram displays our simplified ownership structure as of January 31, 2025:
Free cash flow-focused portfolio
Our asset base, which is primarily located in Texas and the Rockies, includes oil and natural gas assets in key proven onshore U.S. basins, and is composed of producing properties with substantial production and hedged cash flow that are complemented by an extensive inventory of reinvestment opportunities across our undeveloped acreage. While many of our peers have historically outspent their cash flows in pursuit of production growth and left themselves particularly vulnerable to declines in commodity prices, we have an average reinvestment rate of approximately 45% of Adjusted EBITDAX since 2020.
Low-decline production base
Our PDP reserves as of December 31, 2024 have estimated average five-year and ten-year annual decline rates of approximately 11% and 8%, respectively, and an estimated 2025 PDP decline rate of 25%, based on forecasts used in our reserve reports. As a result of this low decline profile, we require relatively minimal capital expenditures to maintain our production and cash flows. Our properties located in the Eagle Ford and Rockies represent approximately 86% of our proved reserves as of December 31, 2024, and provide us with diversification from both a regional location and commodity price perspective, which provides us certain downside protection from commodity-specific pressures, isolated infrastructure constraints or severe weather events. Our Standardized Measure totaled $5.7 billion as of December 31, 2024. The table below illustrates the aggregate leasehold acreage positions, reserve volumes and weighted average decline profiles associated with our proved assets as of December 31, 2024.
Net Acres Net Proved Reserves (1)
% Oil & Liquids (1)
Net PD Reserves (1)
2024 Total Net Production
Net Proved PV-10 (1)(2)
Net PD PV-10 (1)(2)
Operating Area
(M) (MMBoe) (MMBoe) (MBoe) (MM) (MM)
Eagle Ford 461 497 63 % 336 38,708 $ 4,695 $ 3,308
Rockies 374 114 68 % 93 21,479 1,181 980
Other 597 98 52 % 98 13,450 583 579
Total 1,432 709 63 % 527 73,637 $ 6,459 $ 4,867
(1)Our reserves and present value (discounted at ten percent, or PV-10) were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $75.48 per barrel as of December 31, 2024, was adjusted for items such as gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub Index spot price of $2.13 per MMBtu as of December 31, 2024, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted realized product prices over the remaining lives of the properties are $72.69 per barrel of oil, $1.74 per Mcf of natural gas and $23.81 per barrel of NGLs.
(2)Reflects the Net Proved and Net PD present values reflected in our proved reserve estimates as of December 31, 2024. PV-10 is not a financial measure prepared in accordance with GAAP because it does not include the effects of income taxes on future revenues. Our Standardized Measure was $5.7 billion as of December 31, 2024. See “Oil, natural gas and NGL reserve data” for additional discussion.
Our Relationship with the KKR Group
We are a party to a Management Agreement that engages the Manager to provide certain management and investment advisory services to us and our subsidiaries. The Manager is an indirect subsidiary of the KKR Group. The KKR Group is a leading global investment firm that offers alternative asset management as well as capital markets and insurance solutions.
Pursuant to the Management Agreement, the Manager has agreed to provide us with management services, including our senior executive management team, and other assistance, including with respect to strategic planning, risk management, identifying and screening potential acquisitions, identifying and analyzing sustainability-related issues and providing such other assistance as we may require.
Through our integration with the KKR Group’s global platform, we believe that we benefit from: the power of the “KKR Brand;” KKR Capstone, which creates value by assisting with due diligence and identifying and delivering sustainable operational performance improvements within the KKR Group’s portfolio companies; KKR Global Macro and Asset Allocation, which assists with assessing the impact of macroeconomic factors on potential investments and helps identify market opportunities; KKR Capital Markets LLC ("KCM"), which assists with optimizing the capital structure of investments and underwrites and arranges debt, equity and other forms of financing for both KKR portfolio companies and independent clients, and KKR Public Affairs, which, together with the KKR Global Institute, provides insight into sustainability, regulatory, geopolitical, and reputational issues, including experience working with key stakeholders, such as labor unions, industry and trade associations and non-governmental organizations.
For additional information regarding our Management Agreement and our relationship with the KKR Group, see "Item 1A. Risk Factors, Risks related to the oil and natural gas industry and our operations-Through the Management Agreement, we
depend on the Manager and its personnel to manage and operate our business, the loss of any of whom would materially and adversely affect future operations. Additionally, operational risks affecting the Manager, and our ability to work collaboratively with the Manager, including with respect to the allocation of corporate opportunities and other conflicts of interest, may impact our business and have a material effect on our business, financial results and prospects."
Management Agreement
We are a party to a Management Agreement pursuant to which we have engaged the Manager to manage the strategy, assets and day-to-day business and affairs of us and our subsidiaries, subject at all times to applicable law, the further terms and conditions set forth in the Management Agreement and to the supervision of our Board. Pursuant to the Management Agreement, the Manager will provide us with our senior executive management team. Additionally, pursuant to the Management Agreement:
•The Manager shall ensure that at least 70% of any investment amounts related to upstream oil and gas opportunities are allocated to us. Follow-on investment amounts will be generally allocated between us and EIGF II in proportion to the relative amount such vehicle initially invested in the applicable investment.
•From time to time, investment opportunities outside of upstream oil and gas assets may arise that are suitable for investment by us, on the one hand, and by EIGF II (and any successor fund) or other KKR Funds, on the other that are (A) engaged in an investment strategy that is materially different from us (such as distressed debt or special situations investment vehicles) and (B) have pre-existing defined allocation rights pursuant to KKR’s allocation policies or contractual undertakings agreed with the investors in such other KKR Funds. In such cases, we may elect to co-invest alongside EIGF II and/or such other KKR Funds in such investments, in which case KKR will allocate such investment opportunities among us, on the one hand, and EIGF II and/or such other KKR Funds, on the other hand, in a manner consistent with the priority investment rights of such KKR Funds, taking into account such factors as KKR deems appropriate. We shall have no obligation to make any such co-investment.
•As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive (inclusive of the items below, “Manager Compensation”):
(i) compensation from us equal to $51.3 million per annum (calculated based on our pro rata relative ownership of OpCo multiplied by $69.4 million (the “Base Input”), which is included in General and administrative expenses on our consolidated statements of operations. As our business and assets expand, the Base Input will increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of primary equity securities by us (including in connection with acquisitions). However, the Base Input will not increase from the issuance of our shares upon the redemption or exchange of OpCo Units.
We expect our ownership percentage of OpCo will increase over time through the redemption of OpCo Units for shares of Class A Common Stock or the issuance of additional shares of Class A Common Stock. As this occurs, the Manager Compensation will increase pursuant to the formula defined in the Management Agreement, which is reflected in our consolidated statements of operations. In order to pay the Manager Compensation, the Company must first receive a cash distribution from OpCo, and any such cash distribution results in a concurrent pro rata cash distribution to the holders of redeemable noncontrolling interests. This cash distribution to the holders of redeemable noncontrolling interests does not represent additional Manager Compensation; rather, it represents an ordinary cash distribution to the holders of redeemable noncontrolling interests. In certain instances in our financial statements and other disclosures, we clarify the underlying event that requires us to make such distributions, not because the distributions to the holders of redeemable noncontrolling interests are made for such purpose (e.g. Cash distributions to redeemable noncontrolling interests initiated by Class A common stock dividend, Cash distributions to redeemable noncontrolling interests initiated by Manager Compensation and Cash contributions from (cash distributions to) redeemable noncontrolling interests initiated by income taxes).
(ii) a performance-based incentive grant pursuant to which the Manager is targeted to receive up to 10% of outstanding Class A Common Stock based on the achievement of certain performance-based measures (the "Incentive Compensation."). The Incentive Compensation consists of five tranches that settle over a five-year period beginning in 2024, and each tranche relates to a target number of shares of Class A Common Stock equal to 2% of the outstanding Class A Common Stock as of the time such tranche is settled. Performance goals are evaluated on absolute stock price performance and relative stock price performance versus a set of
our peers and there is no vesting based solely on time. Based on the level of achievement with respect to the performance goals applicable to such tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A Common Stock ranging from 0% to 4.8% of the outstanding Class A Common Stock at the time each tranche is settled so long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche.
(iii) reimbursement for the Manager's pro rata share (based on percentage of public ownership of us) of any documented costs or expenses incurred by the Manager on behalf of us (other than normal overhead expenses relating to the business or operations of the Manager). These costs and expenses include, among other things, costs of outside counsel, accountants and auditors, taxes, fees related to regulatory compliance, costs related to IT services and other costs related to identifying, evaluating and structuring investments.
•The Management Agreement was amended in 2024 to cap the increase to the Base Input in connection with the SilverBow Merger and Ridgemar Acquisition and was automatically renewed on December 7, 2024 for an additional three-year term ending December 7, 2027 and will have automatic three-year renewals thereafter.
•Upon the written notice to the Manager at least 180 days prior to the expiration of the initial term or any automatic renewal term, we may, without cause, decline to renew the Management Agreement upon the affirmative determination by at least two-thirds of our independent directors reasonably and in good faith that (1) there has been unsatisfactory long-term performance by the Manager that is materially detrimental to us and our subsidiaries taken as a whole or (2) the fees payable to the Manager, in the aggregate, are materially unfair and excessive compared to those that would be charged by a comparable asset manager managing assets comparable to our assets, subject to the Manager’s right to renegotiate the fees. In the event of such a termination, we shall pay the Manager a termination fee equal to three (3) times the sum of (i) the average annual Manager Compensation and (ii) the average of the Incentive Compensation (but only with respect to the fully vested portion thereof as of the termination date), in each case earned by the Manager during the 24-month period immediately preceding the most recently completed calendar quarter prior to the termination.
Properties
Summary of our assets
Leasehold acreage
Our portfolio includes low-decline oil and natural gas assets in proven regions across the United States, including in the Eagle Ford and Rockies. In addition to this geographic diversity, we believe that our portfolio of leasehold acreage is enhanced and complemented by our additional interests in mineral acreage and midstream infrastructure. We had leasehold interests in an aggregate of 1.4 million net acres as of December 31, 2024, 1.3 million of which we were designated as operator. We are responsible for our pro rata share of capital expenditures and lease operating expenses for the operated and non-operated working interests within our leasehold acreage based on our percentage working interest and we are entitled to revenues derived from such interest based on our net revenue interest, which generally equals our working interest in such property less any royalties and production payments and any overriding royalty and net profits interests burdening the property.
Mineral and royalty interests
In addition to our leasehold acreage, we own mineral and royalty interests. As of December 31, 2024, we owned mineral interests in 166 thousand gross acres and an overriding royalty interest in 118 thousand gross acres, both operated by large, well-capitalized oil and natural gas companies primarily in the Eagle Ford, Marcellus, Utica and Rockies. On our mineral acreage, all of which we have leased to other operators, we have typically retained a royalty interest, which is a cost-free percentage of production revenue that expires upon termination of the lease, at which time the entire mineral interest reverts to us. These interests entitle us to receive a royalty and overriding royalty interest on all production from such acreage with no additional future capital or operating costs required.
Midstream infrastructure
We own and operate a variety of midstream assets, which provide services to our upstream assets and other customers. These include:
•a 12.0% interest in the Springfield Gathering System in the Eagle Ford Shale in Dimmit, La Salle and Webb Counties of southeast Texas, which is operated by Western Midstream Partners, LP (NYSE: WES) and includes both oil and gas gathering systems.
•the Howell Pipeline, a 125-mile, 16-inch carbon dioxide pipeline that stretches across central Wyoming, which provides CO2 supply to support enhanced oil recovery operations on our acreage located in the Salt Creek and Monell Fields, in addition to serving third-party customers in the area.
•a 50.0% interest in a centralized production facility, referred to as the DJ Basin Erie Hub Gathering System, which is located just east of Erie, Colorado, and provides a single site for processing equipment for portions of our DJ asset.
•a 65.0% equity method investment in the Lost Creek Gathering System, a 158-mile, 20-inch natural gas pipeline in Wyoming and a 77-mile, 2- to 8-inch FERC-jurisdictional crude oil pipeline in Wyoming. We also own interests in and operate three gas processing plants and several other pipelines in Wyoming.
•a 66.7% interest in the Cherokee Water Gathering System, an approximately 200-mile produced water pipeline in Oklahoma.
Our operating areas
Our operating areas include the Eagle Ford and Rockies. The below table describes the net acreage, net productive wells, production and proved reserve amounts for each of our geographic areas for the year ended and as of December 31, 2024:
Geographic Area Net Acres Net Productive Wells 2024 Production Proved Reserves
(M) (MBoe) (MBoe)
Eagle Ford 461 2,677 38,708 497,167
Rockies
374 3,148 21,479 113,812
Other Basins
597 2,936 13,450 98,272
Oil, natural gas and NGL reserve data
The following table summarizes our estimated net proved reserves as of December 31, 2024 based on an evaluation prepared in accordance with SEC Pricing, including the provisions of the SEC rule regarding reserve estimation regarding a historical twelve month pricing average applied prospectively.
As of December 31,
2024 (1)
2023 (1)
Net Proved Reserves:
Oil (MBbls) 297,690 250,465
Natural gas (MMcf) 1,595,059 1,176,416
NGLs (MBbls) 145,716 101,632
Total Proved Reserves (MBoe) 709,251 548,166
Standardized Measure (millions) (2)
$ 5,704 $ 5,289
PV-0 (millions) (2)
$ 11,108 $ 9,656
PV-10 (millions) (2)
$ 6,459 $ 5,566
Net Proved Developed Reserves:
Oil (MBbls) 193,611 176,546
Natural gas (MMcf) 1,342,718 1,032,578
NGLs (MBbls) 109,223 87,316
Total Proved Developed Reserves (MBoe) 526,622 435,958
PV-0 (millions) (2)
$ 7,651 $ 7,010
PV-10 (millions) (2)
$ 4,867 $ 4,375
Net Proved Undeveloped Reserves:
Oil (MBbls) 104,079 73,919
Natural gas (MMcf) 252,341 143,838
NGLs (MBbls) 36,493 14,316
Total Proved Undeveloped Reserves (MBoe) 182,629 112,208
PV-0 (millions) (2)
$ 3,457 $ 2,646
PV-10 (millions) (2)
$ 1,592 $ 1,191
(1)Our reserves and present value (discounted at ten percent, or PV-10) were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $75.48 per barrel and $78.22 per barrel as of December 31, 2024 and 2023, was adjusted for items such as gravity, quality, local conditions, gathering, transportation fees and distance from market. For natural gas volumes, the average Henry Hub Index spot price of $2.13 per MMBtu and $2.64 per MMBtu as of December 31, 2024 and 2023, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted realized product prices over the remaining lives of the properties are $72.69 per barrel of oil, $1.74 per Mcf of natural gas and $23.81 per barrel of NGLs as of December 31, 2024. The average adjusted product prices over the remaining lives of the properties were $74.71 per barrel of oil, $2.36 per Mcf of natural gas and $27.33 per barrel of NGLs as of December 31, 2023.
(2)Present value (discounted at PV-0 and PV-10) is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. None of PV-0, PV-10 and Standardized Measure represent an estimate of the fair market value of our oil and natural gas properties. Our PV-0 measurement does not provide a discount rate to estimated future cash flows. PV-0 therefore does not reflect the risk associated with future cash flow projections like PV-10 does. PV-0 should therefore only be evaluated in connection with an evaluation of our PV-10 and Standardized Measure. We believe that the presentation of PV-0 and PV-10 is relevant and useful to its investors as supplemental disclosure to the Standardized Measure because they present future net cash flows attributable to our reserves prior to taking into account future income taxes and our current tax structure. The PV-0 and PV-10 income tax amounts included in the Standardized Measure but not included in PV-0 and PV-10 were $1,055.1 million and $755.3 million, respectively. We and others in our industry use PV-0 and PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Investors should be cautioned that none of PV-0, PV-10 and Standardized Measure represent an estimate of the fair market value of our proved reserves.
Preparation of reserve estimates
Our reserve estimates as of December 31, 2024 are primarily based on evaluations prepared by Ryder Scott Company, L.P., with respect to 98% of our total proved reserves, with the remaining 2% prepared by our internal technical staff. Our Independent Reserve Engineers were selected for their historical experience and geographic expertise in engineering similar resources. Our reserve estimation process is a collaborative effort overseen by our Vice President of Corporate Reserves, who has over 18 years of experience in the estimation and evaluation of petroleum reserves. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs to formulate our reserves estimates. The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
•review and verification of historical production, cost and capital expenditures data;
•verification of property ownership by our land department;
•preparation of reserves estimates by our lead reservoir engineers;
•review by our management, including our Chief Executive Officer and Chief Financial Officer, of all significant reserve changes and all new PUD additions; and
•no employee’s compensation is tied to the amount of reserves booked.
The technical leads responsible for preparing our reserves estimates at December 31, 2024 from Ryder Scott Company, L.P. have over 28 years of industry experience.
Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the Independent Reserve Engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data and well-test data.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net cash flows are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See "Item 1A. Risk Factors" appearing elsewhere in this Annual Report.
Proved undeveloped reserves (PUDs)
Our PUDs will be converted from undeveloped to developed as the applicable wells have been drilled or completed and have minimal capital remaining to bring the well onto production. The changes to our PUDs that occurred during the year are summarized in the table below:
(MBoe)
Balance at December 31, 2023
112,208
Purchases of reserves in place 76,496
Extensions and discoveries 166
Revisions of previous estimates 16,851
Sales of reserves in place -
Transfers to proved developed (23,092)
Balance at December 31, 2024
182,629
Purchases of reserves in place of 76.5 MMBoe during the year ended December 31, 2024 primarily relate to PUD locations added as part of the SilverBow Merger and the Central Eagle Ford Acquisition. Revisions of previous estimates during the year ended December 31, 2024 were primarily due to changes in the drill plan largely attributed to the Western Eagle Ford Acquisitions and related well results, combined with the SilverBow Merger and increased rig count, both which created reprioritization of our capital program and caused upward adjustments to our five-year development plan, partially offset by the removal of 10.1 MMBoe of non-operated PUD locations. Our extensions of 0.2 MMBoe primarily relate to operatorship enhancements and positive results from previously non-operated assets that we acquired in the Western Eagle Ford Acquisitions and assigning undeveloped value to the Austin Chalk formation on our acreage. Additionally, during the year ended December 31, 2024, we spent $369.6 million to convert 23.1 MMBoe to proved developed reserves.
All such PUD reserves are scheduled to be developed within five years from their booking date. The PUD reserves are spread across multiple assets primarily in Texas and Utah. Our PUD reserves represent only reserves that are scheduled, based on such plan, to be developed within five years from the date such locations were initially disclosed as PUDs; however, our five-year development plan may not contemplate a uniform (i.e., 20% per year) conversion of PUD reserves. At December 31, 2024, we estimate that our future development costs relating to the development of PUD reserves are $610 million in 2025, $762 million in 2026 and $705 million in 2027, $329 million in 2028 and $300 million in 2029. We believe cash flow from operations and availability under the Revolving Credit Facility will be sufficient to cover these estimated future development costs.
Oil, natural gas and NGL production prices and operating costs
Production and price history
The following table sets forth production, price and cost data for the years ended December 31, 2024, 2023, and 2022.
Year Ended December 31,
2024 2023 2022
Net Production:
Eagle Ford:
Oil (MBbls) 16,019 8,924 6,212
Natural gas (MMcf) 82,910 23,464 15,154
NGLs (MBbls) 8,871 3,356 1,712
Total (MBoe) 38,708 16,191 10,450
Average daily production (MBoe/d) 106 44 29
Rockies:
Oil (MBbls) 11,155 12,270 11,650
Natural gas (MMcf) 53,262 53,691 53,509
NGLs (MBbls) 1,447 1,832 1,870
Total (MBoe) 21,479 23,051 22,438
Average daily production (MBoe/d) 59 63 61
Total:
Oil (MBbls) 29,945 24,287 21,865
Natural gas (MMcf) 183,227 130,629 128,470
NGLs (MBbls) 13,154 8,475 7,110
Total (MBoe) 73,637 54,533 50,387
Average daily production (MBoe/d) 201 149 138
Average Realized Prices (before effects of derivatives):
Eagle Ford:
Oil (per Bbl) $ 74.03 $ 75.03 $ 94.87
Natural gas (per Mcf) $ 1.91 $ 2.27 $ 6.30
NGLs (per Bbl) $ 24.80 $ 25.75 $ 39.42
Rockies:
Oil (per Bbl) $ 66.12 $ 68.91 $ 85.85
Natural gas (per Mcf) $ 1.94 $ 3.68 $ 5.75
NGLs (per Bbl) $ 27.50 $ 24.02 $ 41.03
Total:
Oil (per Bbl) $ 71.14 $ 72.09 $ 90.06
Natural gas (per Mcf) $ 1.91 $ 2.84 $ 5.97
NGLs (per Bbl) $ 24.10 $ 22.76 $ 37.72
Average Production Costs per Boe:
Eagle Ford $ 14.33 $ 18.76 $ 19.81
Rockies $ 16.06 $ 19.58 $ 19.61
Total $ 15.86 $ 19.04 $ 19.84
Wells
The following table sets forth information regarding our productive wells as of December 31, 2024:
Working Interest Assets Mineral and Royalty Interests
Gross Net Average Working Interest Gross Net Average Net Revenue Interest
Natural gas 4,255 2,850.6 67 % 1,548 20.9 1 %
Oil 11,285 5,783.6 51 % 4,307 106.4 2 %
Total 15,540 8,634.2 56 % 5,855 127.3 2 %
Leasehold acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2024.
Gross Net
(in thousands)
Developed Acres 2,289 1,329
Undeveloped Acres 238 104
Total Net Acres 2,527 1,433
Mineral Acres 166 55
Our undeveloped acreage, as used herein, means acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not the acreage contains proven reserves or is held by production.
Undeveloped acreage expirations
The following table sets forth the number of total net undeveloped acres as of December 31, 2024 that will expire in 2025, 2026, 2027 and 2028 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.
2025 2026 2027 2028
(in thousands)
Net undeveloped acres 8 7 2 3
The leases comprising the acreage that is subject to expiration as set forth in the table above will generally expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which case the lease will remain in effect until the cessation of production. Upon expiration of the primary term, we will lose our interests in the associated acreage unless fully held by production, maintained through our delivery of a lease extension payment or, in the case of many of our leases, we utilize the “continuous development clause” that permits us to continue to hold such acreage if we initiate additional development activities within 120-180 days after the completion of the last well drilled on such lease. Thereafter, the lease remains held under the continuous development clause so long as we undertake additional development activities every 120 to 180 days or until the entire lease is held by production. There can be no assurances as to our ability to maintain such acreage. For more information, see "Item 1A. Risk Factors" appearing elsewhere in this Annual Report.
Drilling and other exploration and development activities
The table below sets forth the results of our drilling activities, including wells in which we have a working or royalty interest but are not the operator, for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
Year Ended December 31,
2024 2023 2022
Gross Net Gross Net Gross Net
Development Wells:
Productive
297 79.4 242 67.5 383 62.2
Dry holes - - - - - -
Total Development 297 79.4 242 67.5 383 62.2
Exploratory Wells:
Productive - - - - - -
Dry holes - - - - - -
Total Exploratory - - - - - -
Total Wells:
Productive 297 79.4 242 67.5 383 62.2
Dry holes - - - - - -
Total 297 79.4 242 67.5 383 62.2
As of December 31, 2024, we were not a party to any long-term drilling rig contracts. The following table provides our wells in progress, as well as the various stages of such progress, at December 31, 2024 and includes wells in which we have a working interest but are not the operator.
Gross Net
Well Status:
Drilling 9 3.9
Waiting on completion 13 8.5
Being completed, not producing 49 20.2
Delivery commitments
We are party to various long-term agreements that require us to physically deliver crude oil and natural gas. These delivery commitments require us to deliver 6,181 MMBoe in 2025 and 175 MMBoe thereafter. These commitments are contracted marketing and gathering arrangements that require delivery of a fixed and determinable quantity of crude oil, natural gas, or NGLs in the future. We believe that our current production and reserves are sufficient to satisfy the majority of these commitments and alternatively we could purchase sufficient volumes of oil, natural gas and NGL in the market at prevailing index-related prices to satisfy the commitments, if needed. We incurred shortfalls related to some of our gathering and transportation commitments and as a result paid $6.6 million, $15.6 million and $4.5 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Marketing and customers
Production from our oil and natural gas properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production, including natural gas with recoverable NGLs, are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. In areas where there is no practical or commercial access to pipelines, oil is transported to storage facilities by truck. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.
During the years ended December 31, 2024, 2023 and 2022, we sold oil and natural gas production representing 10% or more of total revenues to the following purchasers:
Year Ended December 31,
2024 2023 2022
Shell Trading US Company 23.7% 18.3% 20.8%
ConocoPhillips 16.5% * 15.1%
*Purchaser did not account for greater than 10% of revenue for the year.
While the loss of a significant purchaser could result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of any such purchasers would not have a material adverse effect on our operations because there are other purchasers in our producing regions.
We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil or natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than some of the larger companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil or natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Seasonality of business
Generally, demand for oil, natural gas and NGL decreases during the spring and fall months and increases during the summer and winter months. However, certain natural gas and NGL markets utilize storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In addition, seasonal anomalies such as mild winters or mild summers can have a significant impact on prices. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increased costs or delay operations.
Title to properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.
Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current
taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.
Human Capital Measures
Employees
We manage our operations through (i) management and corporate-level services provided by the Manager and (ii) asset-level services and operations provided by our approximately 987 employees as of December 31, 2024 that dedicate all or substantially all of their time to our business. We hire independent contractors on an as-needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.
Values and Culture
We believe our company values of Stewardship, Integrity, Teamwork and Excellence provide the foundation for our culture. Our focus on working together as a team to achieve outstanding results is key to attracting and retaining talented people. The Company’s human resources department manages our human capital initiatives with support and direction from the Company’s senior leadership. Our culture is reinforced by the Company’s senior leadership though holding quarterly town halls, communicating regularly with the workforce and working to foster a culture of open communication.
Safety
Working safely and responsibly is a priority across all business units with a focus on protecting the well-being of our team, partners and communities. Workplace safety procedures and programs include but not limited to confined space entry, emergency response, fall protection, hearing conservation, hot work, hydrogen sulfide, incident reporting and investigation, personal protective equipment and spill prevention. Safety performance is tracked on a monthly basis across operations and trends guide safety program improvements.
Recruitment, development and training
The Company understands that recruitment, development and training are essential to preparing a workforce to deliver on its long-term strategy. We implement a dynamic recruiting process that utilizes online recruiting platforms, referrals and professional recruiters. We foster the growth and professional development of our employees through the use of a robust performance review process, which includes the creation of performance development goals and plans to achieve those goals in order to help our employees reach their full potential. We also incorporate training during our on-boarding process focused on safety and compliance. Additional training offerings are held throughout the year to address the specific needs of our business and workforce.
Total rewards programs
The Company routinely benchmarks its compensation and benefits program with the goal of retaining and attracting industry talent while meeting the varied and evolving needs of a multi-faceted workforce. We provide employees with the ability to participate in subsidized health and welfare plans, including medical, dental, life and short-term and long-term disability insurance plans. We also offer a retirement plan with employer match, paid time off, paid parental leave and a wellness stipend.
Community & social engagement
We are committed to supporting and giving back to the communities in which we operate and live. We recognize the link between local communities, the success of our employees and, ultimately, the success of our business.
Legislative and regulatory environment
Our oil, natural gas and NGL exploration, development, production, gathering, transportation, sales and related operations and activities are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with such rules and regulations can result in administrative, civil or criminal penalties, compulsory remediation and imposition of natural resource damages or other liabilities. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such requirements. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, we believe these obligations generally do not impact us differently or to any greater or lesser extent than they affect other operators in the oil and natural gas industry with similar operations and types, quantities and locations of production.
Regulation of production
In many states oil and natural gas companies are generally required to obtain permits for drilling operations, provide drilling bonds, file reports concerning operations and meet other requirements related to the exploration, development and production of oil, natural gas and NGL. Such states also have statutes and regulations addressing conservation matters, including provisions for unitization or pooling of oil and natural gas interests, rights and properties, the surface use and restoration of properties upon which wells are drilled and disposal of water produced or used in the D&C process. These regulations include the establishment of maximum rates of production from oil and natural gas wells, rules as to the spacing, plugging and abandoning of such wells, restrictions on venting or flaring oil and natural gas and requirements regarding the ratability of production, as well as rules governing the surface use and restoration of properties upon which wells are drilled.
These laws and regulations may limit the amount of oil, natural gas and NGL that can be produced from wells in which we own an interest and may limit the number of wells, the locations in which wells can be drilled or the method of drilling wells. Additionally, the procedures that must be followed under these laws and regulations may result in delays in obtaining permits and approvals necessary for our operations and therefore our expected timing of drilling, completion and production may be negatively impacted. These regulations apply to us directly as the operator of our leasehold. The failure to comply with these rules and regulations can result in substantial penalties.
Regulation of sales and transportation of liquids
Sales of condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, the U.S. Congress could reenact price controls in the future.
Our sales of NGLs are affected by the availability, terms and cost of transportation. The transportation of NGLs in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil, NGL and other liquid pipeline transportation rates under the ICA. In general, interstate liquids pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.
Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of liquids transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Regulation of transportation and sales of oil and natural gas
Historically, the transportation and sale for resale of oil and natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, the U.S. Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.
The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EP Act of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. In January 2025, the maximum penalty increased to $1,584,648 per violation per day to account for inflation. The civil penalty provisions are applicable to entities that engage in the sale and transportation of natural gas for resale in interstate commerce.
On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
On December 26, 2007, FERC issued Order No. 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.
Gathering service, which occurs upstream of jurisdictional transportation services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services could be the subject of ongoing litigation, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts or the U.S. Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
We own an interstate liquids pipeline through a consolidated subsidiary that is considered a common carrier pipeline subject to regulation by FERC under the ICA. Unless we obtain a waiver of the applicable provisions, the ICA requires that we maintain tariffs on file with FERC for interstate movements of liquids on our pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires that tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory. Many FERC-regulated liquids pipelines, including ours, use the FERC indexing methodology to change its rates. FERC, however, retained cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. For those pipelines that use the FERC indexing methodology, FERC reviews the index formula every five years to determine whether a change in the methodology is required or, if not, to determine the appropriate index for the subsequent five-year period. On January 20, 2022, FERC issued an order on rehearing of its December 17, 2020 Order Establishing Index Level in which the FERC reduced the oil pricing index factor for oil pipelines to use for the current five-year period. As a result, the ceiling levels computed for July 1, 2021 to June 30, 2022, as well as the ceiling levels for the period July 1, 2022, to June 30, 2023, and the resulting rates currently in effect for our
pipelines, were recomputed to account for the appropriate index factor. FERC denied rehearing of the January 20 order on May 6, 2022. Certain parties have now appealed the January 20 and May 6 FERC orders, and the appeals remain pending before the DC Circuit.
From time to time, we might enter into arrangements to transport liquids on an affiliated ICA-jurisdictional pipeline, and FERC may more heavily scrutinize agreements between ICA jurisdictional pipelines and their affiliates. On December 15, 2022, FERC issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service seeking comments on a new framework for FERC to analyze agreements between an ICA-jurisdictional pipeline and an affiliated shipper. Under the Proposed Policy Statement, if following an open season, the only shipper agreeing to the noticed service is an affiliate of the pipeline, then FERC would presume the contract is unduly discriminatory and not just and reasonable and require the affiliates to rebut that presumption with additional evidence supporting the justness and reasonableness of the agreement. Comments on the Proposed Policy Statement are due in the spring of 2023. Notices of proposed policy statements are not final rules and FERC’s determination regarding changes to current practices are not required to be completed within a specific timeframe or at all. Additionally, on December 16, 2022, FERC issued an order in FERC Docket No. OR17-2-001 that clarified FERC’s rules and practices enforcing the ICA’s prohibition on certain transactions on ICA jurisdictional pipelines and affiliated shippers. Under FERC’s recent clarification of the ICA, FERC also will scrutinize transactions between jurisdictional pipelines and affiliated shippers to ensure a common parent company is not subsidizing transportation service on the pipeline. FERC’s treatment of contracts between affiliates on ICA jurisdictional pipelines has been changing in recent years, and it is difficult to predict the level and type of scrutiny that will be applied in the future and the extent to which affiliate contracts may be limited.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical and financial sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder enforced by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity as well as certain disruptive trading practices. The CFTC also has statutory authority to seek civil penalties of up to the greater of approximately $1,487,712 (adjusted annually for inflation) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Further, the FTC has the authority under the Federal Trade Commission Act (“FTCA”) and the Energy Independence and Security Act of 2007 (“EISA”) to regulate wholesale petroleum markets. The FTC has adopted anti-market manipulation rules, including prohibiting fraud and deceit in connection with the purchase or sale of certain petroleum products, and prohibiting omissions of material information which distort or are likely to distort market conditions for such products. In addition to other enforcement powers it has under the FTCA, the FTC can sue violators under EISA and request that a court impose fines of approximately $1,510,803 (adjusted annually for inflation) per violation per day.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. As such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.
Regulation of environmental and occupational safety and health matters general
Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing environmental protection, occupational safety and health, and the release, discharge or disposal of materials into the environment, some of which carry substantial administrative, civil and criminal penalties for failure to comply. Applicable U.S.
federal environmental laws include, but are not limited to, RCRA, CERCLA, OPA, the CWA, the CAA, the SDWA, the ESA, and the MBTA. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants, and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling, and production operations; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the D&C process; limit or prohibit construction or drilling activities in sensitive areas such as wilderness, wetlands, critical habitat of protected species, frontier and other protected areas; require investigatory or remedial actions to prevent or mitigate pollution conditions caused by our operations; impose obligations to reclaim and abandon well sites and pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. Additionally, the U.S. Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although environmental obligations have not historically had a material adverse impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of permits or leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. The general trend, over time, is that environmental regulations are evolving to place more restrictions and limitations on activities that may affect the environment, and any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal, or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our business, there can be no assurance that this will continue in the future.
The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on its capital expenditures, results of operations or financial position.
Hazardous substances and wastes
CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These classes of persons, or, as termed in CERCLA, potentially responsible parties, include the current and past owners or operators of a disposal site or site where the release occurred and anyone who disposed or arranged for the disposal of the hazardous substances found at such sites. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA and other environmental laws but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect our business operations. While petroleum and crude oil fractions are generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.
We also generate solid and hazardous wastes that may be subject to the requirements of the RCRA, and analogous state laws. RCRA regulates the generation, handling, storage, treatment, transport and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes “drilling fluids, produced waters and other wastes associated with the development or production of oil, natural gas or geothermal energy” from regulation as hazardous wastes. With the approval of the EPA, individual states can administer some or all of the provisions of RCRA and some states have adopted their own, more stringent requirements. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain oil and natural gas exploration and production wastes as “hazardous wastes,” which would make such wastes subject to much more stringent handling, disposal and clean-up requirements. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are determined to have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
We currently own, lease or operate numerous properties that may have been used by prior owners or operators for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations where such substances have been taken for recycling or disposal. In addition, some of our properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and/or analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.
Water discharges
The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other natural gas wastes, into or near waters of the United States or state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of these regulated waters has been subject to controversy in recent years. In January 2023, the agencies published a final rule defining “waters of the United States” according to the broader pre-2015 standards, with updates to incorporate existing Supreme Court decisions and agency guidance. However, this rule was subsequently enjoined in 27 states. Additionally, the Supreme Court of the United States released their opinion in Sackett v. EPA, which adopted the “continuous surface connection” test to determine if wetlands are water of the United States. The Agencies published a September 2023 rule to incorporate this decision, but did not define the term “continuous surface connection.” Due to the injunction, implementation of the rule is currently split by jurisdiction. In the 27 states subject to the injunction, the agencies are interpreting “waters of the United States” consistent with the pre-2015 regulatory regime and the changes made by the Sackett decision. In the remaining 23 states, the agencies are implementing the September 2023 rule. However, it is currently unclear how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies. Additionally, at this time, it is unclear what actions the Trump Administration may take with respect to any of these regulations and the timing with respect to the same. To the extent any judicial ruling or administrative rulemaking or other action further expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas.
The process for obtaining permits also has the potential to delay our operations. Additionally, spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” are required by federal law in connection with on-site storage of significant quantities of oil. Compliance may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak.
Safe Drinking Water Act
The SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans. The SDWA also regulates saltwater disposal wells under the UIC program. The EP Act of 2005 amended the UIC provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic
fracturing fluids and produced water or their injection for enhanced oil recovery is not excluded. In 2014, the EPA issued permitting guidance governing hydraulic fracturing with diesel fuels. While we do not currently use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under SDWA if our fracturing formula changes. Additionally, we may incur significant costs to comply with disposal requirements for hydraulic fracturing fluids and produced water. For more information, see "Item 1A. Risk Factors."
Air emissions
The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion and completed attainment/non-attainment designations in 2018. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion; however, several groups filed litigation over this decision and the Biden Administration subsequently announced that it would reconsider the 2020 decision. In August 2023, the EPA announced a new review of the ozone NAAQS to reflect updated ozone science in combination with the reconsideration of the December 2020 decision. However, the review remains ongoing at this time. Additionally, it is not clear what actions the Trump Administration may take with respect to the review. To the extent more stringent standards are implemented, we could be required to incur further costs for pollution control equipment or other compliance measures. Further, in June 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. These rules could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements.
State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound (“VOC”) and methane emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair VOC and methane at certain well sites and compressor stations. Additionally, in December 2023, the EPA issued a final rule that established OOOOb as a more stringent new source and OOOOc as first-time existing source standards of performance for methane and VOC emissions for the crude oil and natural gas source category. Under the final rule, owners or operators of affected emission units or processes will have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards under the final rule are generally the same for both new and existing sources, including enhanced leak detection using optical gas imaging and subsequent repair requirements, reduction of regulated emissions through capture and control systems, zero-emission requirements for certain equipment or processes, operations and maintenance requirements and requirements for “green well” completions. The final rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events as detected by governmental agencies or qualified third parties, triggering certain investigation and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. Failure to comply with these new methane rules may result in substantial fines and penalties for non-compliance, as well as injunctive relief. However, the EPA’s final rule is currently being challenged in 23 states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit. Additionally, at this time, it remains uncertain as to whether the Trump Administration will repeal or modify this rule and the timing with respect to the same. Separately, in August 2022, the IRA 2022 was signed into law, which amends the CAA to establish the first ever federal fee on methane emissions from sources required to report their GHG emissions to the EPA, including certain oil and gas operations. The methane emissions charge began in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and subsequent years. Calculation of the methane fee is based on certain thresholds established in the IRA 2022. We cannot predict if the Trump Administration and/or Congress may take action to repeal or revise the IRA, including with respect to the methane emissions charge. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our costs of development, which costs could be significant.
Climate change
Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations in which we have a working interest but are not the operator are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHG. At the federal level, no comprehensive climate change law or regulation has been implemented to date, though recently passed laws such as the IRA 2022 advance numerous climate-related objectives. The EPA has also adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years. For more information, see “Part I., Items 1 and 2. Business and Properties-Legislative and regulatory environment-Air emissions.”
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. For example, California, through CARB has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel fuels. Such programs work alongside increased regulation by California seeking to reduce both the supply and demand for fossil fuels in the state, to include, for example, the phasing out of the sale of vehicles with internal combustion engines. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado. Colorado has begun to increasingly regulate oil and gas operations with consideration towards GHG emissions and cumulative impacts. In October 2024, the Colorado Energy and Carbon Management Commission (formerly the Colorado Oil and Gas Conversation Commission) finalized rules that require regulators to consider cumulative impacts of oil and gas operations in permitting decisions and increase scrutiny on the project’s proximity to other industrial sites, residential and school areas, “disproportionately impacted communities,” and “cumulatively impacted communities.” The rules would set GHG emissions intensity targets for oil and gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas.
Internationally, the United Nations-sponsored Paris Agreement requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States had withdrawn from the Paris Agreement, President Biden signed executive orders recommitting the United States to the agreement and, in April 2021, announced a target of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. However, in January 2025, President Trump signed an Executive Order once again withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. Additionally, President Trump revoked any purported financial commitments made by the United States pursuant to the same. The full impact of these recent developments is uncertain at this time, and our consideration of their impact on our operations is ongoing.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States and has included various climate change related pledges and actions. For example, on January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorizations. The pause was intended to provide time to integrate certain considerations, including potential energy cost increases for consumers and manufacturers and the latest assessment of the impact of GHG emissions, to ensure adequate guards against health risks. The DOE finalized its study in December 2024. However, upon taking office, President Trump signed an Executive Order resuming the processing of permit applications for such projects. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts.
There have also been certain financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies concerned about potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies, although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, in March 2024, the SEC released final rules requiring climate
disclosures from registrants, including data on Scope 1 and 2 GHG emissions as well as a registrant’s climate-related business strategy. However, the future of these rules is uncertain at this time given implementation has been stayed pending the outcome of legal challenges; further, it is uncertain whether, under the new Trump Administration, the Commission will change or revoke the rule, though we cannot predict whether such action will occur or its timing. Similarly, in October 2023, the Governor of California signed the Climate Corporate Data Accountability Act (“CCDAA”) and Climate-Related Financial Risk Act (“CRFRA”) into law. The CCDAA requires both public and private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2 and 3 GHG emissions. Both laws are vague and potentially overbroad with respect to their applicability, appearing to require only minimal contacts with California. The CRFRA requires the disclosure of a climate-related financial risk report (in line with the Task Force on the Climate-related Financial Disclosures (“TCFD”) recommendations or equivalent disclosure requirements under the International Sustainability Standards Board’s (“ISSB”) climate-relate disclosure standards) every other year for public and private companies that are “doing business in California” and have total annual revenue of $500 million. Although both laws are subject to litigation and the implementing regulations have yet to be promulgated, reporting under both laws is expected to begin in 2026. California also passed the Voluntary Carbon Market Disclosures Act, which places disclosure obligations on companies that purchase or use voluntary carbon offsets and make “net zero”, “carbon neutral”, or similar claims. This law took effect at the beginning of 2024, but does not specify when a company’s first disclosures are required, though the bill’s sponsor has stated that the intent is for the law to be enforced beginning January 1, 2025. Currently, the ultimate impact of these laws on our business is uncertain-the Governor of California has directed further consideration of the implementation deadlines for the CCDAA and CRFRA-but, absent clarification or revisions to the law, alongside the SEC finalized rule implementation may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to alleged climate-related damages resulting from our operations, statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events (including storms, wildfires, and other natural disasters) or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Hydraulic fracturing
Hydraulic fracturing is a common practice that is used to stimulate production of oil and/or natural gas from low permeability subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the hydrocarbon-bearing rock formation and stimulate production of hydrocarbons. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is primarily regulated at the state level, typically by state oil and natural gas commissions, but the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In addition, there have been heightened concerns by the public about hydraulic fracturing causing damage to aquifers and there is potential for future regulation to address those concerns. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. Additionally, BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. For example, the EPA finalized rules under the CWA in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
Separately, the federal government may also pursue further restriction of hydraulic fracturing and other oil and gas development on federal lands. For example, on January 27, 2021, President Biden issued an executive order that suspended the issuance of new leases for oil and gas development on public lands, but not on existing operations under valid leases or on tribal lands that the federal government merely holds in trust, pending completion of a comprehensive review and reconsideration of the federal
oil and natural gas permitting and leasing practices. This order was later reversed by a federal district court. In response to the executive order, however, in November 2021, the DOI released a report on the federal oil and gas leasing program that included several recommendations for how to reform the program. IRA 2022 responded to one of the report’s recommendations and increased royalty rates, to include onshore royalty rates to 16 ⅔%. Several of the other recommendations, however, require further Congressional action and include, among other items, revising bidding practices to avoid leasing of low potential lands; and performing more meaningful public and tribal consultations regarding the leasing and permitting processes. Provisions of these reforms have been subject to litigation. A portion of our net acreage and total proved reserves are on federal land. Although permit consideration has resumed, we cannot guarantee that further action will not be taken to curtail oil and gas development on federal lands. In April 2024, the BLM finalized a rule to update the fiscal terms of federal oil and gas leases, which increases fees, rents, royalties, and bonding requirements. The rule also adds new criteria for BLM to consider when determining whether to lease nominated land, including the presence of important habitats or wetlands, the presence of historical properties or sacred sites, and recreational use of the land. To the extent we are unable to obtain the leases, permits, or other authorizations required for our operations or business strategy, our business performance and results of operations may be adversely affected.
Separately, in March 2016, the U.S. Occupational Safety and Health Administration issued a final rule to impose stricter standards for worker exposure to silica, which went into effect on June 23, 2021 for hydraulic fracturing employers. We may be required to incur additional costs associated with compliance with these standards.
At the state level, several states, including Texas, have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. For example, Colorado has adopted more stringent setbacks for oil and gas development and, in October 2024, adopted final rules that would apply increased scrutiny to the cumulative impacts of GHG emissions of oil and gas development and set GHG emissions targets for oil and gas operators. In California, Senate Bill No. 1137 was signed into law on September 16, 2022, which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as homes, schools or parks effective January 1, 2023. However, on February 3, 2023, the Secretary of State of California certified a requisite number of signatures collected by proponents of a voter referendum, thereby qualifying the Bill for the November 2024 ballot. In June 2024, the ballot proposal was withdrawn with the proposal’s sponsors instead indicating a view to challenging Senate Bill No. 1137 in court. The provisions of Senate Bill No. 1137 became effective immediately in June 2024. Then, on September 30, 2024, the Governor of California signed into law Assembly Bill 218, which delays the deadline for some compliance with applicable regulations implementing Senate Bill No. 1137 until July 1, 2026 and further delays compliance with certain other requirements of Senate Bill No. 1137 by up to three years. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. For example, in January 2023, the Board of Supervisors of Los Angeles County in California adopted an ordinance prohibiting new oil wells and production facilities in all zones, designating existing oil wells and production facilities as nonconforming uses in all zones and establishing regulations for existing oil wells and production facilities, to include the phasing out of existing operations. Moreover, existing oil and gas facilities within the setback zone in Los Angeles County are impacted by Senate Bill No. 1137. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and attendant permitting delays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential legislation or regulation governing hydraulic fracturing, and any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
Oil Pollution Act
The OPA establishes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties, including owners and operators of certain facilities from which oil is released, related to the prevention of oil spills and liability for damages resulting from such spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill
was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to the NEPA. NEPA requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of an environmental assessment and, if necessary, an environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action have the potential to significantly impact the environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, may increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases. In January 2023, the CEQ released guidance, effective immediately, to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under the NEPA. In May 2024, the CEQ published a final rule which, in the second and final “phase” of updates, revised the implementing regulations of the procedural provisions of NEPA and implemented amendments to NEPA included in the Fiscal Responsibility Act of 2023. More recently, in November 2024, the U.S. Court of Appeals for the D.C. Circuit held that the CEQ lacks authority to issue NEPA regulations. Additionally, upon taking office, President Trump signed an energy-related Executive Order that included ordering the CEQ to propose rescinding its NEPA regulations. As a result, there is currently significant uncertainty with respect to the scope of environmental analysis required under the NEPA.
Endangered Species Act and Migratory Bird Treaty Act
The ESA restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the MBTA. We may conduct operations on natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. For example, in May 2024, the FWS issued a final rule listing the Dunes Sagebrush Lizard as endangered under the ESA and, in November 2022, the FWS formally listed two distinct population segments of the lesser prairie-chicken under the ESA. In August 2020, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. A coalition of states challenged the three rules and, after the final rules were remanded, the FWS and NMFS revised the three rules. The revised regulations for classifying species and designating critical habitat, interagency cooperation, and protecting endangered and threatened species were finalized on April 5, 2024.
The DOI also issued an opinion in December 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In August 2020, the U.S. District Court for the Southern District of New York vacated this opinion as contrary to law. While the FWS subsequently finalized a rule incorporating the DOI opinion, the rule was revoked on October 4, 2021, and FWS returned to pre-2017 implementation of the MBTA, including the ability to enforce the MBTA against accidental harm or death to birds (known as “incidental take”). FWS has published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while also establishing a process to regulate or permit exceptions to such a prohibition. The identification or designation of previously unprotected species, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, as threatened or endangered, or the redesignation of a species from threatened to endangered, in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Related permits, authorizations and considerations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations. In particular, certain areas within California have been subject to significant permitting uncertainty in the past several years, resulting in the delay of receipt of drilling permits.
Worker health and safety
We are subject to a number of federal and state laws and regulations, including the federal OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. For example, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
Related insurance
We maintain insurance against some contamination risks associated with our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material and adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. Investors should read carefully the following factors as well as the cautionary statements referred to in "Cautionary Statement Regarding Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Company's business, financial condition or results of operations could be materially adversely affected.
Risks related to the oil and natural gas industry and our operations
Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition and results of operations, liquidity and our ability to meet our financial commitments or cause us to delay our planned capital expenditures.
Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGL we sell. We require substantial expenditures to replace our oil, natural gas and NGL reserves, sustain production and fund our business plans, including our development plan. Low oil, natural gas and NGL prices resulting from reduced demand, which may be caused by the conflicts in Ukraine and Israel, substitution of renewable forms of energy for oil and gas, actions of OPEC and other factors materially affected our revenues, particularly before the effects of commodity derivatives, operating results and cash flows. Global oil, natural gas and NGL demand may negatively affect the amount of cash available for capital expenditures and debt repayment, our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows. In addition, low prices may reduce the quantities of oil, natural gas and NGL reserves that may be economically produced and result in an impairment of our oil and natural gas properties.
Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. For
example, the respective conflicts between Russia and Ukraine and Israel and Hamas have contributed to significant increases and volatility in the price for oil and natural gas. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL market uncertainty and other factors that are beyond our control, including:
•worldwide and regional economic conditions, including the potential for a global recession, elevated interest rates and associated policies of the Federal Reserve, impacting the supply and demand for oil, natural gas and NGLs;
•changes in seasonal temperatures, including the number of heating degree days during winter months and cooling degree days during summer months;
•U.S. federal, state and local governmental regulation, including any proposed actions and/or tariffs by the new Trump Administration, and taxes;
•the level of oil, natural gas and NGL exploration, development and production;
•the level of oil, natural gas and NGL inventories;
•the level of U.S. LNG exports;
•prevailing prices, and expectations regarding future prices, on local price indexes in the areas in which we operate;
•the proximity, capacity, cost and availability of gathering and transportation facilities;
•localized and global supply and demand fundamentals and transportation availability;
•the cost of exploring for, developing, producing and transporting reserves;
•the spot price of LNG on world markets;
•weather conditions and natural disasters;
•technological advances affecting energy consumption, including those related to new and emerging technologies;
•the price and availability of alternative fuels, including the potential acceleration of the development of alternative fuels;
•speculative trading in oil and natural gas derivative contracts;
•increased end-user conservation;
•political and economic conditions, such as the conflicts in Ukraine and the Middle East, in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;
•political and economic conditions in or affecting major LNG consumption regions or countries, particularly Asia and Europe;
•actions of OPEC, including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls, including the anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia;
•U.S. trade policies, including potential tariffs and their effect on U.S. oil and natural gas exports;
•expectations about future commodity prices; and
•the possibility of terrorist or cyberattacks and the consequences of any such attacks.
We have been negatively affected and may in the future be negatively affected by a drop in commodity prices.
Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. Any drop in commodity prices may adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program, and result in the reduction of some of our PUD reserves and related PV-0 and PV-10. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to meet our financial commitments or cause us to delay our planned capital expenditures.
We have consolidated our business over time through acquisitions, including the Uinta Transaction, the Western Eagle Ford Acquisitions and the SilverBow Merger and there are risks associated with integration of all of these assets, operations and our ability to manage those risks. In addition, we may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any inability to do so may disrupt our business and hinder our ability to grow.
We intend to pursue a strategy focused on both reinvestment and future acquisitions, which is designed to obtain the optimal risk adjusted returns through commodity cycles. Accordingly, in the future we may make acquisitions of businesses, assets or properties that we expect to complement or expand our current assets. For example, in March 2022, we acquired certain exploration and production assets in the state of Utah pursuant to the Uinta Transaction. In 2023 and 2024, we also acquired certain exploration and production assets in the state of Texas pursuant to the Western Eagle Ford Acquisitions and the SilverBow Merger. However, we may not be able to identify attractive acquisition opportunities in the future. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.
The success of any completed acquisition, including the Western Eagle Ford Acquisitions and the SilverBow Merger, will depend on our ability to integrate effectively the acquired business, asset or property into our existing operations. The process of integrating acquired businesses, assets and properties may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. For example, as with other operators in the area, certain potential midstream constraints may create operational challenges for us in the Uinta Basin. The integration of acquisitions is a complex, costly and time-consuming process, and our management may face significant challenges in such process. Some of the factors affecting integration will be outside of our control, and any one of them could result in increased costs and diversion of management’s time and energy, as well as decreases in the amount of expected revenue.
Our failure to achieve consolidation savings, to incorporate the acquired businesses, assets and properties into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material and adverse effect on our financial condition and results of operations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our SEC reserves are based upon average commodity prices over the prior 12 months, which may not reflect actual prices received for our production. For example, our reserve volumes and PV-10 as disclosed in this Annual Report are based on assumed commodity prices of $75.48 per Bbl of oil and $2.13 per MMBtu of natural gas as of December 31, 2024, which, in the case of oil, are higher than the five-year NYMEX forward curve range of $62.75 to $71.54 per Bbl and, in the case of natural gas, below the five-year NYMEX forward curve range of $3.04 to $4.77 per Mcf. Accordingly, you are cautioned not to place undue weight on our reserve volumes or PV-10 based on such pricing when evaluating our financial condition or an investment in our securities. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. The reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, our drilling program, production levels, and operating and development costs. Our ability to develop any identified drilling location is subject to various limitations and any drilling activities we are able to conduct may not be successful. As a result, our actual drilling activities may materially differ from those presently identified and could result in downward revisions of estimated proved reserves. In addition, loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production may occur in certain cases. Production from wellbores may be affected by nearby fracturing activities by offset operators or us, resulting in reserve revisions.
As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. Sustained lower prices will cause the 12-month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced.
Any material inaccuracies in our reserves estimates could also materially affect our borrowing base and liquidity under the Revolving Credit Facility. If the borrowing base under the Revolving Credit Facility decreases as a result of any reductions in our reserve estimates, we may have limited ability to obtain the capital necessary to sustain our operations at current and anticipated future levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all.
The present value of future net revenues from our proved reserves, as reflected in our Standardized Measure, PV-0 value and PV-10 value, will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves, as reflected in our Standardized Measure, PV-0 value and PV-10 value, is the current market value of our estimated oil and natural gas reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. For example, our reserve volumes, PV-0 and PV-10 as disclosed in this Annual Report are based on assumed commodity prices of $75.48 per Bbl of oil and $2.13 per MMBtu of natural gas as of December 31, 2024, which, in the case of oil, is higher than the five-year NYMEX forward curve range of $62.75 to $71.54 per Bbl and, in the case of natural gas, below the five-year NYMEX forward curve range of $3.04 to $4.77 per Mcf. Accordingly, you are cautioned not to place undue weight on our reserve volumes, PV-0 or PV-10 based on such pricing when evaluating our financial condition or an investment in our securities. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:
•actual prices we receive for crude oil, natural gas and NGLs;
•actual cost of development and production expenditures;
•the amount and timing of actual production;
•transportation and processing; and
•changes in governmental regulations or taxation.
The timing of both our production and expenses in connection with the development and production of, and investment in, our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues at PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which may adversely affect our future cash flows and results of operations.
In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration, exploitation, development or reinvestment activities or acquire properties containing proved reserves, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves as well as the pace of D&C of new wells. Additionally, the business of exploring for, exploiting, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited, unavailable or on terms deemed unacceptable by us, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves or to return capital to our investors would be impaired.
As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques as well as enhanced recovery operations. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well or a horizontal well utilizing less advanced techniques and therefore may result in fewer wells being completed or recompleted in any given year. The incremental capital expenditures are generally the result of greater measured depths, additional hydraulic fracture stages in horizontal wellbores and increased volumes of water, CO2 and proppant.
The unavailability or high cost of equipment, supplies, personnel and oilfield services, due to, among other things, potential tariffs, commodity price volatility or supply constraints as a result of the conflicts in Ukraine and the Middle East, elevated, interest rates and associated policies of the Federal Reserve or otherwise could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could materially and adversely affect our anticipated cash flow.
We utilize third-party services to maximize the efficiency of our operation. The cost of oilfield services typically fluctuates based on demand for those services, and the increase in commodity prices and supply constraints due to potential tariffs, the conflicts in Ukraine and the Middle East, elevated interest rates and associated policies of the Federal Reserve or otherwise has increased the cost of oilfield services. While we currently have excellent relationships with oilfield service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material and adverse effect on our business, financial condition or results of operations.
Our development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms or at all, which could lead to a decline in our reserves and cash flows.
The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the development of, and reinvestment in, oil and natural gas reserves. We have historically funded development and operating activities primarily through the sale of our oil, natural gas and NGL production. If necessary, we may also access capital through proceeds from asset dispositions, borrowings under the Revolving Credit Facility and capital markets offerings from time to time. Our cash flow from operations and access to capital are subject to a number of variables, including:
•the amount of oil and natural gas we produce from existing wells;
•the prices at which we sell our production;
•take-away capacity;
•the estimated quantities of our oil and natural gas reserves; and
•our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under the Revolving Credit Facility decrease as a result of lower commodity prices, operating difficulties, production cost increases, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. The Revolving Credit Facility and the documents governing our other indebtedness may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all which could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves, production and cash flows, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our outstanding indebtedness.
The development of our estimated PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUD reserves may not be ultimately developed or produced.
Recovery of PUDs requires significant capital expenditures and successful drilling operations. At December 31, 2024, approximately 182.6 MMBoe of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2024 assumes that we will spend $2.8 billion to develop our estimated PUDs. Although cost and reserve estimates attributable to our oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated PUDs, and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, extended declines in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material and adverse effect on our financial condition, results of operations and future cash flows.
Our development opportunities are scheduled to be developed over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such development. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
As of December 31, 2024, we have undrilled locations, including both PUD drilling locations and unproved drilling locations. These drilling locations represent a meaningful part of our future development strategy. Our ability to drill and develop these drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals, labor, takeaway capacity and other factors. Because of these uncertain factors, we do not know if the drilling locations will ever be developed or if we will be able to produce oil or natural gas from these drilling locations at anticipated levels or at all. In addition, unless production is established within the spacing units covering the undeveloped acreage on which some of the locations are located, the leases for such acreage will expire. Therefore, our actual development activities may materially differ from those presently contemplated.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil and natural gas reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.
Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled. The cost of our drilling, completion and well operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:
•unexpected drilling conditions;
•title problems;
•pressure or irregularities in formations;
•equipment failures or accidents;
•adverse weather conditions, such as winter storms, fires, flooding and hurricanes, and changes in weather patterns;
•compliance with, or changes in, environmental laws and regulations, including the IRA 2022 or as a result of the new Trump Administration, relating to air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on D&C operations and other laws and regulations, such as tax laws and regulations;
•the availability and timely issuance of required governmental permits and licenses; and
•the availability of, costs associated with and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, rail cars, crude oil hauling trucks and qualified drivers and related facilities and equipment to gather, process, compress, transport and market oil, natural gas, NGLs and related commodities.
Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.
We may experience difficulty in achieving and managing future growth.
Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:
•the results of our drilling program;
•hydrocarbon prices;
•our ability to develop existing prospects;
•our ability to continue to retain and attract skilled personnel;
•our ability to maintain or enter into new relationships with project partners and independent contracts; and
•our access to capital.
We may also be unable to make attractive acquisitions or asset exchanges, which could inhibit our ability to grow, or could experience difficulty integrating any acquired assets and operations. It may be difficult to identify attractive acquisition opportunities and, even if such opportunities are identified, our debt agreements (including the indentures that govern the Senior Notes contain limitations on our ability to enter into certain transactions, which could limit our future growth.
Our operations are dependent on third-party service providers.
We contract with third-party service providers to support our operations. These contracted services are generally provided pursuant to master services agreements entered into between the third-party service providers and our operating subsidiaries. Although we have our own employees, our ability to conduct operations and generate revenues is dependent on the availability and performance of those third-party service providers and their compliance with the terms of their respective master service agreements (as further described under "Part III., Item 13. Certain Relationships and Related Party Transactions and Director Independence-KKR Funds"). We cannot guarantee that we will be successful in either retaining the services of our current third-party service providers or contracting with alternative service providers in the event that our current contractors discontinue providing services to us or fail to meet their obligations under their respective master services agreements. Any failure to retain the services of our current service providers or locate alternatives will negatively affect our ability to generate revenues and continue and expand our operations. Please see "Part I., Items 1 and 2. Business and Properties-Employees" for more information.
Inflationary issues and associated changes in monetary policy previously have resulted in and such issues, as well as certain proposed tariffs, may in the future 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.
The U.S. inflation rate began increasing in 2021 and remained elevated throughout 2023. These inflationary pressures resulted in additional increases to the costs of our oilfield goods, services and personnel, which in turn caused our capital expenditures and operating costs to rise. Sustained levels of high inflation during such period likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times during such period. Although the U.S. Federal Reserve reduced benchmark interest rates in 2024, and may continue to reduce rates in 2025, to the extent such rates remain elevated above historic levels, we may continue to experience higher costs and may encounter 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.
Through the Management Agreement, we depend on the Manager and its personnel to manage and operate our business, the loss of any of whom would materially and adversely affect future operations. Additionally, operational risks affecting the Manager, and our ability to work collaboratively with the Manager, including with respect to the allocation of corporate opportunities and other conflicts of interest, may impact our business and have a material effect on our business, financial results and prospects.
Pursuant to our Management Agreement, the Manager provides us with our senior management team and provides certain other management services. However, in each case such resources are not fully dedicated to our assets and operations, and the allocation of such resources is generally within the Manager’s discretion. See "Part III., Item 13. Certain Relationships and Related Party Transactions and Director Independence-Management Agreement.” Accordingly, our success depends on the efforts, experience, diligence, skill and network of business contacts of the Manager’s personnel. We can offer no assurance that the Manager will continue to provide services to us or that we will continue to have access to the Manager’s personnel. The Management Agreement had an initial three-year term, was automatically renewed on December 7, 2024 for an additional three-year term ending December 7, 2027, and will have automatic three-year renewals thereafter. Upon the written notice to the Manager at least 180 days prior to the expiration of the initial term or any automatic renewal term, we may, without cause,
decline to renew the Management Agreement upon the affirmative determination of at least two-thirds of its independent directors reasonably and in good faith, that (1) there has been unsatisfactory long-term performance by the Manager that is materially detrimental to us and our subsidiaries taken as a whole or (2) the fees payable to the Manager, in the aggregate, are materially unfair and excessive compared to those that would be charged by a comparable asset manager managing assets comparable to our assets, subject to Manager’s right to renegotiate the fees. If the Management Agreement is terminated and no suitable replacement is found to provide management and operating services for our oil and natural gas assets, we may not be able to execute our business plan, and our financial condition and results of operation may be materially and adversely affected.
Further, our relationship with the Manager presents certain challenges relating to our ability to work collaboratively with the Manager’s broader business. For example, the Manager will source investment opportunities both for our benefit and for the benefit of other KKR investment vehicles. Pursuant to the Management Agreement, the manager shall ensure that at least 70% of any investment amounts related to upstream oil and gas opportunities are allocated to us. Follow-on investment amounts will be generally allocated between us and EIGF II in proportion to the relative amount such vehicle initially invested in the applicable investment. In addition, from time to time, investment opportunities outside of upstream oil and gas assets may arise that are suitable for investment by us, on the one hand, and by EIGF II (and any successor fund) or other KKR Group funds, on the other, that are (A) engaged in an investment strategy that is materially different from our investment strategy (such as distressed debt or special situations investment vehicles) and (B) have pre-existing defined allocation rights pursuant to the KKR Group’s allocation policies or contractual undertakings agreed with the investors in such other KKR Group funds. In such cases, we may elect to co-invest alongside EIGF II and/or such other KKR Group funds in such investments, in which case the Manager will allocate such investment opportunities among us, on the one hand, and EIGF II and/or such other KKR Group funds, on the other hand, in a manner consistent with the priority investment rights of such KKR Group funds, taking into account such factors as the Manager deems appropriate. We shall have no obligation to make any such co-investment.
In addition, other conflicts of interest may arise from time to time in connection with the investment and other activities of us and other members of the KKR Group. With respect to conflicts involving investment opportunities, the Manager will endeavor to resolve any such conflicts of interest in a fair and equitable manner in accordance with the investment allocation policy described above and its prevailing policies and procedures with respect to conflicts resolution among other members of the KKR Group. However, the Manager may have a fiduciary duty to make decisions in the best interests of the Manager's affiliates, including KKR Funds, which may be contrary to our interests. In addition, other conflicts of interest may arise between us, on the one hand, and the Manager or any other member of the KKR Group and their affiliates, including KKR Funds, on the other hand, which may not be resolved in our favor. Further, the Management Agreement provides that nothing shall prevent the Manager from taking certain actions for the sole benefit of the Manager and/or its affiliates. To the fullest extent permitted by law, the Manager and its affiliates, including but not limited to their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, will not be liable to us or any subsidiary or any of their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, for any acts or omissions by the Manager or its affiliates, including by their respective directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders, and equityholders, performed in accordance with and pursuant to the Management Agreement, except in cases of bad faith, fraud, willful misconduct or gross negligence. The Management Agreement requires us to reimburse, indemnify and hold harmless the Manager, its affiliates, and their respective directors, officers, employees, managers, trustees, control persons, partners, stockholders, and equityholders, and directors, officers, employees, agents, managers, trustees, control persons, partners, stockholders and equityholders of the foregoing from any and all Losses (as defined in the Management Agreement) arising from any proceeding related to us or acts or omissions of the Manager or its affiliates in connection with the Management Agreement, subject to certain exceptions. However, with the exception of the Manager, no other member of the KKR Group assumes any responsibility to render services to us or to consider our interests and our stakeholders in making any investment or other decisions.
Our certificate of incorporation contains a provision that, to the maximum extent permitted under the law of the State of Delaware, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to our officers, directors, the Preferred Stockholder or any partner, manager, member, director, officer, stockholder, employee or agent or affiliate of any such holder. We believe that this provision, which is intended to provide that certain business opportunities are not subject to the “corporate opportunity” doctrine, is appropriate, as the Preferred Stockholder and its affiliates invest in a wide array of companies, including companies with businesses similar to us. As a result of this provision, we may be not be offered certain corporate opportunities which could be beneficial to us and our stockholders.
Properties we have recently acquired or may acquire in the future may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, future oil and gas prices and their applicable differentials, development and operating costs, and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations. For these reasons, the properties we will acquire in connection with any future acquisitions may not produce as expected, which could have a material and adverse effect on our financial condition and results of operations.
Future commodity price declines may result in write-downs of our asset carrying values.
We follow the successful efforts method of accounting for our oil and gas operations. Under this method, all property acquisition cost and cost of exploratory and development wells are capitalized when incurred, pending determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. The capitalized costs of our oil and natural gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated fair value (discounted future net cash flows of that depletion pool). Any such charge will not affect our cash flow from operating activities or liquidity, but will reduce our earnings and investors’ equity.
We may also at times record reporting unit goodwill in connection with a business combination. Goodwill has an indefinite useful life but is tested by us for impairment annually, or more frequently if there are changes in future commodity prices, amongst other factors, that may indicate that the fair value of the reporting unit may have been reduced below its carrying value. If the carrying value of the reporting unit exceeds the fair value, we generally must write down goodwill to the estimated fair value of that reporting unit. Any such charge will not affect our cash flow from operating activities or liquidity but will reduce our earnings and investors’ equity.
A decline in future oil or natural gas prices, or other factors, could cause an impairment write-down of capitalized costs and a non-cash charge against future earnings. For example, 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, and 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 during the year ended December 31, 2023. Additionally, as of December 31, 2024, certain of our non-operated assets had limited cushion between their carrying value and estimated undiscounted cash flows. As a result, 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. Once incurred, a write-down of our assets cannot be reversed at a later date, even if oil or natural gas prices increase.
Our business is subject to operational risks that will not be fully insured. If any of the operational risks materialize our financial condition or results of operations could be materially and adversely affected.
Our business activities are subject to operational risks, including, but not limited to:
•damages to equipment caused by natural disasters such as earthquakes, and adverse weather conditions, including tornadoes, wildfires, hurricanes, extreme weather events and flooding;
•facility or equipment malfunctions;
•pipeline ruptures or spills;
•surface fluid spills, produced water contamination and salt water, surface or groundwater contamination resulting from petroleum constituents or hydraulic fracturing chemical additions;
•fires, blowouts, craterings and explosions; and
•uncontrollable flows of oil, natural gas or well fluids.
Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension or termination of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.
As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material and adverse effect on our business, financial condition and results of operations.
We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us, particularly following recent consolidation within the industry. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce oil and natural gas, but they also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. Our competitors may be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipelines and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas properties, oil and natural gas companies, and drilling rights. Our inability to compete effectively with our competitors could have a material and adverse impact on our business activities, financial condition and results of operations.
Deficiencies of title to our leased interests could materially and adversely affect our financial condition.
If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.
Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the leasehold. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leaseholds may adversely impact our ability in the future to increase production and reserves.
Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our properties as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. We are also subject to certain ordinances and restrictions promulgated by the Ute Indian Tribe as it relates to our operations in Uinta
Basin. The costs we incur to comply with such restrictions may be significant and our development and production activities may be delayed, curtailed or precluded by such restrictions.
Part of our business strategy will involve using some of the latest available horizontal D&C techniques, which involve risks and uncertainties in their application.
Our operations will involve utilizing some of the latest D&C techniques as developed by us and our service providers. The difficulties we may face drilling horizontal wells include:
•landing our wellbore in the desired drilling zone;
•staying in the desired drilling zone while drilling horizontally through the formation;
•running our casing through the entire length of the wellbore; and
•being able to run tools and other equipment consistently through the horizontal wellbore.
The difficulties that we will likely face while completing wells include the following:
•the ability to fracture stimulate the planned number of stages;
•the ability to run tools the entire length of the wellbore during completion operations; and
•the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
Use of new technologies may not prove successful and could result in significant cost overruns or delays or reductions in production, and, in extreme cases, the abandonment of a well. In addition, certain of the new techniques we adopt may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer and emerging formations and areas have limited or no production history and, consequently, we will be more limited in assessing future drilling results in these areas. If its drilling results are less than anticipated, the return on investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of undeveloped acreage could decline in the future.
We may encounter obstacles to marketing our oil and natural gas, which could materially and adversely affect our revenues.
The marketability of our production depends in part upon the availability and capacity of oil and natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities, weather-related operational issues, or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.
In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our acreage, could materially and adversely affect our financial condition, results of operations and cash available for distribution.
We are not the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets and could be liable
for certain financial obligations of the operators or any of our contractors to the extent such operator or contractor is unable to satisfy such obligations.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We do not operate 100% of the total net undrilled locations, and there is no assurance that we will operate all of our other future drilling locations. As a result, we have limited ability to influence or control the operation or future development of certain of these properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties, subject to certain of our election rights. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties in which we own an interest during periods of lower crude oil or natural gas prices. Furthermore, the success and timing of development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
•the timing and amount of capital expenditures;
•the operator’s expertise and financial resources;
•the approval of other participants in drilling wells;
•the selection of technology; and
•the rate of production of reserves, if any.
This limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in development or acquisition activities. Further, we may be liable for certain financial obligations of the operator of a well in which we own a working interest to the extent such operator becomes insolvent and cannot satisfy such obligations. Similarly, we may be liable for certain obligations of contractors to the extent such contractor becomes insolvent and cannot satisfy their obligations. The satisfaction of such obligations could have a material and adverse effect on our financial condition. For more information, see "Items 1 and 2. Business and Properties" and "Part II., Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations."
Risks related to regulatory matters
The Inflation Reduction Act of 2022 imposed new costs on our operations and might contribute to an acceleration in the transition to a low carbon economy.
On August 16, 2022, former President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022”) into law pursuant to the budget reconciliation process. 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 the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA 2022 amends the federal CAA to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge began in calendar year 2024 and the fee is based on certain thresholds established in the IRA 2022. We cannot predict whether, how, or when the Trump Administration might take action to revise or repeal the methane emissions charge. Additionally, Congress may take actions to repeal the IRA 2022, including with respect to the methane emissions charge, which timing or outcome similarly cannot be predicted. To the extent that the methane emissions charge is implemented as originally promulgated, as well as any other provision of the IRA 2022, it could increase our operating costs and adversely affect our business and results of operations.
Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, transmission, storage and processing facilities to market our production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.
The marketing of oil and natural gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, as well as the existence of adequate markets. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Additionally, new fields may require the construction of gathering systems and other transportation facilities. These facilities may require us to spend significant capital that would otherwise be spent on drilling. We rely, and expect to rely in the future, on facilities developed and owned by third parties in order to store, process, transmit and sell our production. Our plans to develop and sell our reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could materially and adversely affect our ability to produce and market oil and natural gas.
Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the NGA as well as under Section 311 of the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.
Our sales of oil and NGLs are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and NGLs by pipelines are regulated by FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and NGL pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and NGL pipeline rates. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
As an alternative to pipeline transportation, any transportation of our crude oil and NGLs by rail will also be subject to regulation by the PHMSA and the FRA of the DOT under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have a material and adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions that could result in restrictions on water use. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas in the affected areas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.
We may face unanticipated water and other waste disposal costs.
We may be subject to regulation that restricts our ability to discharge water produced as part of our production operations. Productive zones frequently contain water that must be removed in order for the oil and natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce oil and
natural gas in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:
•we cannot obtain future permits from applicable regulatory agencies;
•water of lesser quality or requiring additional treatment is produced;
•our wells produce excess water;
•new laws and regulations require water to be disposed in a different manner; or
•costs to transport the produced water to the disposal wells increase.
The disposal of fluids gathered from oil and natural gas producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. Several states have adopted or are considering adopting laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in December 2021 the TRC issued a notice to suspend the permit of all deep disposal wells within the Northern Culberson-Reeves Seismic Response Area. Similarly, in Oklahoma, the Oklahoma Corporation Commission has at times limited drilling or ordered wells to be shut down in response to seismic activity. In November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. While we cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other oilfield fluids may increase our costs or have other adverse impacts on our operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company as defined under that statute. We believe that the Springfield Gathering System, Lost Creek Gathering System, and DJ Basin Erie Hub Gathering System in which we own interests meet the traditional tests FERC has used to establish a pipeline’s status as a gathering pipeline not subject to regulation by FERC. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is fact intensive and the subject of ongoing litigation, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or the U.S. Congress. If FERC were to consider the status of the gathering system and determine that it is subject to FERC regulation, the rates for, and terms and conditions of, services provided by that gathering system would be subject to modification by FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and adversely affect our business, financial condition, and results of operations.
Our natural gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transmission services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities, and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs. Other FERC regulations may indirectly affect our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas and liquids regulatory activities, including, for example, its policies on open access transportation, natural gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas and liquids
markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas and liquids pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.
We have an interstate liquids pipeline that is considered a common carrier pipeline subject to regulation by FERC under the ICA. Unless we obtain a waiver of the applicable provisions, the ICA requires that we maintain tariffs on file with FERC for interstate movements of liquids on our pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. Further, FERC’s scrutiny of transportation service agreements between an ICA jurisdictional pipeline and affiliated shippers or marketers under the just and reasonable and non-discriminatory standard is evolving. The ICA permits interested persons to challenge proposed new or changed rates or rules, and authorizes FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. Upon completion of such an investigation, FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest. FERC may also investigate, upon complaint or on its own motion, rates and related rules that are already in effect, and may order a carrier to change them prospectively. Upon an appropriate showing, a shipper may obtain reparations (including interest) for damages sustained for a period of up to two years prior to the filing of its complaint. Changes in FERC’s methodologies for approving rates and the treatment of agreements with affiliated shippers could adversely affect us. Further, challenges to our regulated rates could be filed with FERC and future decisions by FERC regarding our regulated rates and agreements with affiliated shippers could adversely affect our cash flows. We cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines. For more information, see “Items 1 and 2. Business and Properties-Legislative and regulatory environment.”
The classification of some of our gathering facilities, transportation pipelines, and purchase and sale transactions as FERC-jurisdictional or non-jurisdictional may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.
In addition, the pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the DOT through PHMSA. PHMSA has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. These standards may be revised by PHMSA over time. For example, in October 2019, PHMSA published three final rules that create or expand reporting, inspection, maintenance, and other pipeline safety obligations. As part of the Consolidated Appropriations Act of 2021, the U.S. Congress reauthorized PHMSA through 2023 and directed the agency to move forward with several regulatory actions, including but not limited to the issuance of final regulations to require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations. PHMSA has issued various rules to address certain of these requirements. For example, in January 2025, PHMSA finalized a rule to address the management of methane emissions through more stringent leak detection and repair requirements, among other matters. However, the Trump Administration's position on such ruling is currently unknown and we cannot predict any reaction of the Trump Administration with respect to such ruling. Notwithstanding this, PHMSA is continuing to work on developing additional regulations related to safety oversight of gas gathering pipelines, and additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. As of December 28, 2023, the maximum civil penalties PHMSA can impose are $266,015 per violation per day, with a maximum of $2,660,135 for a related series of violations.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Domenici-Barton Energy Policy Act of 2005 ("EPAct 2005"), FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1,584,648 per day (adjusted annually for inflation) for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. The EPAct 2005 also authorized FERC to impose civil penalties for violations of the ICA and FERC regulations thereunder, up to a maximum amount that is adjusted annual for inflation, which for 2025 equals $16,590 per day, per violation. Additional rules and legislation pertaining to those and other matters may be considered or
adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Items 1 and 2. Business and Properties - Legislative and regulatory environment.”
Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.
Sales of oil natural gas and NGLs are not currently regulated and are made at negotiated prices. However, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations.
Additionally, FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. These agencies have substantial enforcement authority, including the ability to impose penalties for current violations of $1,584,648 per day (adjusted annually for inflation) by FERC, $1,487,712 (adjusted annually for inflation) by the CFTC, and $1,510,803 (adjusted annually for inflation) by the FTC, for each violation. The FERC has also imposed requirements related to reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to these and other matters may be considered or adopted from time to time. Our failure to comply with these or other laws and regulations administered by these agencies could subject us to criminal and civil penalties, as described in "Items 1 and 2. Business and Properties-Legislative and regulatory environment." Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.
The adoption of derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have a material and adverse effect on our ability to hedge risks associated with our business.
Title VII of Dodd-Frank establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.
In one of its rulemaking proceedings still pending under Dodd-Frank, the CFTC issued on January 30, 2020, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including oil and natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued.
The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief-until August 12, 2025-from various conditions and requirements in the final aggregation rules. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.
The CFTC issued a final rule on the amount of capital certain swap dealers and major swap participants are required to set aside with respect to their swap business on July 22, 2020. This rule may require our swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions.
The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements
for other types of swap transactions. Dodd-Frank also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.
All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. The Volcker Rule provisions of Dodd-Frank may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.
As a result, Dodd-Frank and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.
If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on our consolidated financial condition, results of operations or cash flows.
Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental laws or regulations or a release of hazardous substances or other wastes into the environment.
We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:
•the CAA, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring and reporting requirements and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;
•the CWA, which regulates discharges of pollutants from facilities to state and federal waters and establish the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
•the OPA, which imposes liabilities for removal costs and damages arising from an oil spill into waters of the United States;
•the SDWA, which protects the quality of the nations’ public drinking water through adoption of drinking water standards and control over the subsurface injection of fluids into belowground formations;
•the RCRA, which imposes requirements for the generation, treatment, storage, transport disposal and cleanup of non-hazardous and hazardous wastes;
•the CERCLA, which imposes liability without regard for fault on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur, as well as on present and certain past owners and operators of sites were hazardous substance releases have occurred or are threatening to occur;
•the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories; and
•the ESA, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas. Similar protections are afforded to migratory birds under the MBTA.
These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases to surface and below-ground soils and ground water. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective actions obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Compliance with more stringent standards and other environmental regulations could restrict our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant. Certain environmental laws and analogous state laws and regulations impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. In addition, these laws and regulations may restrict the rate of oil or natural gas production. Historically, our environmental compliance costs have not had a material and adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material and adverse effect on our business and operating results.
We are subject to complex federal, state, local and other laws and regulations that could materially and adversely affect the cost, manner or feasibility of conducting our operations.
Our oil and natural gas operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material and adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.
We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be materially and adversely affected.
For example, the TRC has adopted rules and regulations implementing legislation mandating certain clean-up activities for inactive wells and additional requirements related to the approval of plugging extensions. Failure to comply can result in administrative penalties and the loss of an operator’s ability to conduct operations in Texas. A major component of the law is Rule 15, which requires a well operator to comply with certain inactive well clean-up activities, including the disconnection of electricity, purging of all production fluids from inactive lines and tanks and removal of surface equipment for wells that have not produced oil or gas during the preceding year. Noncompliance with Rule 15 could result in administrative penalties of up to $10,000 per violation per day and the loss of an operator’s ability to conduct operations in Texas.
Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. Various proposals and proceedings that might affect the petroleum industry are pending before the U.S. Congress, FERC, various state legislatures and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by FERC and the U.S. Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.
Fuel conservation measures, alternative fuel requirements, elevated consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and incentives or funding for renewable energy projects included in governmental regulations, such as those contained in the IRA 2022, could reduce demand for oil and natural gas. The impact of any changing demand for oil and natural gas may have a material and adverse effect on our business, financial condition, results of operations and cash flows.
Our operations are subject to a series of risks arising from climate change.
Climate change continues to attract considerable public and scientific attention. As a result, our operations as well as the operations of our non-operated assets are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHG. At the federal level, no comprehensive climate change law or regulation has been implemented to date, though the IRA 2022 advances numerous climate related objectives. The EPA has, however, adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, and together with DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal regulation of methane emissions from oil and gas facilities has been subject to controversy in recent years the Trump Administration’s position on such regulations its reaction to such regulations is currently unknown. For more information, see "Items 1 and 2. Business and Properties-Legislative and regulatory environment-Air emissions."
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. For example, California, through CARB, has implemented a cap and trade program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030. Covered entities must either reduce their GHG emissions or purchase allowances to account for such emissions. Separately, California has implemented LCFS and associated tradable credits that require a progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel fuels. Such programs work
alongside increased regulation by California seeking to reduce both the supply and demand for fossil fuels in the state, to
include, for example, the phasing out of the sale of vehicles with internal combustion engines. CARB has also promulgated regulations regarding monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and gas production facilities. Similar regulations applicable to oil and gas facilities have been promulgated in Colorado. Colorado has begun to increasingly regulate oil and gas operations with consideration towards GHG emissions and cumulative impacts. In October 2024, the Colorado Energy and Carbon Management Commission finalized rules that require regulators to consider cumulative impacts of oil and gas operations in permitting decisions and increase scrutiny on the project’s proximity to other industrial sites, residential and school areas, “disproportionately impacted communities,” and “cumulatively impacted communities.” The rules also set GHG emissions intensity targets for oil and gas operators and require regulators to consider such targets in their cumulative impacts analysis, as well as the potential to restrict operations during the summer in Ozone Nonattainment Areas.
Furthermore, we have been and could be impacted in the future by the effects of winter weather and the weatherization of our facility equipment and the equipment of counterparties in anticipation of future climactic events. For example, in the winter of 2022, certain of our surface facilities in South Texas were impacted by abnormal winter conditions that temporarily adversely affected our production. In addition, in response to Winter Storm Uri, the TRC was directed to adopt rules requiring certain natural gas processing, storage, and pipeline facility operators experiencing major or repeated weather-related forced interruptions of service to, among other things, engage an independent party to assess the operator’s weatherization plans, procedures and operations, and submit the assessment to the TRC. In August 2022, the TRC adopted the Weather Emergency Preparedness Standards Rule, which requires critical gas facilities on the state’s Electricity Supply Chain, including natural gas processing, storage, and pipeline facilities, to (i) weatherize to help ensure sustained operations during a weather emergency; (ii) correct known issues that caused weather-related forced stoppages; and (iii) contact the TRC if a facility sustains a weather-related forced stoppage during a weather emergency. In addition, weather-related forced stoppages at processing, storage and pipeline facilities operated by counterparties with which we contract for services may also adversely affect our operations and financial results.
Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emission reduction targets every five years after 2020. Although the United States withdrew from the agreement, President Biden signed executive orders recommitting the United States to the agreement and, in April 2021, announced a target of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. However, in January 2025, President Trump signed an Executive Order once again withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. Additionally, President Trump revoked any purported financial commitments made by the United States pursuant to the same. The full impact of these recent developments is uncertain at this time.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States and has included various climate change related pledges and actions. For example, in January 2024, the Biden Administration temporarily paused pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with. However, upon taking office in January 2025, President Trump signed an Executive Order resuming the processing of permit applications for such projects. For more information, see our regulatory
disclosure in “Items 1 and 2. Business and Properties.” Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. There have also recently been certain increasing financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies concerned about potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies, although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, in March 2024, the SEC released a final rule requiring climate-related disclosures from registrants, including data on Scope 1 and 2 GHG emissions as well as any set climate-related targets and goals. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges; moreover, it is uncertain whether, under the new Trump Administration, the SEC will change or revoke the rule, and we cannot predict whether such action will occur or its timing. If the final rules are implemented as currently written, we also cannot predict how such disclosures may be considered by financial institutions and investors when making investments decisions, and it is possible that we could face increased costs or restrictions on our access to capital.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events (including storms, wildfires, and other natural disasters) or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact our supply chain or infrastructure on which we rely to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. We and the operators of our properties regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. The U.S. Congress from time to time has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed.
Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. For example, in June 2016, the EPA published an effluent limitations guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. To date, EPA has taken no further action in response to the December 2016 report.
In addition, the BLM finalized a rule in April 2024 updating the fiscal terms of oil and gas leases on federal lands and the criteria BLM considers when determining whether to lease nominated land. For more information, see our regulatory disclosure in "Items 1 and 2. Business and Properties-Legislative and regulatory environment-Hydraulic fracturing."
In addition, some states, including Texas, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail or
in some cases prohibit hydraulic fracturing. For example, Colorado has adopted more stringent setbacks for oil and gas development and, in October 2024, adopted final rules that would apply increased scrutiny to the cumulative impacts of GHG emissions of oil and gas development and set GHG emissions targets for oil and gas operators. In California, Senate Bill No. 1137 was signed into law on September 16, 2022, which establishes 3,200 feet as the minimum distance between new oil and gas production wells and certain sensitive receptors such as home, schools or parks effective January 1, 2023. However, on February 3, 2023, the Secretary of State of California certified a requisite number of signatures collected by proponents of a voter referendum, thereby qualifying the Bill for the November 2024 ballot. In June 2024, the ballot proposal was withdrawn with the proposal’s sponsors instead indicating a view to challenging Senate Bill No. 1137 in court. The provisions of Senate Bill No. 1137 became effective immediately in June 2024. In September 2024, the Governor of California signed into law Assembly Bill 218, which delays the deadline for some compliance with applicable regulations implementing Senate Bill No. 1137 until July 1, 2026, and further delays compliance with certain other requirements of Senate Bill No. 1137 by up to three years. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material and adverse effect on our business, prospects, financial condition, results of operations and liquidity.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as those restrictions imposed under the federal ESA and MBTA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist, such as the dunes sagebrush lizard, lesser prairie chicken, and greater sage grouse, and where other species that potentially could be listed as threatened or endangered under the ESA may exist. In May 2024, the FWS issued a final rule listing the dunes sagebrush lizard as endangered under the ESA and, in November 2022, the FWS listed two distinct population segments of the lesser prairie-chicken under the ESA. Additionally, the Biden Administration took action to broaden enforcement under the ESA, including expanding the definition of “critical habitat.” The designation of previously unprotected species in areas where we operate as threatened or endangered, a recategorization of a species from threatened to endangered, or an expansion of areas designated as “critical habitat” could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves. To the extent species are listed or critical habitats are designated under the ESA or similar laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.
Increased attention to sustainability-related matters and conservation measures may adversely impact our business.
Increased attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary sustainability disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increased attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Moreover, while we may create and publish voluntary disclosures regarding sustainability-related matters from time to time, many of the statements in those voluntary disclosures are based on expectations and assumptions and hypothetical scenarios that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring and reporting on many sustainability-related matters. We may also announce participation in, or certification under, various third-party sustainability or climate-related frameworks in an attempt to improve our sustainability
profile, but such participation or certification may be costly and may not achieve the desired results. Additionally, while we may announce various voluntary climate or sustainability-related targets, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our environmental impact instead of actual changes in our environmental performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the demand from numerous businesses implementing net zero goals, or that offsets we do purchase will successfully achieve the emissions reductions they represent. Also, despite these aspirational goals and any other actions taken, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other sustainability-related goals, but we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings and any recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects. Additionally, to the extent sustainability-related matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. sustainability-related matters may also impact our suppliers and customers, which may ultimately have adverse impacts on our operations.
Furthermore, certain public statements with respect to sustainability matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential benefits. For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including greenwashing. Certain regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals or standards were misleading, false or otherwise deceptive. Certain employment practices and social initiatives are the subject of scrutiny by both those advocating for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various governmental agencies. Such sentiment may focus on the Company’s environmental or social commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives that are alleged to be political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Company’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties. As a result, we may face increased litigation risk from private parties and governmental authorities related to our sustainability-related efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. In addition, certain institutions have also undertaken anti-ESG initiatives focused around their view of the politicization of ESG issues. We could face increasing costs as we attempt to comply with and navigate further regulatory sustainability-related focus and scrutiny.
Risks related to our indebtedness
We are partially dependent on our Revolving Credit Facility and continued access to capital markets to successfully execute our operating strategies.
If we are unable to make capital expenditures or acquisitions because we are unable to obtain capital or financing on satisfactory terms, we may experience a decline in our oil and gas production rates and reserves. We are partially dependent on external capital sources to provide financing for certain projects. The availability and cost of these capital sources is cyclical, and these capital sources may not remain available, or we may not be able to obtain financing at a reasonable cost in the future. Elevated interest rates may increase the cost of capital and prevent us from being able to obtain debt financing at favorable rates, or at all, which would materially impact our operations. In addition, conditions in the global capital markets have been volatile due to among other things, the conflicts in Ukraine and Israel, making terms for certain types of financing difficult to
predict, and in certain cases, resulting in certain types of financing being unavailable. If our revenues decline as a result of lower oil, gas or NGL prices, operating difficulties, declines in production or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our failure to obtain additional financing could result in a curtailment of our operations or not make acquisitions, which in turn could lead to a possible reduction in our oil or gas production, reserves and revenues, not having sufficient liquidity to meet future financial obligations and could negatively impact our results of operations.
We have incurred significant additional indebtedness during recent periods, which may impair our ability to raise further capital or impact our ability to service our debt.
We have incurred significant additional indebtedness during recent periods. Our additional indebtedness may impair our ability to raise further capital, including to expand our business, pursue strategic investments, and take advantage of financing or other opportunities that we believe to be in the best interests of the Company and our shareholders.
Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, curtailing spending, restructuring debt, or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time. Our additional indebtedness may also impact our ability to service our debt and to comply with financial covenants and the other terms of our relevant credit arrangements, in which case our lenders might pursue available remedies up to and including terminating our credit arrangements and foreclosing on available collateral.
A reduction in the borrowing base under our Revolving Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our primary sources of liquidity are borrowings under our Revolving Credit Facility, cash from operations and proceeds from equity and debt offerings. The borrowing base under our Revolving Credit Facility is subject to semi-annual redeterminations which occur on or about April 1 and Oct 1 of each year. During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Revolving Credit Facility. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan, many of which factors are beyond our control.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
The borrowings under our Revolving Credit Facility expose us to interest rate risk.
We are exposed to interest rate risk associated with borrowings under our Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted SOFR(as defined below)), plus an applicable margin or SOFR, plus an applicable margin, at the election of the borrowers. As a result of our variable interest debt, our results of operations could be adversely affected by increases in interest rates.
Risks related to our common stock
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A Common Stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A Common Stock.
An active, liquid and orderly trading market for our Class A Common Stock may not be maintained.
Our Class A Common Stock trades on the NYSE under the ticker "CRGY." However, an active, liquid and orderly trading market for our Class A Common Stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. Consequently, you may not be able to sell shares of our Class A Common Stock at prices equal to or greater than the assumed price attributable to such shares. The stock markets in general have experienced extreme volatility that has often been unrelated or disproportionate to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us could result in very substantial costs, divert management’s attention and resources and harm our business, operating results and financial condition.
Future sales of our Class A Common Stock in the public market, or the perception that such sales may occur, could reduce the price of our Class A Common Stock, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We may sell additional shares of our Class A Common Stock in subsequent offerings. In addition, subject to certain limitations and exceptions, OpCo Unit Holders may redeem their OpCo Units (together with a corresponding number of shares of our Class B Common Stock) for shares of our Class A Common Stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions) and then sell those shares of our Class A Common Stock. At December 31, 2024, we had 187,070,725 outstanding shares of Class A Common Stock and 65,948,124 outstanding shares of Class B Common Stock. Independence’s former owners own all of the outstanding shares of our Class B Common Stock, representing approximately 26% of our total outstanding common stock at such date.
Pursuant to the 2021 Registration Rights Agreement and the Ridgemar Registration Rights Agreement, we have registered for resale all of the shares of our Class A Common Stock (including shares of Class A Common Stock to be issued upon redemption of a corresponding number of Class B Common Stock) held by the former owners of Independence and Ridgemar. The 2021 Registration Rights Agreement provides for additional demand and "piggyback" rights that would facilitate future sales of our Class A Common Stock in the public market. In addition to sales pursuant to such registration by selling stockholders, certain of our significant stockholders, including certain of Independence's former owners, have distributed shares of our securities that they hold to their investors who themselves may then sell into the public market. Any sales of such securities may depress the price of our shares. Furthermore, we filed registration statements with the SEC on Form S-8 providing for the registration of 6,520,410 shares of our Class A Common Stock issued or reserved for issuance under the Equity Incentive Plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144 under the Securities Act of 1933, as amended, shares registered under the registration statement on Form S-8 have been made available for resale immediately in the public market without restriction.
We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition and/or sales by our existing stockholders in the public or private markets), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock and may impair our ability to raise capital through future offerings.
If securities or industry analysts do not continue to publish research or reports about our business, if they adversely change their recommendations regarding our Class A Common Stock or if our operating results do not meet their expectations, the trading price of our Class A Common Stock could decline.
The trading market for our Class A Common Stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of us or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrades our Class A Common Stock or if our operating results do not meet their expectations, the trading price of our Class A Common Stock could decline.
Risks related to our financial condition
Our hedging activities could result in financial losses or could reduce our net income.
We enter into derivative instrument contracts for a significant portion of our existing production. We plan to continue the practice of entering into hedging arrangements to reduce near-term exposure to commodity prices, protect cash flow and returns and maintain our liquidity.
Our hedging contracts may result in substantial gains or losses. For example, we had realized commodity derivative losses of $35.9 million in 2024, and we may realize additional substantial future losses due to our hedging activities. In addition, if we enter into any hedging contracts and experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.
Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. In the future, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.
Our price hedging strategy and future hedging transactions will be determined at our discretion. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price fluctuations.
Our hedging transactions could expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the historical disruptions that have occurred in the financial markets and the significant decline in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.
During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Certain employees of our operating subsidiaries have profits interests that may require substantial payouts and result in substantial accounting charges.
Certain employees of our operating subsidiaries have profits interests that may require substantial payouts, particularly upon liquidation of any such operating subsidiary or a disposition of assets, and may result in substantial accounting charges. Such payouts are linked to the achievement of certain return thresholds and would be paid in the event of such liquidation or disposition in a proportionate amount to the amount of cash received in respect of such liquidation or disposition. For additional information, please read "Part II., Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-General and Administrative Expense" and NOTE 13 - Equity-Based Compensation Awards in the notes to our audited financial statements for the year ended December 31, 2024 included herein.
Our only principal asset is our interest in OpCo; accordingly, which in turn holds interests in our operating subsidiaries; we depend on distributions and other payments from OpCo and our operating subsidiaries, the amount of which will depend on various factors.
We are a holding company and have no material assets other than our ownership interest in OpCo, which in turn holds interests in our operating subsidiaries. We have no independent means of generating revenue or cash flow and we anticipate that the only source of our earnings will be cash distributions from our operating subsidiaries. Because we have no independent means of generating revenue, our ability to make tax payments and payments under the Management Agreement is dependent on the ability of OpCo to make distributions to us in an amount sufficient to cover such obligations. This ability, in turn, depends on the ability of our operating subsidiaries to make distributions to OpCo.
The ability of OpCo, our operating subsidiaries and other entities in which OpCo directly or indirectly holds an equity interest to make such distributions will be subject to, among other things, (i) the applicable provisions of Delaware law (or other applicable jurisdiction) that may limit the amount of funds available for distribution and (ii) restrictions in relevant debt instruments of OpCo or its subsidiaries and other entities in which OpCo directly or indirectly holds an equity interest, including any restrictions on the payment of distributions required under the Revolving Credit Facility. In addition, we do not wholly own certain of our operating subsidiaries. As a result, if such operating subsidiaries make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners. The amount of cash that our operating subsidiaries can distribute each quarter to their owners principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things, the amount of oil and natural gas our operating subsidiaries produce from existing wells; our operating subsidiaries’ ability to fund their drilling and development plans; the levels of investments in each of our operating subsidiaries, which may be limited and disparate; and prevailing economic conditions, including the supply of, or demand for, oil, natural gas and NGLs.
To the extent OpCo has available cash and subject to the terms of any current or future indebtedness agreements, we intend to cause OpCo (i) to make pro rata cash distributions to holders of OpCo Units, including us, in an amount sufficient to allow us to pay our taxes and to make payments under the Management Agreement and (ii) to make payments to us to reimburse us for our corporate and other overhead expenses. We generally expect OpCo to fund such distributions and payments out of available cash. When OpCo makes distributions, the holders of OpCo Units will be entitled to receive proportionate distributions based on their interests in OpCo at the time of such distribution. To the extent that we need funds and OpCo or our operating subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any current or future indebtedness agreements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.
Risks related to our governance structure
We are a “controlled company” within the meaning of NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements.
Because the Preferred Stockholder is the sole owner of our Non-Economic Series I Preferred Stock and accordingly has the exclusive right to appoint our Board of Directors, we are a controlled company under the Sarbanes-Oxley Act and NYSE rules. A controlled company does not need its board of directors to have a majority of independent directors or to form an independent compensation or nominating and corporate governance committee. As a controlled company, we will remain subject to rules of the Sarbanes-Oxley Act and the NYSE that require us to have an audit committee composed entirely of independent directors.
If at any time we cease to be a controlled company, we will take all action necessary to comply with the Sarbanes-Oxley Act and NYSE rules, including ensuring that our Board of Directors has a majority of independent directors and ensuring that our Compensation Committee and Nominating & Governance Committee are each composed entirely of independent directors, subject to a permitted “phase-in” period.
Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed
by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our Certificate of Incorporation or our Bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our restated Certificate of Incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Our Preferred Stockholder’s significant voting power limits the ability of holders of our common stock to influence our business.
Our Preferred Stockholder is the sole holder of our Non-Economic Series I Preferred Stock and is expected to retain its ownership of our Non-Economic Series I Preferred Stock until such time as it ceases to own more than 14,369,367 shares of Common Stock, subject to certain exceptions. Our Non-Economic Series I Preferred Stock entitles the holder thereof to appoint our entire Board of Directors and to certain other to approval rights with respect to certain fundamental corporate actions, including debt incurrence in excess of 10% of then outstanding indebtedness, significant equity raises, preferred equity issuances, adoption of a shareholder rights plan, amendments of our certificate of incorporation and certain sections of its bylaws, a sale of all or substantially all of our assets, mergers involving us, removals of our Chief Executive Officer and the liquidation or dissolution of us. Unlike common equity in traditional corporate structures, holders of our common stock will not vote for the election of directors. As a result, holders of our common stock will have less ability to influence our business than would the holders of common equity in a traditional corporate structure.
The Preferred Stockholder’s controlling ownership position may have the effect of delaying or preventing changes in control or changes in management and may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.
Given its ownership of our Non-Economic Series I Preferred Stock, the Preferred Stockholder would have to approve any potential acquisition of us. The existence of a controlling shareholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in our best interests. Moreover, the Preferred Stockholder’s controlling ownership position may adversely affect the trading price of our Class A Common Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder, whether due to a decreased likelihood of a sale of us at a premium to the then-existing trading price of our Class A Common Stock or otherwise.
Our Certificate of Incorporation provides that the Preferred Stockholder is, to the fullest extent permitted by law, under no obligation to consider the separate interests of the other stockholders and will contain provisions limiting the liability of the Preferred Stockholder.
To the fullest extent permitted by applicable law, our Certificate of Incorporation contains provisions limiting the duties owed by the Preferred Stockholder and contain provisions allowing the Preferred Stockholder to favor its own interests and the interests of its controlling persons over us and the holders of our common stock. Our Certificate of Incorporation contains provisions stating that the Preferred Stockholder is under no obligation to consider the separate interests of the other stockholders (including the tax consequences to such stockholders) in deciding whether or not to authorize us to take (or decline to authorize us to take) any action as well as provisions stating that the Preferred Stockholder shall not be liable to the other stockholders for damages or equitable relief for any losses, liabilities or benefits not derived by such stockholders in connection with such decisions.
Our Certificate of Incorporation contains a provision renouncing our interest and expectancy in certain corporate opportunities that may prevent us from receiving the benefit of certain corporate opportunities.
The “corporate opportunity” doctrine provides that corporate fiduciaries, as part of their duty of loyalty to the corporation and its stockholders, may not take for themselves an opportunity that in fairness should belong to the corporation. As such, a corporate fiduciary may generally not pursue a business opportunity which the corporation is financially able to undertake and which, by its nature, falls into the line of the corporation’s business and is of practical advantage to it, or in which the corporation has an actual or expectant interest, unless the opportunity is disclosed to the corporation and the corporation
determines that it is not going to pursue such opportunity. Section 122(17) of the DGCL, however, expressly permits a Delaware corporation to renounce in its certificate of incorporation any interest or expectancy of the corporation in, or in being offered an opportunity to participate in, specified business opportunities or specified classes or categories of business opportunities that are presented to the corporation or its officers, directors or stockholders.
Our Certificate of Incorporation contains a provision that, to the maximum extent permitted under the law of the State of Delaware, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, business opportunities that are from time to time presented to its officers, directors, the Preferred Stockholder or any partner, manager, member, director, officer, stockholder, employee or agent or affiliate of any such holder. We believe that this provision, which is intended to provide that certain business opportunities are not subject to the “corporate opportunity” doctrine, is appropriate, as the Preferred Stockholder and its affiliates invest in a wide array of companies, including companies with businesses similar to us. As a result of this provision, we may be not be offered certain corporate opportunities which could be beneficial to us and our stockholders.
Tax risks
If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and OpCo might be subject to potentially significant tax inefficiencies.
We intend to operate such that OpCo does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of OpCo Units pursuant to the Redemption Right or other transfers of OpCo Units could cause OpCo to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of OpCo Units qualify for one or more such safe harbors. For example, we intend to limit the number of holders of OpCo Units, and the OpCo LLC Agreement, provides for limitations on the ability of holders of OpCo Units to transfer their OpCo Units and provides us, as the managing member of OpCo, with the right to impose restrictions (in addition to those already in place) on the ability of holders of OpCo Units to redeem their OpCo Units pursuant to the Redemption Right to the extent we believe it is necessary to ensure that OpCo will continue to be treated as a partnership for U.S. federal income tax purposes.
If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and OpCo, including as a result of our inability to file a consolidated U.S. federal income tax return with OpCo.
Changes to applicable tax laws and regulations or exposure to additional tax liabilities could adversely affect our business, results of operations, financial condition and cash flows.
We are subject to various complex evolving U.S. federal, state and local tax laws. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect. From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently applicable to natural gas and oil exploration and development companies. Such proposed legislative changes include, but are not limited to, (i) the elimination of current deductions for intangible drilling and development costs, (ii) the elimination of the percentage depletion allowance for oil and natural gas properties, (iii) an extension of the amortization period for certain geological and geophysical expenditures,(iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any legislation as a result of these proposals, any change or modification of current tax laws, any significant variance in our interpretation of current tax laws or a successful challenge of one or more of our tax positions by the U.S. Internal Revenue Service or other tax authorities increase our future tax liabilities and adversely affect our business, results of operations, financial condition and cash flows.
General risks
Loss, failure or disruption of our and our operators’ information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including with respect to our well operations information, seismic data, electronic data processing and accounting data, and the availability and integrity of these programs and systems are essential for us to conduct our business and operations. If any of such programs or systems were to be subject to a cyberattack, to fail or to create erroneous information in our hardware or software network infrastructure, whether due to telecommunications failures, human error, natural disaster, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism or similar acts or occurrences, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material and adverse effect on our business.
A terrorist attack or armed conflict or associated economic sanctions resulting therefrom could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Under the new Trump Administration, additional sanctions to certain other countries have been proposed. These sanctions, including the threat of potential sanctions, and actions by countries in response thereto may cause disruptions in international supply chains, financial activities and operations, the full costs, burdens, and limitations of which are currently unknown and may become significant. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Our business could be negatively affected by security threats, including cyber security threats, and other disruptions and is subject to complex and evolving laws and regulations regarding privacy and data protection.
We face various security threats, including cyber security threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist or criminal actors. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring, particularly given the unpredictability of the timing, nature, and scope of breaches, attacks, disruptions and other incidents. If any of these incidents were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cyber security attacks in particular are becoming more sophisticated and include, but are not limited to, installation of malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. The U.S. government also has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. While we maintain insurance that covers certain security and privacy breaches, we may not carry appropriate or sufficient coverage to compensate for all potential liability, and such insurance may not continue to be available to us on reasonable terms, if at all.
The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of personal or confidential information pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. We continue to monitor and assess the impact of these laws, which in addition to penalties and legal liability, could impose significant costs for investigations and compliance, require us to change our business practices and carry significant potential liability for our business should we fail to comply with any such applicable laws.
From time to time, we may be involved in legal proceedings that could result in substantial liabilities.
Similar to many oil and natural gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material and adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in
liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
We may be unable to dispose of non-strategic assets on attractive terms and may be required to retain liabilities for certain matters.
We regularly review our asset base to assess the market value versus holding value of existing assets with a view to optimizing returns on deployed capital. Our ability to dispose of assets could be affected by various factors, including the availability of buyers willing to purchase assets at prices acceptable to us. Sellers typically retain certain liabilities or agree to indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Our operations are subject to catastrophic losses, operational hazards and unforeseen interruptions and other disruptive risks for which we may not be adequately insured.
Our operations are subject to catastrophic losses, operational hazards, unforeseen interruptions and other disruptive risks such as natural disasters, adverse weather, accidents, maritime disasters (including those involving marine vessels/terminals), fires, explosions, hazardous materials releases, terror or cyberattacks, domestic vandalism, power failures, mechanical failures and other events beyond our control. These events could result in an injury, loss of life, property damage or destruction, as well as a curtailment or an interruption in our operations and may affect our ability to meet marketing commitments.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities
Purchase of Equity Securities by the Issuer and Affiliated Purchasers
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.
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.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
We may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.
As an owner and operator of oil and gas properties, we are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup resulting from operations and subject the lessee to liability for pollution damages. In some instances, we may be directed to suspend or cease operations in the affected area. We maintain insurance coverage that is customary in the industry, although we are not fully insured against all environmental risks.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable
Part II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Class A Common Stock is listed and traded on the NYSE under the ticker symbol "CRGY." As of January 31, 2025, we had 217 Class A common stock shareholders of record and two Class B common stock shareholders of record. 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 Revolving Credit Facility and the indentures governing the Senior Notes.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table sets forth information with respect to our repurchases of shares of Class A common stock during the quarter ended December 31, 2024.
Period Total number of shares purchased
Average price paid per share Total number of shares purchased as part of publicly announced plans or programs Approximate dollar value of shares that may yet be purchased under the plans or programs.
(in thousands)
10/1/2024 - 10/31/2024
45,618 $10.99 45,618 $119,454
11/1/2024 - 11/30/2024
- - - -
12/1/2024 - 12/31/2024
- - - -
Recent Sales of Unregistered Equity Securities
We had no sales of unregistered equity securities during the period covered by this Annual Report that were not previously reported in a Current Report on Form 8-K or Quarterly Report on Form 10-Q.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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
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
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
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
$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:
•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:
Year Ended December 31,
2024 2023 2022
Oil 76 % 76 % 66 %
Natural gas 13 % 16 % 25 %
NGLs 11 % 8 % 9 %
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:
Year Ended December 31,
2024 2023 2022
Oil (MBbls) 29,945 24,287 21,865
Natural gas (MMcf) 183,227 130,629 128,470
NGLs (MBbls) 13,154 8,475 7,110
Total (MBoe) 73,637 54,533 50,387
Daily average (MBoe/d) 201 149 138
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.
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:
Year Ended December 31,
2024 2023 2022
Oil 67 % 65 % 64 %
Natural gas 51 % 57 % 66 %
NGLs 6 % 16 % 46 %
The following table sets forth the average NYMEX oil and natural gas prices and our average realized prices for the periods presented:
Year Ended December 31,
2024 2023 2022
Oil (Bbl):
Average NYMEX $ 75.72 $ 77.62 $ 94.23
Realized price (excluding derivative settlements) 71.14 72.09 90.06
Realized price (including derivative settlements) (1)
67.38 65.04 71.98
Natural Gas (Mcf):
Average NYMEX $ 2.27 $ 2.74 $ 6.64
Realized price (excluding derivative settlements) 1.91 2.84 5.97
Realized price (including derivative settlements) (1)
2.33 2.83 3.42
NGLs (Bbl):
Realized price (excluding derivative settlements) $ 24.10 $ 22.76 $ 37.72
Realized price (including derivative settlements) (1)
24.05 24.95 29.70
(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
The following table provides the components of our revenues, respective average realized prices and net sales volumes for the periods indicated:
Year Ended December 31,
2024 2023 $ Change % Change
Revenues (in thousands):
Oil $ 2,130,418 $ 1,750,961 $ 379,457 22 %
Natural gas 349,858 371,066 (21,208) (6 %)
Natural gas liquids 316,981 192,870 124,111 64 %
Midstream and other 133,662 67,705 65,957 97 %
Total revenues $ 2,930,919 $ 2,382,602 $ 548,317 23 %
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl) $ 71.14 $ 72.09 $ (0.95) (1 %)
Natural gas ($/Mcf) $ 1.91 $ 2.84 $ (0.93) (33 %)
NGLs ($/Bbl) $ 24.10 $ 22.76 $ 1.34 6 %
Total ($/Boe) $ 37.99 $ 42.45 $ (4.46) (11 %)
Net sales volumes:
Oil (MBbls) 29,945 24,287 5,658 23 %
Natural gas (MMcf) 183,227 130,629 52,598 40 %
NGLs (MBbls) 13,154 8,475 4,679 55 %
Total (MBoe) 73,637 54,533 19,104 35 %
Average daily net sales volumes:
Oil (MBbls/d) 82 67 15 22 %
Natural gas (MMcf/d) 501 358 143 40 %
NGLs (MBbls/d) 36 23 13 57 %
Total (MBoe/d) 201 149 52 35 %
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.
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:
Year Ended December 31,
2024 2023 $ Change % Change
Expenses (in thousands):
Operating expense $ 1,278,055 $ 1,078,338 $ 199,717 19 %
Depreciation, depletion and amortization 949,480 675,782 273,698 41 %
Impairment expense 161,542 153,495 8,047 NM*
General and administrative expense 336,219 140,918 195,301 139 %
Other operating costs (12,839) 9,328 (22,167) (238 %)
Total expenses $ 2,712,457 $ 2,057,862 $ 654,596 32 %
Selected expenses per Boe:
Operating expense $ 17.36 $ 19.77 $ (2.41) (12) %
Depreciation, depletion and amortization 12.89 12.39 0.50 4 %
*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.
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.
Year Ended December 31,
2024 2023 $ Change % Change
General and administrative expense (in thousands)
Recurring general and administrative expense $ 72,857 $ 51,949 $ 20,908 40 %
Transaction and nonrecurring expenses 69,881 6,033 63,848 1,058 %
Equity-based compensation 193,481 82,936 110,545 133 %
Total general and administrative expense $ 336,219 $ 140,918 $ 195,301 139 %
General and administrative expense per Boe:
Recurring general and administrative expense $ 0.99 $ 0.95 $ 0.04 4 %
Transaction and nonrecurring expenses 0.95 0.11 0.84 764 %
Equity-based compensation 2.63 1.52 1.11 73 %
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:
Year Ended December 31,
2024 2023 $ Change % Change
(in thousands, except percentages)
Net income (loss) $ (137,683) $ 321,991 $ (459,674) (143) %
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense 216,263 145,807
Loss from extinguishment of debt 59,095 -
Income tax expense (benefit) (31,072) 23,227
Depreciation, depletion and amortization 949,480 675,782
Exploration expense 16,591 9,328
Non-cash (gain) loss on derivatives 78,494 (320,714)
Impairment expense 161,542 153,495
Equity-based compensation expense 193,481 82,936
Gain on sale of assets (29,430) -
Other (income) expense (1,760) 282
Certain redeemable noncontrolling interest distributions made by OpCo (1)
(19,963) (30,563)
Transaction and nonrecurring expenses (2)
82,484 22,632
Settlement of acquired derivative contracts 60,787 (61,455)
Adjusted EBITDAX (non-GAAP) $ 1,598,309 $ 1,022,748 $ 575,561 56 %
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums (202,886) (132,981)
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, premiums and SilverBow Merger transaction related costs (14,817) -
Current income tax benefit (expense) (4,782) (494)
Tax-related redeemable noncontrolling interest distributions made by OpCo
(458) (753)
Development of oil and natural gas properties (745,198) (578,316)
Levered Free Cash Flow (non-GAAP) $ 630,168 $ 310,204 $ 319,964 103 %
(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.
Year Ended December 31,
2024 2023 $ Change % Change
(in thousands, except percentages)
Net cash provided by operating activities $ 1,223,086 $ 935,769 $ 287,317 31 %
Changes in operating assets and liabilities 49,695 (72,380)
Certain redeemable noncontrolling interest distributions made by OpCo (1)
(19,963) (30,563)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo (458) (753)
Transaction and nonrecurring expenses (2)
82,484 22,632
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, premiums and SilverBow Merger transaction related costs (14,817) -
Other adjustments and operating activities
55,339 33,815
Development of oil and natural gas properties (745,198) (578,316)
Levered Free Cash Flow (non-GAAP) $ 630,168 $ 310,204 $ 319,964 103 %
(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".
The following table presents our cash balances and outstanding borrowings at the end of each period presented:
At December 31,
(in thousands) 2024 2023
Cash and cash equivalents $ 132,818 $ 2,974
Long-term debt 3,049,255 1,694,375
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:
Year Ended December 31,
(in thousands) 2024 2023
Net cash provided by operating activities $ 1,223,086 $ 935,769
Net cash used in investing activities (1,198,299) (1,398,800)
Net cash (used in) provided by financing activities 207,392 456,456
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
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.
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.
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
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:
Year Ended December 31,
(in thousands) 2024 2023
Total development of oil and natural gas properties $ 745,198 $ 578,316
Change in accruals and other non-cash adjustments (59,514) 3,034
Cash used in development of oil and natural gas properties 685,684 581,350
Cash used in acquisition of oil and natural gas properties 558,600 849,254
Non-cash acquisition of oil and natural gas properties 611,423 -
Total expenditure on acquisition and development of oil and natural gas properties $ 1,855,707 $ 1,430,604
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:
(in thousands)
Due within
one year Due after
one year Total
Long-term debt - principal (1)
$ - $ 3,100,000 $ 3,100,000
Fixed rate long-term debt - interest (2)
250,125 1,329,563 1,579,688
Derivative liabilities 2,698 37,732 40,430
Asset retirement obligations (3)
37,223 448,945 486,168
Oil and natural gas transportation and gathering agreements (4)
164,314 741,590 905,904
Drilling Commitments (5)
18,600 700 19,300
Manager Compensation
51,343 102,687 154,030
Total $ 524,303 $ 5,761,217 $ 6,285,520
(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.
(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.
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.
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
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
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses.
Commodity price risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production.
Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil, natural gas and NGLs prices on our cash flows, we regularly enter into commodity derivative contracts with respect to certain of our oil, natural gas and NGL production through various transactions that limit the risks of fluctuations of future prices. 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 hedging program allows us to reserve capital and protect margins and corporate returns through commodity cycles and return capital to investors. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed
floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These economic hedging activities are intended to limit our near-term exposure to product price volatility and to maintain stable cash flows, a strong balance sheet and attractive corporate returns.
As of December 31, 2024, our derivative portfolio had an aggregate notional value of approximately $3.1 billion, and the fair market value of our commodity derivative contracts was a net asset of $19.5 million. We determine the fair value of our oil and natural gas commodity derivatives using valuation techniques that utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.
Based upon our open commodity derivative positions at December 31, 2024, a hypothetical 10% increase or decrease in the NYMEX WTI, Brent price, Henry Hub Index price, NGL prices and basis prices would change our net commodity derivative position. If prices increased by 10%, our derivative position would change by approximately $224.1 million. If prices decreased by 10%, our derivative position would change by approximately $192.5 million. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices decrease or increase.
Derivative assets and liabilities are classified on the consolidated balance sheets as risk management assets and liabilities. We use derivative instruments and enter into swap contracts which are governed by International Swaps and Derivatives Association (“ISDA”) master agreements. Amounts not offset on the consolidated balance sheets represent positions that do not meet all of the conditions to be netted on such balance sheet, such as the legally enforceable right of offset or the execution of a master netting arrangement. See "Notes to Consolidated Financial Statements, NOTE 5 - Derivatives" in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report for additional discussion.
Counterparty and customer credit risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.
We sell oil, natural gas and NGLs to various types of customers. Credit is extended based on an evaluation of our customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGLs depends on numerous factors outside of our control, none of which can be predicted with certainty.
For the years ended December 31, 2024, 2023 and 2022, we had certain major customers that exceeded 10% of total revenues. See "Part I., Items 1 and 2. Business and Properties-Marketing and customers.” We do not believe the loss of any single customer would materially impact its operating results because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.
To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by our management as competent and competitive market makers. Additionally, our ISDAs allow us to net positions with the same counterparty to minimize credit risk exposure. The creditworthiness of our counterparties is subject to periodic review.
Interest rate risk
Although we had no variable rate debt outstanding at December 31, 2024, we are subject to the risk of changes in interest rates under our Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at either a U.S. dollar alternative base rate (based on the prime rate, the federal funds effective rate or an adjusted SOFR (as defined below)), plus an applicable margin or SOFR, plus an applicable margin, at the election of the borrowers. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
CRESCENT ENERGY COMPANY
Page
Report of Independent Registered Public Accounting Firm 91
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2024 and 2023
Consolidated Statements of Operations for the Years Ended December 31, 2024, 2023 and 2022
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2024, 2023 and 2022
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022
Notes to Consolidated Financial Statements
Financial Statement Schedules:
Schedule I - Condensed Financial Information of Registrant 142
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Crescent Energy Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Crescent Energy Company and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of operations, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2025, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Proved Oil and Natural Gas Properties - Oil and Natural Gas Reserves - Refer to Notes 2 and 4 to the financial statements
Critical Audit Matter Description
The Company’s proved oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method and reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount may have occurred, by comparing the carrying amount of the proved oil and natural gas properties to the estimated undiscounted future net cash flows, derived in part from the underlying proved oil and natural gas reserves. The development of the Company’s proved oil and natural gas reserves and the related future net cash flows used to evaluate proved oil and natural gas properties for impairment requires management to make significant estimates and assumptions, including calculating the best estimate of future production and the Company’s ability to convert proved undeveloped reserves to producing oil and natural gas properties within five years of their initial proved reserves bookings.
The Company engaged an independent reserve engineer to independently engineer their proved oil and natural gas reserves in accordance with Securities and Exchange Commission Regulation S-X and other sources of accounting principles generally accepted in the United States of America. Changes in these estimates, assumptions or engineering data could have a significant impact on the depletion calculations and the proved oil and natural properties impairment evaluations. Given the significant judgments made by management, performing audit procedures to evaluate the Company’s proved oil and natural gas reserves and the related estimated
undiscounted future net cash flows, including management’s estimates and assumptions related to the best estimate of future production and converting proved undeveloped reserves to producing oil and natural gas properties within five years, required a high degree of auditor judgment and an increased extent of effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant judgments and assumptions related to oil and natural gas reserves and estimates of the future net cash flows, included the following, among others:
•We tested the operating effectiveness of controls related to the Company’s estimation of proved oil and natural gas reserves and the related expected undiscounted future net cash flows.
•We evaluated the Company’s best estimate of future production by:
•Comparing the Company’s best estimate of future production to historical production volumes.
•Assessing the reasonableness of the production volume decline curves by comparing to historical decline curve estimates.
•We evaluated the reasonableness of management’s estimates and assumptions related to converting proved undeveloped reserves to producing oil and natural gas properties within five years, by performing the following:
•Comparing historical conversions of proved undeveloped reserves into proved developed reserves to management’s forecasts of conversions.
•Comparing management’s forecasts to the Company’s drilling plan and the availability of capital relative to the drilling plan.
•Evaluating whether the forecasted date of development for the proved undeveloped locations are within five years of their original booking date.
•Reviewing internal communications to management and the Board of Directors.
•We evaluated the experience, qualifications and objectivity of management’s expert, an independent reserve engineering firm.
Management's Determination of Fair Value - Refer to Notes 2, 3 and 6 to the financial statements
Critical Audit Matter Description
The Company’s determination of the fair value of their assets and liabilities, inclusive of acquired oil and natural gas properties, requires management to make significant estimates and apply a high level of judgement. As such, management will typically utilize third-party firms to assist as the valuation techniques (such as the income valuation technique) incorporate several business and market assumptions which are highly subjective and require a high level of judgement and estimation. During the year ended December 31, 2024, management made significant estimates when determining the fair value of assets acquired from SilverBow Resources, Inc. (SilverBow) on July 30, 2024, as well as when determining the fair value of their proved oil and natural gas properties which had an impairment indicator at year-end.
For the acquisition of SilverBow on July 30, 2024, the Company employed an independent third-party firm to value the oil and gas properties which represent a substantial majority of the gross assets acquired. The third-party firm was predominantly used to assist management in their assessment of assumptions applied in the valuation model with a high degree of subjectivity and judgement, including the application of a discount rate commensurate with the risk and current market conditions associated with realizing the projected cash flows, determining appropriate Risk Adjustment Factors (RAF's) for each reserve category, determining an appropriate escalation factor for pricing and costs, and future oil and natural gas prices of the acquired oil and natural gas properties.
During the year ended December 31, 2024, certain of the Company's proved oil and natural gas properties were reduced to their fair value, resulting in an impairment to their carrying values which was included in impairment expense within the consolidated statement of operations. When an impairment indicator is identified, the Company compares the estimated undiscounted future net cash flows of its proved oil and natural gas reserves to the carrying amount of the proved oil and natural gas properties on a field-by-field basis to determine if the carrying amount is recoverable. If the carrying amount of the proved oil and natural gas properties exceeds the undiscounted future net cash flows, the Company will adjust the carrying value to fair value. Management estimated the fair value of the proved oil and natural gas properties using the income valuation technique which incorporates the application of a discount rate commensurate with the risk and current market conditions associated with realizing the projected cash flows.
Given the significant judgments made by management, including the development of oil and natural gas reserves estimates using management’s experts as defined in the previous Critical Audit Matter and in developing estimates of appropriate business and market assumptions, performing audit procedures over these management estimates required a higher degree of auditor judgment and an increased extent of effort, including the use of professionals with specialized skill and knowledge.
How the Critical Audit Matter Was Addressed in the Audit
In addition to the procedures specified in the previous Critical Audit Matter, our audit procedures related to managements selection of business and market assumptions applied to the determination of fair value of proved oil and natural gas properties, included the following, among others:
•We tested the operating effectiveness of controls related to the Company’s estimation of business and market assumptions.
•We evaluated the appropriateness of the business assumptions and accounting assumptions in line with the applicable financial reporting framework, as well as assessed the acceptability of the underlying data.
•With the assistance of our fair value specialist, we evaluated the appropriateness of the market assumptions by:
◦Evaluating the appropriateness of the mathematical models and selected valuation technique.
◦Evaluating the guideline public companies selected by management and used in the selection of market assumptions considering the comparability of operations to the Company, specifically for our purchase price allocation work related to SilverBow.
◦Comparing the selected market assumptions to published estimates for the industry.
◦Developing a range of independent estimates for each market assumption and comparing the assumptions selected by management with the range of independent estimates.
/s/ Deloitte & Touche LLP
Houston, Texas
February 26, 2025
We have served as the Company’s auditor since 2021.
CRESCENT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
2024 December 31,
(in thousands, except share and unit data)
ASSETS
Current assets:
Cash and cash equivalents $ 132,818 $ 2,974
Restricted cash 5,490 261
Accounts receivable, net 535,416 504,630
Accounts receivable - affiliates 6,856 2,108
Derivative assets - current 53,273 54,321
Prepaid expenses
42,595 40,406
Other current assets
11,640 10,952
Total current assets 788,088 615,652
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved 11,471,299 8,574,478
Unproved 374,306 283,324
Oil and natural gas properties at cost, successful efforts method 11,845,605 8,857,802
Field and other property and equipment, at cost 226,871 198,570
Total property, plant and equipment 12,072,476 9,056,372
Less: accumulated depreciation, depletion, amortization and impairment (3,927,422) (2,940,546)
Property, plant and equipment, net 8,145,054 6,115,826
Derivative assets - noncurrent 6,684 8,066
Investments in equity affiliates
13,810 6,076
Other assets 207,013 57,715
TOTAL ASSETS $ 9,160,649 $ 6,803,335
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
2024 December 31,
(in thousands, except share and unit data)
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 740,452 $ 613,543
Accounts payable - affiliates 18,334 52,607
Derivative liabilities - current 2,698 42,051
Financing lease obligations - current 3,625 4,233
Other current liabilities 62,254 37,823
Total current liabilities 827,363 750,257
Long-term debt 3,049,255 1,694,375
Derivative liabilities - noncurrent 37,732 -
Asset retirement obligations 448,945 418,319
Deferred tax liability 370,329 262,581
Financing lease obligations - noncurrent 3,526 7,066
Other liabilities 55,539 35,019
Total liabilities 4,792,689 3,167,617
Commitments and contingencies (Note 12)
Redeemable noncontrolling interests 1,228,329 1,901,208
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized, 189,505,209 and 92,680,353 shares issued, and 187,070,725 and 91,608,800 shares outstanding as of December 31, 2024 and 2023, respectively
19 9
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 65,948,124 and 88,048,124 shares issued and outstanding as of December 31, 2024 and 2023, respectively
7 9
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2024 and 2023
- -
Treasury stock, at cost; 2,434,484 and 1,071,553 shares of Class A common stock as of December 31, 2024 and 2023, respectively
(32,430) (17,143)
Additional paid-in capital 3,227,450 1,626,501
Retained earnings (accumulated deficit)
(64,751) 95,447
Noncontrolling interests 9,336 29,687
Total equity 3,139,631 1,734,510
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY $ 9,160,649 $ 6,803,335
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2024 2023 2022
(in thousands, except per share amounts)
Revenues:
Oil $ 2,130,418 $ 1,750,961 $ 1,969,070
Natural gas 349,858 371,066 766,962
Natural gas liquids 316,981 192,870 268,192
Midstream and other 133,662 67,705 52,841
Total revenues 2,930,919 2,382,602 3,057,065
Expenses:
Lease operating expense 528,822 495,380 438,753
Workover expense 60,312 58,441 66,864
Asset operating expense 103,220 86,593 78,709
Gathering, transportation and marketing 312,931 235,153 177,078
Production and other taxes 162,634 162,963 238,381
Depreciation, depletion and amortization 949,480 675,782 532,926
Impairment expense 161,542 153,495 142,902
Exploration expense 16,591 9,328 3,425
Midstream and other operating expense
110,136 39,809 13,513
General and administrative expense 336,219 140,918 84,990
(Gain) loss on sale of assets
(29,430) - (4,641)
Total expenses 2,712,457 2,057,862 1,772,900
Income (loss) from operations 218,462 324,740 1,284,165
Other income (expense):
Gain (loss) on derivatives (114,348) 166,980 (676,902)
Interest expense (216,263) (145,807) (95,937)
Loss from extinguishment of debt (59,095) - -
Other income (expense) 1,760 (282) 949
Income (loss) from equity affiliates
729 (413) 4,616
Total other income (expense) (387,217) 20,478 (767,274)
Income (loss) before taxes (168,755) 345,218 516,891
Income tax benefit (expense) 31,072 (23,227) (36,291)
Net income (loss) (137,683) 321,991 480,600
Less: net (income) loss attributable to noncontrolling interests 1,215 (472) (2,669)
Less: net (income) loss attributable to redeemable noncontrolling interests 21,863 (253,909) (381,257)
Net income (loss) attributable to Crescent Energy $ (114,605) $ 67,610 $ 96,674
Net income (loss) per share:
Class A - basic $ (0.88) $ 1.02 $ 2.20
Class A - diluted $ (0.88) $ 1.02 $ 2.20
Class B - basic and diluted $ - $ - $ -
Weighted average shares outstanding:
Class A - basic 130,715 66,598 43,865
Class A - diluted 130,715 67,402 44,112
Class B - basic and diluted 70,519 104,271 124,857
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(in thousands)
Crescent Energy Company
Class A Common Stock Class B Common Stock Series I Preferred Stock Treasury Stock Additional Paid-in Capital Retained Earnings (Accumulated Deficit) Noncontrolling
Interest
Total
Shares Amount Shares Amount Shares Amount Shares Amount
Balance at December 31, 2021 41,954 $ 4 127,536 $ 13 1 $ - 1,151 $ (18,448) $ 720,016 $ (19,376) $ 12,435 $ 694,644
Net income (loss) - - - - - - - - - 96,674 2,669 99,343
Contributions - - - - - - - - - - 1,533 1,533
Distributions - - - - - - - - - - (7,884) (7,884)
Repurchase of noncontrolling interest - - - - - - - - - - (4,060) (4,060)
Dividend to Class A common stock - - - - - - - - (12,168) (15,341) - (27,509)
Equity based compensation - - - - - - - - 6,899 - 9,485 16,384
Change in deferred taxes related to basis in OpCo - - - - - - - - (26,351) - - (26,351)
Change in deferred taxes related to basis differences associated with the 2022 Equity Transactions - - - - - - - - (5,599) - - (5,599)
Change in equity associated with the 2022 Equity Transactions 6,328 1 (8,891) (1) - - - - 121,790 - - 121,790
Balance at December 31, 2022 48,282 $ 5 118,645 $ 12 1 $ - 1,151 $ (18,448) $ 804,587 $ 61,957 $ 14,178 $ 862,291
Net income (loss) - - - - - - - - - 67,610 472 68,082
Contributions - - - - - - - - - - 4,738 4,738
Distributions - - - - - - - - - - (2,500) (2,500)
Dividend to Class A common stock - - - - - - - - - (34,120) - (34,120)
Equity based compensation 80 - - - - - (80) 1,305 25,681 - 12,799 39,785
Change in deferred taxes related to basis differences associated with the Class A Conversions - - - - - - - - (79,378) - - (79,378)
Change in equity associated with the Class A Conversions 30,597 3 (30,597) (3) - - - - 679,567 - - 679,567
Change in deferred taxes related to basis differences associated with the 2023 Equity Issuance - - - - - - - - (13,122) - - (13,122)
Change in equity associated with the 2023 Equity Issuance 12,650 1 - - - - - - 209,166 - - 209,167
Balance at December 31, 2023 91,609 $ 9 88,048 $ 9 1 $ - 1,071 $ (17,143) $ 1,626,501 $ 95,447 $ 29,687 $ 1,734,510
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(in thousands)
Crescent Energy Company
Class A Common Stock Class B Common Stock Series I Preferred Stock Treasury Stock Additional Paid-in Capital Retained Earnings (Accumulated Deficit) Noncontrolling
Interest
Total
Shares Amount Shares Amount Shares Amount Shares Amount
Balance at December 31, 2023 91,609 $ 9 88,048 $ 9 1 $ - 1,071 $ (17,143) $ 1,626,501 $ 95,447 $ 29,687 $ 1,734,510
Net income (loss) - - - - - - - - - (114,605) (1,215) (115,820)
Contributions - - - - - - - - - - 4,280 4,280
Distributions - - - - - - - - - - (10,111) (10,111)
Dividend to Class A common stock - - - - - - - - (19,482) (45,593) - (65,075)
Equity-based compensation 108 - - - - - - - 131,850 - (13,375) 118,475
Change in deferred taxes related to basis differences associated with the SilverBow Merger - - - - - - - - (31,454) - - (31,454)
Change in deferred taxes related to basis differences associated with the 2024 Equity Transactions and 2024 Class A Repurchases - - - - - - - - (53,272) - - (53,272)
Repurchase of redeemable noncontrolling interest - - - - - - - - 653 - 70 723
Change in equity associated with the 2024 Equity Transactions 44,525 5 (22,100) (2) - - - - 821,530 - - 821,533
Changes in equity associated with the SilverBow Merger 51,562 5 - - - - 630 (7,442) 754,956 - - 747,519
Repurchases of Class A common stock (733) - - - - - 733 (7,845) (3,832) - - (11,677)
Balance at December 31, 2024 187,071 $ 19 65,948 $ 7 1 $ - 2,434 $ (32,430) $ 3,227,450 $ (64,751) $ 9,336 $ 3,139,631
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2024 2023 2022
Cash flows from operating activities: (in thousands)
Net income (loss)
$ (137,683) $ 321,991 $ 480,600
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 949,480 675,782 532,926
Impairment expense 161,542 153,495 142,902
Deferred income tax expense (benefit) (35,854) 22,733 33,178
(Gain) loss on sale of assets
(29,430) - (4,641)
(Gain) loss on derivatives 114,348 (166,980) 676,902
Net cash (paid) received on settlement of derivatives (35,854) (153,734) (779,260)
Non-cash equity-based compensation expense 185,613 82,936 38,063
Amortization of debt issuance costs, premium and discount 13,377 12,826 8,894
Loss from debt extinguishment 59,095 - -
Restructuring of acquired derivative contracts - - (51,994)
Settlement of acquired derivative contracts 60,787 (61,455) (49,929)
Other (32,640) (24,205) (7,011)
Changes in operating assets and liabilities:
Accounts receivable 111,405 (42,091) (128,820)
Accounts receivable - affiliates (4,748) 573 18,360
Prepaid and other current assets 3,223 (6,523) (24,932)
Accounts payable and accrued liabilities (128,016) 91,822 127,620
Accounts payable - affiliates (25,144) 20,773 12,044
Other (6,415) 7,826 (12,530)
Net cash provided by operating activities 1,223,086 935,769 1,012,372
Cash flows from investing activities:
Development of oil and natural gas properties (685,684) (581,350) (592,707)
Acquisitions of oil and natural gas properties, net of cash acquired (558,600) (849,254) (626,620)
Proceeds from the sale of oil and natural gas properties 54,771 28,946 93,203
Purchases of restricted investment securities - HTM (7,114) (12,428) (8,956)
Maturities of restricted investment securities - HTM 7,200 12,522 7,200
Other (8,872) 2,764 3,536
Net cash used in investing activities $ (1,198,299) $ (1,398,800) $ (1,124,344)
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2024 2023 2022
Cash flows from financing activities:
Proceeds from the issuance of Senior Notes, after premium, discount and underwriting fees
$ 2,074,625 $ 984,625 $ 199,250
Repurchase of Senior Notes, including extinguishment costs (714,817) - -
Revolving Credit Facility borrowings 3,168,300 2,283,800 1,385,000
Revolving Credit Facility repayments (3,191,800) (2,819,748) (1,369,000)
Payment of debt issuance costs (28,019) (7,241) (20,051)
Settlement of acquired deferred acquisition consideration (75,000) - -
Proceeds from the Equity Issuances after underwriting fees 330,573 145,665 -
Payment of costs related to the Equity Issuances (1,296) (2,340) -
Redeemable noncontrolling interest contributions - 1,238 5,985
Redeemable noncontrolling interest distributions (293) (417) (213)
Repayments of debt acquired in SilverBow Merger, including extinguishment costs (1,177,138) - -
Dividend to Class A common stock (65,075) (34,120) (27,509)
Cash distributions to redeemable noncontrolling interests initiated by Class A common stock dividend (32,013) (56,259) (78,855)
Cash distributions to redeemable noncontrolling interests initiated by Manager Compensation (22,237) (33,236) (32,250)
Cash contributions from (cash distributions to) redeemable noncontrolling interests initiated by income taxes (458) (798) (18,118)
Repurchase of redeemable noncontrolling interests related to 2024 Equity Transactions (22,701) - (36,220)
Repurchase of redeemable noncontrolling interests (9,916) - -
Noncontrolling interest distributions (10,111) (2,500) (6,477)
Noncontrolling interest contributions 4,280 1,771 55
Repurchase of noncontrolling interest - - (4,060)
Cash paid for treasury stock acquired for equity-based compensation tax withholding (7,536) (72) -
Repurchases of Class A common stock (7,845) - -
Other and member contributions (4,131) (3,912) (5,378)
Net cash provided by (used in) financing activities 207,392 456,456 (7,841)
Net change in cash, cash equivalents and restricted cash 232,179 (6,575) (119,813)
Cash, cash equivalents and restricted cash, beginning of period 8,729 15,304 135,117
Cash, cash equivalents, and restricted cash, end of period $ 240,908 $ 8,729 $ 15,304
The accompanying notes to financial statements are an integral part of these consolidated financial statements
CRESCENT ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)
NOTE 1 - Organization and Basis of Presentation
Organization
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 low-decline production with deep, high-quality development inventory. Our activities are focused in Texas and the Rocky Mountain region.
Corporate Structure
Our Class A Common Stock is listed on the New York Stock Exchange under the symbol “CRGY.” We are structured as an “Up-C,” and Crescent is a holding company, the sole material asset of which are of units ("OpCo Units") of Crescent Energy OpCo LLC ("OpCo"). The assets and liabilities of OpCo represent substantially all our consolidated assets and liabilities, with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement, as defined within NOTE 14 - Related Party Transactions. Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in NOTE 8 - Debt. Shares of Crescent Class A common stock, par value $0.0001 per share ("Class A Common Stock") have both voting and economic rights with respect to Crescent. Holders of Crescent Class B common stock, par value $0.0001 per share ("Class B Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights with respect to Crescent, hold a corresponding amount of economic, non-voting OpCo Units. 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 (“OpCo LLC Agreement”). Additionally, an affiliate KKR & Co. Inc. (together with its subsidiaries, the "KKR Group") is the sole holder of Crescent's non-economic Series I preferred stock, $0.0001 par value per share, which entitles the holder thereof to appoint the Board of Directors of Crescent and to certain other approval rights.
Basis of Presentation
Our consolidated financial statements (the “financial statements”) include the accounts of the Company and its subsidiaries after the elimination of intercompany transactions and balances and are presented in accordance with U.S. general accepted accounting principles (“GAAP”). We have no elements of other comprehensive income for the periods presented.
Crescent is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which, as of December 31, 2024 and 2023, respectively, is owned approximately 74% and 51% by Crescent and approximately 26% and 49% by holders of our redeemable noncontrolling interests representing former owners of Independence, and (ii) Crescent Energy Finance LLC, OpCo's wholly owned subsidiary. Crescent and OpCo have no operations, or material cash flows, assets or liabilities other than their investment in Crescent Energy Finance LLC. As the sole managing member of OpCo, Crescent is responsible for all operational, management and administrative decisions related to OpCo’s business. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo was determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, Crescent consolidates the financial results of OpCo and its subsidiaries, including Crescent Energy Finance LLC. See “- Corporate Structure” above for more information regarding our corporate structure.
The financial statements include undivided interests in oil and natural gas properties. We account for our share of oil and natural gas properties by reporting our proportionate share of assets, liabilities, revenues, costs, and cash flows within the accompanying consolidated balance sheets, statements of operations, and statements of cash flows.
NOTE 2 - Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make use of estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We use historical experience and various other assumptions and information that are believed to be reasonable under the circumstances in developing our estimates and judgments. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results may differ from these estimates. Our significant estimates include the fair value of acquired assets and liabilities, oil and natural gas reserves, impairment of proved and unproved oil and natural gas properties, valuation of derivative instruments and income taxes.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash deposited in commercial bank accounts and highly liquid investments purchased with an original maturity of three months or less at the date of purchase. Cash and cash equivalents are maintained with major financial institutions in the U.S. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, the financial stability of the financial institutions is regularly monitored, and we believe that we do not have exposure to any significant default risk.
Restricted Cash
Restricted cash consists of funds earmarked for a special purpose and therefore not available for immediate and general use. The majority of our restricted cash is comprised of cash that is contractually required to be restricted to fund acquisitions or to pay for the future abandonment of certain wells. Restricted cash is included in Other current assets and Other assets on our consolidated balance sheets.
The following table provides a reconciliation of cash and restricted cash presented on our balance sheets to amounts shown in our consolidated statements of cash flows:
As of December 31,
2024 2023 2022
(in thousands)
Cash and cash equivalents
$ 132,818 $ 2,974 $ -
Restricted cash - current 5,490 261 8,000
Restricted cash - noncurrent 102,600 5,494 7,304
Total cash, cash equivalents and restricted cash $ 240,908 $ 8,729 $ 15,304
Accounts Receivable
We routinely assess the recoverability of our accounts receivable, which primarily comprise amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. We monitor our exposure to credit risk primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Generally, our oil and natural gas receivables are collected within 45 to 60 days of production. Our joint interest billings are collected within the month after they are billed, and we have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.
We establish allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur primarily based on a historical loss rate analysis. We estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. We consider forecasts of future economic conditions in the estimate of our expected credit losses, in particular whether there is an increase in the probability that our counterparties will be unable to pay their obligations when due, and adjust our allowance for expected credit losses, when necessary. Our allowances for expected credit losses were nominal as of December 31, 2024 and 2023. We did not incur credit loss expense or bad debt expense related to our accounts receivable
during the years ended December 31, 2024, 2023, and 2022. We do not have any off-balance sheet credit exposure related to our customers.
Restricted Investment Securities
We hold U.S. Treasury securities, which are contractually required to be set aside to pay for the future abandonment of certain wells in California. Due to this restriction, we report these investment securities as noncurrent and include them within Other assets on our consolidated balance sheets.
We classify our investment in these debt securities at the acquisition date and re-evaluate the classification at each balance sheet date. We classify debt securities purchased with the positive intent and ability to hold until their maturity date as held-to-maturity investments (“HTM”) and carry these investments at amortized cost. Premiums and discounts on purchases are amortized over the remaining time to maturity of the security and the amortization is recorded as an adjustment to interest income. At each of December 31, 2024 and 2023, we had restricted investment securities - HTM with a carrying value of $7.1 million.
Oil and Natural Gas Properties
Oil and natural gas producing activities are accounted for under the successful efforts method of accounting. Under this method, exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion and amortization (“DD&A”). Dry hole costs associated with developing proved fields are capitalized. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs and costs of certain non-producing leasehold costs are expensed once evaluated and determined to be a dry hole. We incurred exploration expense of $16.6 million, $9.3 million, and $3.4 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Delay and surface rentals are charged to expense as incurred. The costs to acquire mineral interests in oil and natural gas properties and lease acquisition costs are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold costs are transferred to proved properties.
The capitalized costs of producing oil and natural gas properties are depleted on a field-by-field basis using the units-of-production method based on the ratio of current production to estimated total net proved oil, natural gas and NGL reserves. Proved developed reserves are used in computing depletion rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.
Upon the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized.
Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. Refer to Asset Retirement Obligations below for additional discussion.
During the years ended December 31, 2024, 2023 and 2022, we recognized depletion expense of $892.4 million, $626.6 million and $498.3 million, respectively.
Other Property, Plant and Equipment
We have other property, plant, and equipment that consists principally of gathering and processing facilities, land, vehicles, computer hardware and software, office furniture and equipment, buildings and leasehold improvements. Other property, plant, and equipment, except land, is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the respective assets which range from three to thirty years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.
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. We perform this analysis on an asset pool basis. 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, but are not limited to, estimates of reserves, future commodity prices, future production estimates, and discount rates commensurate with the risk associated with realizing the projected cash flows.
During the years ended December 31, 2024 and 2023, we determined that there were triggering events requiring the evaluation of the recoverability of certain of our oil and natural gas properties. Based on an assessment of our oil and natural gas properties, we recorded impairment expense of $161.5 million and $149.6 million, respectively, during the years ended December 31, 2024 and 2023.
Investments in Equity Affiliates
If an entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we generally account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we generally apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. We eliminate our proportionate share of profits and losses from transactions with equity affiliates to the extent such amounts remain on our consolidated balance sheets (or those of our equity affiliates).
Under the equity method, our proportionate share of each investees' net income increases the balance of our investment, while a net loss or receipt of dividends decreases the balance of our investment. Our proportionate share of net income from our equity affiliates are reported as a single line item within income (loss) from equity affiliates in our consolidated statements of operations.
During the year ended December 31, 2023, we identified an indicator that the carrying value of our equity method investment was not recoverable and thus recorded an other-than-temporary impairment charge of $3.9 million.
Debt Issuance Costs
We capitalize costs incurred in connection with obtaining financing associated with our Revolving Credit Facility and the 2028 Notes, 2032 Notes and 2033 Notes (collectively, the "Senior Notes") and amortize such costs as additional interest expense over the life of the underlying indebtedness. These costs include fees paid to financial institutions and legal fees. Debt issuance costs associated with our Revolving Credit Facility are included in Other assets in our consolidated balance sheets. Debt issuance costs associated with our Senior Notes are included as a contra-liability in Long-term debt in our consolidated balance sheets.
Revenue Recognition
Oil, Gas and NGL Revenues
We hold operated and non-operated working interests and mineral and royalty interests in producing assets that function as follows:
Operated working interests: We are responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing and marketing; we remit proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.
Non-operated working interests: An operator of these assets is responsible for the day-to-day management and operation of the field as well as negotiations required for post-production transportation, gathering, processing, and marketing; the operator then remits proceeds from sales of resulting hydrocarbons to third parties back to non-operators less costs as agreed in the applicable joint operating agreement.
Mineral and royalty interests: Ownership of a percentage of production or production revenues produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating or any other expense associated with drilling and producing an oil and gas well. Mineral and royalty interests may be burdened by some or all of the post-production costs related to gathering, processing and marketing.
We sell oil production at the lease and collect an agreed-upon index price, net of pricing differentials.
Under our natural gas contracts, we deliver natural gas to a midstream processor at a contractually specified delivery point. The midstream processor gathers and processes the natural gas and then markets and remits proceeds to us for the resulting sale of the residue gas and NGLs.
Our non-operated production is marketed by operators, after which the operators remit net proceeds from the sale of our share of production to us. Proceeds reflect post-production expenses such as gathering, processing and other expenses incurred in marketing of that production.
Performance Obligations
Under product sales contracts, each unit of product generally represents a separate performance obligation. We record revenue for our product sales contracts at the point-in-time control of a commodity is transferred to the customer. However, settlement statements from non-operated working interests may not be received for 30 to 60 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products.
At the end of the reporting period, we did not have any unsatisfied performance obligations. Our contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of our contracts with customers does not require us to constrain variable consideration for accounting purposes.
Revenue is recognized to the extent it is determined that it is probable that a significant reversal will not occur. We record the differences between our revenue estimates and the actual amounts received in the month that payment is received from the operator.
Equity-Based Compensation Awards
Equity-based compensation awards include share-based payments that are issued to employees, directors and non-employees in exchange for services provided to us. Equity-classified share-based payment awards are recognized at fair value on the grant date, and amortized over the life of the award. Liability-classified share-based payment awards are remeasured at fair value until settlement. For awards with service-based vesting conditions only, we recognize compensation cost using straight-line attribution. For awards that contain market or performance conditions we use accelerated attribution. Our policy is to recognize forfeitures as they occur.
Equity-based compensation cost is presented as "General and administrative expense" on our consolidated statements of operations. See NOTE 13 - Equity-Based Compensation Awards for additional discussion.
Defined Contribution Plan
We offer our employees a defined contribution 401(k) Plan (the “401(k) Plan”) which allows eligible employees to make tax-deferred contributions, not to exceed annual limits established by the Internal Revenue Service. We match 100% of employee contributions up to a certain threshold of compensation with immediate vesting for existing employees. We did not make any contributions to the 401(k) Plan for the year ended December 31, 2021 since the plan's inception began in January 2022 in conjunction with the start of the benefit plan year. During the year ended December 31, 2024, 2023, and 2022, we made contributions of $4.5 million, $4.2 million and $4.7 million, respectively, to the plan.
Business Combinations
We recognize the identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. These fair values are accounted for at the date of acquisition and included in our consolidated balance sheets as of December 31, 2024 and 2023. The results of operations of an acquired business are included in our consolidated statements of operations from the date of the acquisition.
Credit and Concentration Risk
We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. This concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our purchasers may be similarly affected by changes in economic, industry or other conditions. If these counterparties were to fail to pay amounts due to us, our financial position and results of operations could be materially affected.
The below purchasers represented greater than 10% of our revenues during the years ended December 31, 2024, 2023 and 2022:
2024 2023 2022
Shell Trading US Company 23.7% 18.3% 20.8%
ConocoPhillips 16.5% * 15.1%
*Purchaser did not account for greater than 10% of revenue for the year
We believe that the loss of any of our purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.
Risks and Uncertainties
Our future financial condition, results of operations and cash flows are dependent on the demand and prices received for oil, natural gas and NGL production. These prices historically have been volatile, and we expect such volatility to continue in the future, as they are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil, natural gas and NGL, market uncertainty and a variety of additional factors beyond our control. These factors include weather conditions, government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil, natural gas or NGL prices may adversely affect our financial position, cash flows and results of operations. Lower oil, natural gas or NGL prices also may reduce the amount of oil, natural gas and NGL that can be produced economically.
Our revenues are derived principally from uncollateralized sales to numerous companies in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry.
Risk Management
We periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, swaptions, collars or other options. We do not use derivative contracts for speculative purposes and have not designated any derivative instruments as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts, as well as realized gains and losses on the settlement of derivative contracts, are reported in Gain (loss) on derivatives in our consolidated statements of operations.
Such derivative instruments are initially recorded at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value at each reporting date. Derivatives are carried as assets when the fair value is positive or as liabilities when the fair value is negative and are classified as current and long term based on the delivery periods of the financial instruments. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on our consolidated balance sheets.
See NOTE 6 - Fair Value Measurements for additional discussion.
Contingencies
Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived
merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.
For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed. See NOTE 12 - Commitments and Contingencies.
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 and certain state taxes on our allocable share of any taxable income of OpCo. Taxable income or loss generated by OpCo is generally allocated and passed through to the holders of OpCo Units, including Crescent, based on their proportionate share of OpCo Unit ownership.
The amount of income taxes we record requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. We recognize deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Temporary differences arise when there are differences between the financial statement carrying amount and the tax basis of existing assets and liabilities as these differences create taxable or tax-deductible amounts for future periods. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see NOTE 11 - Income Taxes.
ASC Topic 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more likely than not that the Company's recorded income tax benefits will be fully realized, or recognizes a valuation allowance against deferred tax assets in cases where we do not forecast sufficient future income to recognize the deferred tax asset.
Leases
We record a net operating lease right-of-use ("ROU") asset and operating lease liability on the consolidated balance sheets for all operating leases with a lease term in excess of 12 months.
We enter into contractual lease arrangements to rent buildings, compressors, drilling rigs, office and rental equipment and vehicles from third-party lessors. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make future lease payments arising from the lease. Operating lease ROU assets and liabilities are recorded at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. The Company recognizes lease expense for these short-term leases on a straight-line basis over the lease term. We use our incremental borrowing rate based on the information available at commencement date of the contract in determining the present value of future lease payments. The incremental borrowing rate is calculated using our collateralized incremental borrowing rate based on our debt structure. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. Certain of our leases may also include escalation clauses or options to extend or terminate the lease. These options are included in the present value recorded for the leases when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term.
If an arrangement is determined to be a lease, we record the resulting ROU asset on the consolidated balance sheets with offsetting liabilities at the commencement date. We recognize a lease in the financial statements when the arrangement either explicitly or implicitly involves property, plant or equipment ("PP&E"), the contract terms are dependent on the use of the PP&E, and we have the ability or right to control the PP&E or to direct others to control the PP&E and receive the majority of
the economic benefits of the assets. As of December 31, 2024 and 2023, we had financing right-of-use asset of $18.4 million and $18.5 million in field and other property and equipment, at cost, and operating right-of-use asset of $66.6 million and $24.2 million in Other assets, respectively.
Asset Retirement Obligations
An ARO represents the legal obligation associated with the future abandonment of tangible assets, such as wells, service assets, pipelines, and other facilities. We record an ARO liability and capitalize the asset retirement cost in oil and natural gas properties in the period in which the ARO liability is incurred based upon the estimated fair value of the obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO liability is accreted to its future estimated value using an estimated credited-adjusted risk-free rate and the capitalized asset retirement cost is depleted on a unit-of-production basis. Both the accretion expense and the depletion expense are included in Depreciation, depletion and amortization expense on our consolidated statements of operations.
Measuring the future ARO liability requires management to make estimates, assumptions and judgments inherent in the present value calculation including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. If the ARO liability is settled for an amount other than the recorded amount, a gain or loss is recognized at settlement and included in Depreciation, depletion and amortization expense on our consolidated statements of operations.
See NOTE 9 - Asset Retirement Obligations.
Environmental Expenditures
In addition to our ARO liability, management also reviews our estimates of the cleanup costs of various sites on an annual basis. When it is probable that obligations have been incurred, and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. Recoveries for environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. As of December 31, 2024 and 2023, we did not have any significant probable environmental remediation costs.
Supplemental Cash Flow Disclosures
The following are our supplemental cash flow disclosures for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31,
2024 2023 2022
(in thousands)
Supplemental cash flow disclosures:
Interest paid, net of amounts capitalized $ 141,760 $ 113,796 $ 81,920
Income tax payments (refunds)
1,851 (1,391) 8,164
Non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued liabilities 180,172 83,841 92,518
Equity consideration for acquisitions
611,423 - -
Right-of-use assets obtained in exchange for leases 62,468 29,624 13,343
Recent Accounting Standards
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires public entities, on an annual basis, to provide disclosure of specific categories in the rate reconciliation, as well as disclosure of income taxes paid disaggregated by jurisdiction. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2023-09 but does not expect a material impact.
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires public entities, on an annual and interim basis, to provide enhanced disclosures about significant segment expenses, including entities that have a single reportable segment. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Company adopted ASU 2023-07 during 2024, see NOTE 16 - Segment Information.
In November 2024, the FASB issued ASU 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires public entities to disclose additional information about specific expense categories in the notes to the financial statements on an interim and annual basis. ASU 2024-03 is effective for fiscal years beginning after December 15, 2026, and interim periods within the fiscal year beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating the impact of adopting ASU 2024-03.
NOTE 3 - Acquisitions and Divestitures
During the three years ended December 31, 2024, we completed the following acquisitions and divestitures:
Acquisitions
SilverBow Merger
On July 30, 2024, we consummated the transactions contemplated by the Agreement and Plan of Merger, dated May 15, 2024 (the transactions contemplated therein, the "SilverBow Merger"), between Crescent, SilverBow Resources, Inc. ("SilverBow"), Artemis Acquisition Holdings Inc. ("Artemis Holdings"), Artemis Merger Sub Inc. ("Merger Sub Inc.") and Artemis Merger Sub II LLC ("Merger Sub LLC"). The SilverBow Merger has been accounted for as a business combination using the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations (“ASC 805”), with Crescent being identified as the accounting acquirer.
Merger Sub Inc., a Delaware corporation and a direct wholly owned subsidiary of Crescent, merged with and into SilverBow (the "Initial Merger"), with SilverBow surviving the merger (the "Initial Surviving Corporation"), and immediately following the Initial Merger, the Initial Surviving Corporation merged with and into Merger Sub LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of Artemis Holdings, a Delaware corporation and a direct wholly owned subsidiary of Crescent (the "Subsequent Merger" and together with the Initial Merger, the "Mergers"), with Merger Sub LLC continuing as the surviving company of the Subsequent Merger (the "Subsequent Surviving Company") as a direct wholly owned subsidiary of Artemis Holdings. Promptly following the completion of the Mergers, Artemis Holdings contributed the Subsequent Surviving Company to Crescent Energy OpCo LLC, a Delaware limited liability company, of which Crescent is the managing member, which in turn contributed the Subsequent Surviving Company to its wholly owned subsidiary, Crescent Energy Finance, a Delaware limited liability company.
Subject to the terms and conditions of the Merger Agreement, each share of SilverBow's common stock, par value $0.01 per share ("SilverBow Common Stock") issued and outstanding immediately prior to the merger close date, was converted into the right to receive, pursuant to an election made and not revoked, one of the following forms of consideration: (A) 3.125 shares of Crescent Class A Common Stock, (B) a combination of 1.866 shares of Crescent Class A Common Stock and $15.31 in cash or (C) $38.00 in cash, subject to an aggregate cap of $400.0 million on the total cash consideration payable for the SilverBow Common Stock in the SilverBow Merger. The Merger Agreement also provided that each outstanding SilverBow restricted stock unit, performance-based stock unit (assuming maximum performance) and in-the money stock option, whether vested or unvested, held by certain employees and directors of SilverBow (collectively, the "SilverBow Equity Awards") became fully vested and was canceled and converted into a right to receive a cash payment (less the exercise price in the case of stock options) or, in the case of the restricted stock units and performance-based stock units, a partial cash payment and partial settlement in shares of Crescent Class A Common Stock. Each stock option with an exercise price that equaled or exceeded the amount of such cash payment was cancelled for no consideration. See the table below for consideration transferred and preliminary purchase price allocation. Certain data necessary to complete the final purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of SilverBow’s assets and liabilities. We expect to complete the purchase price allocation during the 12-month period following the acquisition date. Crescent issued 51.6 million shares of Class A Common Stock in the SilverBow Merger and paid $382.4 million in cash to former SilverBow shareholders, including amounts payable in respect of outstanding SilverBow equity awards. See NOTE 13 - Equity-Based Compensation Awards.
From the date of the SilverBow Merger through December 31, 2024, revenues and net income associated with operations acquired through the SilverBow Merger were $430.2 million and $156.9 million, respectively. We recognized transaction related expenses of $42.8 million within General and administrative expense on the consolidated statements of operations for the year ended December 31, 2024.
The following table summarizes our unaudited pro forma financial information for the years ended December 31, 2024 and 2023 as if the SilverBow Merger and Central Eagle Ford Acquisition occurred on January 1, 2023 (unaudited):
Year Ended December 31,
2024 2023
(in thousands)
Revenues $ 3,582,776 $ 3,610,300
Net income
10,158 782,563
As part of the SilverBow Merger we acquired a deferred acquisition liability from historical SilverBow acquisitions. Per the terms of the acquired contract we were required to make a $75.0 million payment in the fourth quarter of 2024 related to deferred purchase consideration of $50.0 million and a WTI-based contingent earn-out payment of $25.0 million since the average settlement price of WTI was between $75 per barrel and $80 per barrel during the 12-month period that began in December 2023.
During 2024 we reorganized our business, primarily as a result of the SilverBow Merger, which included one-time termination costs and exit costs for the closure of one of our offices. During the year ended December 31, 2024, we expect the total amount of one-time employee termination benefits incurred to be $11.4 million and lease termination and other costs of $5.5 million, of which $14.3 million were recognized in General and Administrative expense and $2.7 million were recognized in Asset operating expense, respectively, on the consolidated statements of operations. The following is a reconciliation of our restructuring liability, which is included within Accounts payable and accrued liabilities on the consolidated balance sheets.
One-time employee termination benefits
Lease termination and other costs
Total
(in thousands)
December 31, 2023 $ - $ - $ -
Costs incurred and charged to expense 11,433 5,516 16,949
Costs paid (6,531) (5,516) (12,047)
December 31, 2024 $ 4,902 $ - $ 4,902
Other Acquisitions
Central Eagle Ford Acquisition
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 (the “Central Eagle Ford Acquisition”).
The Central Eagle Ford Acquisition has been accounted for as a business combination using the acquisition method of accounting in accordance with ASC 805, with Crescent being identified as the accounting acquirer. From the date of the Central Eagle Ford Acquisition through December 31, 2024, revenues and net income associated with operations acquired through the Central Eagle Ford Acquisition were $10.4 million and $3.1 million, respectively. We recognized transaction related expenses of $5.6 million within General and administrative expense on the consolidated statements of operations for the year ended December 31, 2024.
Eagle Ford Minerals Acquisition
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.
Western Eagle Ford Acquisitions
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 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.
Uinta Transaction
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 in NOTE 8 - Debt). In addition, subsequent to the closing date but during the year ended December 31, 2022, we recorded $11.1 million in customary purchase price adjustments that increased our total purchase price to $632.4 million. 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 in 2022, 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.
Consideration Transferred
The following table summarizes the consideration transferred and the net assets acquired for our significant asset acquisitions and business combinations during the three years ended December 31, 2024 that impact the periods presented:
Asset Acquisitions
Business Combinations
Eagle Ford Minerals Acquisition July Western Eagle Ford Acquisition October Western Eagle Ford Acquisition Uinta Transaction SilverBow Merger Central Eagle Ford Acquisition
(in thousands)
Consideration transferred:
Cash consideration:
Cash paid $ 25,000 $ 592,735 $ 235,069 $ 632,400 $ 358,092 $ 156,031
Settlement of SilverBow Equity Awards in cash - - - - 18,858 -
Equity consideration:
Fair value of Class A Common Stock issued to SilverBow Common stockholders - - - - 595,294 -
Settlement of SilverBow Equity Awards in Class A Common Stock - - - - 16,129 -
Total $ 25,000 $ 592,735 $ 235,069 $ 632,400 $ 988,373 $ 156,031
Assets acquired and liabilities assumed:
Cash and cash equivalents $ - $ - $ - $ - $ 5,200 $ -
Accounts receivable, net - - - - 140,073 -
Derivative assets - current - - - - 100,601 -
Prepaid expenses - 355 - - 6,154 -
Other current assets - - - - 945 -
Oil and natural gas properties - proved 12,865 595,025 239,573 785,150 1,980,500 144,085
Oil and natural gas properties - unproved 12,135 22,310 9,819 70,057 207,191 -
Field and other property and equipment - - - 8,374 4,586 17,848
Derivative assets - noncurrent - - - - 37,870 -
Other assets - - - - 25,199 -
Accounts payable and accrued liabilities - (12,668) (5,790) - (196,963) (1,212)
Acquired deferred acquisition consideration
- - - - (76,550) -
Other current liabilities - - - - (10,029) -
Derivative liabilities - current - - - (179,696) - -
Short-term debt - - - - (37,500) -
Long-term debt - - - - (1,103,125) -
Deferred tax liability - - - - (58,670) -
Asset retirement obligations - (10,541) (7,908) (37,203) (25,683) (4,690)
Other liabilities - (1,746) (625) (14,282) (11,426) -
Net assets acquired $ 25,000 $ 592,735 $ 235,069 $ 632,400 $ 988,373 $ 156,031
Divestitures
During the years ended 2024 and 2023, we sold non-core assets to unrelated third-party buyers for $54.8 million and $28.9 million in aggregate cash proceeds, respectively, and recorded a gain of approximately $29.4 million during the year ended 2024 on the sale of these assets.
Permian Basin Divestiture
On November 4, 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 this transaction in December 2022 and recorded a loss of $0.9 million during the year ended December 31, 2022.
Exaro
In April 2022, our equity method investee, 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 from Exaro of $6.8 million primarily as a result of the sale.
Chama
In February 2022, we contributed all of the assets and prospects in the U.S.Gulf formerly owned by Contango to 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 investment in equity affiliates 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.
NOTE 4 - Property, Plant and Equipment
The following table summarizes our oil and natural gas properties as of December 31, 2024 and 2023:
As of December 31,
2024 2023
(in thousands)
Proved oil and natural gas properties (successful efforts method) $ 11,471,299 $ 8,574,478
Unproved oil and natural gas properties 374,306 283,324
Oil and natural gas properties, at cost 11,845,605 8,857,802
Less: accumulated depreciation, depletion, amortization and impairment (3,840,344) (2,865,095)
Oil and natural gas properties, net $ 8,005,261 $ 5,992,707
Other Property
The following table summarizes other property, plant and equipment as of December 31, 2024 and 2023:
Estimated useful life As of December 31,
2024 2023
(years) (in thousands)
Gathering and pipeline system 30 $ 109,324 $ 106,023
Vehicles 3-5
19,309 16,420
Computers, furniture, and equipment 3-10
12,491 7,733
Buildings and improvements 5-30
14,177 13,452
Land 20,694 5,374
Financing right of use asset 1-5
18,435 18,454
Field inventory 32,441 31,114
Field and other property and equipment, at cost 226,871 198,570
Less: accumulated depreciation, amortization and impairment (87,078) (75,451)
Field and other property and equipment, net $ 139,793 $ 123,119
Capitalized Exploratory Well Costs
Capitalized exploratory well costs are included in unproved oil and natural gas properties. As of December 31, 2024 and 2023, we did not have any capitalized exploratory well costs.
NOTE 5 - Derivatives
In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our Revolving Credit Facility that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks.
As of December 31, 2024, our commodity derivative instruments consisted of fixed price and basis swaps and collars which are described below:
Fixed Price and Basis Swaps: Fixed price swaps receive a fixed price and pay a floating market price to counterparty on the notional amount. Our basis swaps fix the basis differentials between the index price at which we sell our production as compared to the index price used in the basis swap. Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty if the settlement price is greater than the fixed price.
Collars: Collars provide a minimum and maximum price on a notional amount of sales volume. Under a collar, we will receive payment if the settlement price is less than the minimum price of the range and make a payment to the counterparty if the settlement price is greater than the maximum price of the range. We would not be required to make a payment or receive payment if the settlement price falls within the range.
The following table details our net volume positions by commodity as of December 31, 2024:
Production Period
Volumes
Weighted
Average Fixed
Price
Fair Value
(in thousands) (in thousands)
Crude oil swaps - WTI (Bbls):
2025 14,837 $70.14 $ 7,971
2026 4,301 $68.71 8,975
2026 (1)
2,738 $76.31 (7,569)
2027 (2)
3,650 $75.00 (10,770)
Crude oil collars - WTI (Bbls):
5,576 $ 62.33 - $ 79.10 3,750
273 $ 64.00 - $ 71.50 280
2026 (3)
730 $ 65.00 - $ 76.00 (2,275)
Crude oil collars - Brent (Bbls):
2025 365 $ 65.00 - $ 91.61 579
Natural gas swaps (MMBtu):
2025 57,760 $3.95 25,655
2026 45,395 $3.96 2,445
Natural gas collars (MMBtu):
2025 74,009 $ 3.12 - $ 5.74 11,285
2026 40,100 $ 3.02 - $ 4.65 (7,476)
NGL swaps (Bbls):
2025 1,460 $23.88 (2,072)
Crude oil basis swaps (Bbls):
2025 17,240 $1.62 4,084
2026 3,831 $1.85 547
Natural gas basis swaps (MMBtu):
2025 105,347 $(0.26) 1,065
2026 76,600 $(0.44) (10,028)
2027 36,500 $(0.38) (5,177)
Calendar Month Average roll swaps (Bbls):
2025 12,958 $0.31 (1,742)
Total $ 19,527
(1) Represents outstanding crude oil swap options exercisable by the counterparty until December 2025.
(2) Represents outstanding crude oil swap options exercisable by the counterparty until December 2026.
(3) Represents outstanding crude oil collar options exercisable by the counterparty until December 2025.
We use derivative commodity instruments and enter into swap contracts which are governed by International Swaps and Derivatives Association ("ISDA") master agreements. The following table shows the effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2024 and 2023:
Gross Fair
Value
Effect of
Counterparty
Netting
Net Carrying
Value
(in thousands)
December 31, 2024
Assets:
Derivative assets - current $ 95,484 $ (42,211) $ 53,273
Derivative assets - noncurrent 25,287 (18,603) 6,684
Total assets $ 120,771 $ (60,814) $ 59,957
Liabilities:
Derivative liabilities - current $ (44,909) $ 42,211 $ (2,698)
Derivative liabilities - noncurrent
(56,335) 18,603 (37,732)
Total liabilities $ (101,244) $ 60,814 $ (40,430)
December 31, 2023
Assets:
Derivative assets - current $ 93,720 $ (39,399) $ 54,321
Derivative assets - noncurrent 22,686 (14,620) 8,066
Total assets $ 116,406 $ (54,019) $ 62,387
Liabilities:
Derivative liabilities - current $ (81,450) $ 39,399 $ (42,051)
Derivative liabilities - noncurrent
(14,620) 14,620 -
Total liabilities $ (96,070) $ 54,019 $ (42,051)
See NOTE 6 - Fair Value Measurements for more information.
The amount of realized and unrealized gain (loss) recognized in Gain (loss) on derivatives in our consolidated statements of operations was as follows for the years ended December 31, 2024, 2023 and 2022:
Years ended December 31,
2024 2023 2022
(in thousands)
Derivatives not designated as hedging instruments:
Realized gain (loss) on oil positions $ (112,777) $ (171,274) $ (395,147)
Realized gain (loss) on natural gas positions 77,546 (1,022) (327,098)
Realized gain (loss) on NGL positions (623) 18,562 (57,015)
Total realized gain (loss) on derivatives
(35,854) (153,734) (779,260)
Unrealized gain (loss) on commodity derivatives
(78,494) 320,714 102,358
Gain (loss) on derivatives
$ (114,348) $ 166,980 $ (676,902)
During the year ended December 31, 2022, we settled certain of our outstanding derivative oil commodity contracts for open positions associated with calendar years 2022 and 2023. Subsequent to the settlements, we entered into new commodity derivative contracts at prevailing market prices.
NOTE 6 - Fair Value Measurements
GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Generally, the determination of fair value requires the use of significant judgment and different approaches and models under varying circumstances. Under a market-based approach, we consider prices of similar assets, consult with brokers and experts, or employ other valuation techniques. Under an income-based approach, we generally estimate future cash flows and then discount them at a risk-adjusted rate. We classify the inputs used to measure the fair value of our financial assets and liabilities into the following hierarchy:
Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable, either directly or indirectly, and can be corroborated by observable market data.
Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of significance for a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities within the fair value hierarchy levels.
Recurring Fair Value Measurements
The following table presents the location and fair value of our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2024 and 2023, by level within the fair value hierarchy:
Fair Value Measurement Using
Level 1 Level 2 Level 3 Total
(in thousands)
December 31, 2024
Financial assets:
Derivative assets $ - $ 120,771 $ - $ 120,771
Financial Liabilities:
Derivative liabilities $ - $ (101,244) $ - $ (101,244)
December 31, 2023
Financial assets:
Derivative assets $ - $ 116,406 $ - $ 116,406
Financial Liabilities:
Derivative liabilities $ - $ (96,070) $ - $ (96,070)
Non-Recurring Fair Value Measurements
Certain nonfinancial assets and liabilities are measured at fair value on a non-recurring basis. We utilize fair value measurement on a non-recurring basis to value our oil and natural gas properties when the carrying value of such property exceeds the respective undiscounted future cash flows. We also utilize fair value measurement on a non-recurring basis to value our goodwill when the carrying value of such reporting unit exceeds the respective discounted future cash flows. The inputs used to determine such fair values are primarily based upon internally developed cash flow models, as well as market-based valuations as discussed in Note 2 and are classified within Level 3.
As stated in NOTE 2 - Summary of Significant Accounting Policies, our oil and natural gas properties were written down to their fair value resulting in an impairment expense. During the year ended December 31, 2024, we recorded impairment expense of $161.5 million related to Oil and natural gas properties with a carrying value of $345.9 million that was determined to not be recoverable and a fair value of $184.4 million. During the year ended December 31, 2023, we recorded impairment expense of
$153.5 million related to Oil and natural gas properties and Investments in equity affiliates. We recorded an impairment of $149.6 million related to Oil and natural gas properties with a carrying value of $238.1 million that was determined to not be recoverable and a fair value of $88.5 million. We also recorded an other-than-temporary impairment of $3.9 million related to Investments in equity affiliates for an investment that was determined to be fully impaired. The fair value was determined using a discounted cash flow model based on the expected present value of the future net cash flows from our oil and natural gas reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include estimates of (i) future prices based on the forward commodity price curve as of December 31, 2024, (ii) production costs, development expenditures and anticipated production, based on our 2024 net proved reserves, and (iii) a risk-adjusted discount rate of 10%.
Our other non-recurring fair value measurements include the estimates of the fair value of assets and liabilities acquired through business combinations. Our business combinations are accounted for using the acquisition method under GAAP, which requires all assets acquired and liabilities assumed in the acquisitions to be recorded at fair values at the acquisition date of each transaction. Oil and natural gas properties were valued based on an income approach using a discounted cash flow model utilizing Level 3 inputs, including internally generated development and production profiles and price and cost assumptions. Net derivative liabilities assumed in the acquisitions were valued based on Level 2 inputs similar to the Company's other commodity price derivatives. See NOTE 3 - Acquisitions and Divestitures.
Other Fair Value Measurements
The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Our long-term debt obligations under our Revolving Credit Facility also approximate fair value because the associated variable rates of interest are market based. The fair value of the Senior Notes as of December 31, 2024 and 2023 was $3,113.8 million and $1,750.7 million based on quoted market prices or Level 1 inputs.
NOTE 7 - Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities consisted of the following as of December 31, 2024 and 2023:
As of December 31,
2024 2023
(in thousands)
Accounts payable and accrued liabilities:
Accounts payable $ 56,323 $ 125,010
Accrued lease and asset operating expense 76,990 58,847
Accrued capital expenditure 171,365 74,206
Accrued general and administrative 15,044 16,441
Accrued gathering, transportation and marketing expense 76,477 56,088
Accrued revenue and royalties payable 192,884 154,345
Accrued interest expense 98,343 45,546
Accrued severance taxes 36,135 58,100
Other 16,891 24,960
Total accounts payable and accrued liabilities $ 740,452 $ 613,543
NOTE 8 - Debt
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 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.
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
Overview
We are party to 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 Revolving Credit Facility matures on April 10, 2029, but contains terms that if certain conditions regarding our outstanding 2028 Notes exist on November 16, 2027, it will mature on November 16, 2027. At December 31, 2024, we had no outstanding borrowings and $21.2 million in letters of credit outstanding under the Revolving Credit Facility.
The obligations under the Revolving Credit Facility remain secured by first priority liens on substantially all of the Company’s and the guarantors’ tangible and intangible assets, including without limitation, oil and natural gas properties and associated assets and equity interests owned by the Company and such guarantors. In connection with each redetermination of the borrowing base, the Company must maintain mortgages on at least 85% of the net present value, discounted at 9% per annum (“PV-9”) of the oil and natural gas properties that constitute borrowing base properties. The Company’s domestic direct and indirect subsidiaries are required to be guarantors under the Revolving Credit Facility, subject to certain exceptions.
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 (i)
the issuance of certain permitted junior lien debt and other permitted additional debt, (ii) the sale or other disposition of borrowing base properties if the aggregate PV-9 of such properties sold or disposed of is in excess of 5.0% of the borrowing base then in effect and (iii) early termination or set-off of swap agreements (a) the administrative agent relied on in determining the borrowing base or (b) if the value of such swap agreements so terminated is in excess of 5.0% of the borrowing base then in effect.
Interest
Borrowings under the Revolving Credit Facility bear interest at either (i) a 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 and fees incurred are included within Interest expense on our consolidated statements of operations. Our weighted average interest rate on loan amounts outstanding as of December 31, 2023 was 9.75%. We had no borrowing outstanding under the Revolving Credit Facility at December 31, 2024.
Covenants
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 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.
Letters of Credit
From time to time, we may request the issuance of letters of credit for our own account. Letters of credit accrue interest at a rate equal to the margin associated with SOFR borrowings. At December 31, 2024 and 2023, we had letters of credit outstanding of $21.2 million and $14.4 million, respectively, which reduces the amount available to borrow under our Revolving Credit Facility.
The following table summarizes our debt balances as of December 31, 2024 and 2023:
Debt
Outstanding
Letters of Credit
Issued
Borrowing
Base
Maturity
(in thousands)
December 31, 2024
Revolving Credit Facility
$ - $ 21,186 $ 2,600,000 4/10/2029
9.250% Senior Notes due 2028
1,000,000 - - 2/15/2028
7.625% Senior Notes due 2032
1,100,000 - - 4/1/2032
7.375% Senior Notes due 2033
1,000,000 - - 1/15/2033
Less: Unamortized discount, premium and issuance costs (50,745)
Total long-term debt $ 3,049,255
December 31, 2023
Revolving Credit Facility $ 23,500 $ 14,408 $ 2,000,000 9/23/2027
7.250% Senior Notes due 2026
700,000 - - 5/1/2026
9.250% Senior Notes due 2028
1,000,000 - - 2/15/2028
Less: Unamortized discount, premium and issuance costs (29,125)
Total long-term debt $ 1,694,375
NOTE 9 - Asset Retirement Obligations
Our ARO liabilities are based on our net ownership in wells and facilities and management’s estimate of the costs to abandon and remediate those wells and facilities together with management’s estimate of the future timing of the costs to be incurred. The following table summarizes activity related to our ARO liabilities for the years ended December 31, 2024 and 2023:
Year Ended December 31,
2024 2023
(in thousands)
Balance at beginning of period
$ 445,060 $ 365,614
Additions(1)
43,784 34,460
Retirements (13,399) (10,046)
Accretion expense 31,527 27,782
Revisions 35,230 29,002
Sale (56,034) (1,752)
Balance at end of period 486,168 445,060
Less: current portion (37,223) (26,741)
Balance at end of period, noncurrent portion $ 448,945 $ 418,319
(1)During the year ended December 31, 2024, our ARO additions primarily related to oil and natural gas properties acquired in the SilverBow Merger and the Central Eagle Ford Acquisition. During the year ended December 31, 2023, our ARO additions primarily related to properties acquired in the Western Eagle Ford Acquisitions. See NOTE 3 - Acquisitions and Divestitures for additional information.
NOTE 10 - Equity and Redeemable Noncontrolling Interests
Equity
Class A and Class B Common Stock
As of December 31, 2024 and 2023, we had 187,070,725 and 91,608,800 shares of Class A Common Stock and 65,948,124 and 88,048,124 shares of Class B Common Stock outstanding, respectively. Our Class A Common Stock is publicly traded, while our Class B Common Stock is 100% owned by the former owners of Independence. We paid dividends of $0.48 and $0.53 per share of Class A Common Stock during the years ended December 31, 2024 and 2023, respectively.
Equity Transactions
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 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").
As a result of the December 2024, April 2024 Class A Redemption and the March 2024 Equity Transactions (the "2024 Equity Transactions"), the total number of shares of our Class A Common Stock increased by 44.5 million shares and the total number of shares of our Class B Common Stock decreased by 22.1 million shares. Redeemable noncontrolling interests decreased by $515.0 million while APIC increased by $821.5 million as a result of the 2024 Equity Transactions.
2023 Equity Transactions
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 includes 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 such issuance (the "2023 Equity Issuance," and together with the 2024 Equity Issuance, the "Equity Issuances"), after deducting underwriting fees and expenses.
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"); 27.6 million of such shares of Class A Common Stock were subsequently distributed to certain of its legacy investors in privately-managed funds and accounts; 3.0 million of such shares of Class A Common Stock were subsequently sold by such affiliate 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.
2022 Equity Transactions
In September 2022, Independence Energy Aggregator L.P., the entity through which certain affiliated entities held 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 Energy Holdings LLC 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 "2022 Equity Transactions"). As a result of the 2022 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 Independence Energy Aggregator L.P. to affiliates, and the number of shares of our Class B Common Stock decreased by approximately 8.9 million. Redeemable noncontrolling interests decreased by $158.1 million while APIC increased by $121.8 million as a result of the 2022 Equity Transactions and to reflect the new ownership of OpCo.
Treasury stock
At December 31, 2024 and 2023, our treasury stock shares represent shares we withheld associated with the payroll tax withholding obligations due from employees upon the vesting of stock awards. We include the shares withheld as Treasury stock on our consolidated balance sheets and separately pay the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of our Class A Common Stock and are accounted for at cost.
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 repurchases may be made by Crescent or by OpCo, as applicable, and may be made from time to time in the open market, in privately negotiated transactions, 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 stock 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. The 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA 2022 applies to repurchases of our Class A Common Stock pursuant to our stock repurchase program.
We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction to equity on our consolidated balance sheets. For the year ended December 31, 2024, we repurchased 0.7 million shares of our Class A Common Stock for $7.8 million, at an average price of $10.70 per share ("2024 Class A Repurchases"), and in connection therewith, we cancelled a corresponding number of OpCo units held by us. When combining our 2024 Class A Repurchases with our March 2024 Repurchase, we have $119.5 million remaining under our stock repurchase program.
Noncontrolling interests
We record noncontrolling interest associated with third party ownership interests in our subsidiaries. Income or loss associated with these interests is classified as net income (loss) attributable to noncontrolling interest on our consolidated statements of operations.
Redeemable Noncontrolling Interests
In 2021, 127.5 million OpCo Units were issued to the former owners of Independence. The former owners of Independence also own all outstanding shares of our Class B Common Stock. Pursuant to the OpCo LLC Agreement, holders of OpCo Units, other than the Company, may redeem all or a portion of their OpCo Units, together with a corresponding number of shares of Class B Common Stock, for either (a) shares of Class A Common Stock or (b) an approximately equivalent amount of cash as determined pursuant to the terms of the OpCo LLC Agreement, at the election of the Company. In connection with the exercise of such redemption, a corresponding number of shares of Class B Common Stock will be cancelled. The redemption election is not considered to be within the control of the Company because the holders of Class B Common Stock and their affiliates control the Company through direct representation on the Board of Directors. As a result, we present the noncontrolling interests in OpCo as redeemable noncontrolling interests outside of permanent equity. Redeemable noncontrolling interest is recorded at the greater of the carrying value or redemption amount with a corresponding adjustment to additional paid-in capital. The redemption amount is based on the 10-day volume-weighted average closing price (“VWAP”) of Class A Common Stock at the end of the reporting period. Changes in the redemption value are recognized immediately as they occur, as if the end of the reporting period was also the redemption date for the instrument, with an offsetting entry to additional paid-in capital.
The 2024 Equity Transactions reduced the number of shares of our Class B Common Stock by 22.1 million shares. In addition, the 2024 Equity Transactions resulted in the transfer of 19.8 million OpCo Units to Crescent and the repurchase, by OpCo, of 2.3 million OpCo Units for $22.7 million in cash. As a result of the transfer of additional OpCo Units to Crescent, we reclassified $448.0 million from Redeemable noncontrolling interests to Additional paid-in capital.
In September 2023, the proceeds from the 2023 Equity Issuance, including the exercise of the underwriters' over-allotment, were contributed by Crescent to OpCo in exchange for 12.7 million OpCo Units. As a result of the additional OpCo Units owned by Crescent, we reclassified $65.8 million from Redeemable noncontrolling interests to Additional paid-in capital.
During 2023, the Class A Conversion reduced the number of shares of our Class B Common Stock outstanding by 30.6 million shares. A corresponding number of OpCo Units were transferred to Crescent, which reduced the value of our Redeemable noncontrolling interests by $679.6 million.
From December 31, 2021 through December 31, 2024, we recorded adjustments to the value of our redeemable noncontrolling interests as shown below:
Redeemable Noncontrolling Interest
(in thousands)
Balance as of December 31, 2021 $ 2,325,013
Net income attributable to redeemable noncontrolling interests 381,257
Contributions 5,985
Distributions (213)
Cash distributions from OpCo initiated by Class A common stock dividend, Manager Compensation and income taxes, net (126,384)
Accrued OpCo cash distribution initiated by Manager Compensation (9,513)
Equity-based compensation 18,623
Cancellation of OpCo Units associated with 2022 Equity Transactions (158,065)
Balance as of December 31, 2022 $ 2,436,703
Net income attributable to redeemable noncontrolling interests 253,909
Contributions 1,238
Distributions (417)
Cash distributions from OpCo initiated by Class A common stock dividend, Manager Compensation and income taxes, net (80,805)
Accrued OpCo cash distribution initiated by Manager Compensation (6,794)
Equity-based compensation 42,782
Change in redeemable noncontrolling interests associated with the Class A Conversions (679,567)
Change in redeemable noncontrolling interests associated with the 2023 Equity Issuance (65,841)
Balance as of December 31, 2023 $ 1,901,208
Net (loss) attributable to redeemable noncontrolling interests (21,863)
Distributions (293)
Cash distributions from OpCo initiated by Class A common stock dividend, Manager Compensation and income taxes, net (48,008)
Accrued OpCo cash distribution initiated by Manager Compensation (4,525)
Equity-based compensation 67,042
Repurchase of redeemable noncontrolling interest (10,569)
Change in redeemable noncontrolling interests associated with the 2024 Equity Transactions (514,955)
Change in redeemable noncontrolling interests associated with the SilverBow Merger (143,540)
Cancellation of OpCo Units associated with 2024 Class A Repurchases 3,832
Balance as of December 31, 2024 $ 1,228,329
NOTE 11 - Income Taxes
We are subject to U.S. federal income and state tax on our allocable share of any taxable income of OpCo.
During the years ended December 31, 2024 and 2023, we decreased APIC by $84.7 million and $92.5 million, respectively, related to a change in the deferred tax liability related to our estimated basis in our ownership interests in OpCo as a result of the 2024 Equity Issuances, the SilverBow Merger, Class A Conversions and 2023 Equity Issuance. As of December 31, 2024 and 2023, we did not have any uncertain tax positions.
Details of current and deferred income taxes are provided in the following tables:
Year Ended December 31,
2024 2023 2022
Federal income tax expense (benefit) (in thousands)
Current
$ 1,422 $ (17) $ 323
Deferred (39,379) 19,520 38,002
State income tax expense (benefit)
Current
3,360 511 2,790
Deferred 3,525 3,213 (4,824)
Total income tax expense (benefit) $ (31,072) $ 23,227 $ 36,291
The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows:
Year Ended December 31,
2024 2023 2022
Federal income taxes statutory rate 21.0 % 21.0 % 21.0 %
Change in rate as a result of:
State income tax provision, net of federal benefit (3.1) % 1.0 % (0.6) %
SilverBow Merger transaction costs
3.1 % - % - %
Change in valuation allowance (1)
(0.6) % - % 2.6 %
Permanent adjustments
(0.1) % - % 0.9 %
Income attributable to noncontrolling interests and redeemable noncontrolling interests (2.6) % (15.3) % (15.6) %
Other 0.7 % - % (1.3) %
Effective income tax rate 18.4 % 6.7 % 7.0 %
(1)During the years ended December 31, 2024 and 2022, we recognized changes in the valuation allowance related to our recognized built-in loss ("RBIL") deferred tax asset as it was not more likely than not to be fully utilized.
Significant components of the Company's deferred income taxes were as follows:
Year Ended December 31,
2024 2023
Deferred tax liabilities (in thousands)
Outside basis in OpCo $ 529,071 $ 284,533
OpCo state deferred tax 13,832 4,232
Total deferred tax liabilities 542,903 288,765
Deferred tax assets
U.S. federal and state NOLs (1)
132,811 32,381
Recognized built-in loss carryforward 21,637 20,622
NOL and RBIL valuation allowance (45,136) (44,121)
Equity-based compensation 47,402 10,630
Other 15,860 6,672
Total deferred tax assets, net of valuation allowance 172,574 26,184
Net deferred income tax liability $ 370,329 $ 262,581
(1)At December 31, 2024 and 2023, we had U.S. federal net operating loss carryforwards ("NOLs") of $1.9 million, net of tax, that have expiration dates beginning in 2029. At December 31, 2024 and 2023, we also have U.S. federal NOLs of $130.4 million and $30.0 million, net of tax, that were generated after 2017 and have indefinite lives but are limited to offsetting 80% of taxable income in a given tax year.
In July 2024, we completed the SilverBow Merger, see NOTE 3 - Acquisitions and Divestitures for more information. As part of the preliminary purchase price allocation, we recognized a net deferred tax liability of $58.7 million to reflect differences
between tax basis and the fair value of SilverBow’s assets acquired and liabilities assumed. Tax attributes related to U.S. federal NOLs and interest expense are included in the net deferred tax liability. Due to the change of ownership of SilverBow in connection with the SilverBow Merger, the availability of these attributes will have utilization limitations under Section 382.
We assess the available positive and negative evidence to determine if sufficient future taxable income will be generated to use the existing deferred tax assets. On the basis of this evaluation, as of December 31, 2024 and 2023, a valuation allowance has been recorded to recognize only the portion of the deferred tax assets that are more likely than not to be realized. The amount of the deferred tax asset considered realizable, however, could be adjusted in the future.
As of December 31, 2024 and 2023, we had U.S. federal and state NOLs of $132.8 million and $32.4 million, respectively. A portion of these NOLs are subject to a valuation allowance of $23.5 million as of December 31, 2024 and 2023, respectively, because we do not believe they will be recoverable as a result of limitations on their use under Section 382. During the year ended December 31, 2024 and 2023 we recorded an additional $1.0 million and $19.3 million valuation allowance related to recognized built-in-loss ("RBIL") property that was also subject to the Section 382 limitation. At December 31, 2024 and 2023, the valuation allowance related to our RBIL carryforward was $21.6 million and $20.6 million, respectively.
As we noted above, we have U.S. federal net operating loss ("NOL") carryforwards and recognized built-in-loss ("RBIL") that are subject to limitation under Section 382. Pursuant to Section 382 and 383 of the U.S. Internal Revenue Code of 1986, as amended, utilization of our NOL and RBIL carryforwards is subject to an annual limitation. These annual limitations may resulted in the expiration of NOL and RBIL carryforwards prior to utilization; accordingly we have maintained a valuation allowance related to U.S. federal NOL and RBIL carryforwards that we do not believe are recoverable due to these Section 382 limitations.
NOTE 12 - Commitments and Contingencies
From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.
We are subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. We believe we are currently in compliance with all applicable federal, state and local regulations. Accordingly, no significant liability or loss associated with environmental remediation was recognized as of December 31, 2024 and 2023.
Carbon Dioxide Purchase Agreement
We have a take-or-pay carbon dioxide purchase agreement that includes a minimum volume commitment to purchase carbon dioxide at a price stipulated in the contract. The agreement provides carbon dioxide for use in our enhanced recovery projects in certain of our properties. The daily minimum volume commitments are 119 MMcf/per day from June 2021 to May 2026, with the commitment effectively ending in May 2026. We expect to purchase more carbon dioxide through the end of the agreement in 2026 than our minimum volume commitments, and, in accordance with the agreement, if we do not meet our minimum volume commitments for a year (or years), we can make up the volumes in future years through 2029 as long as we pay for our minimum volumes each year. As of December 31, 2024 and 2023, we have met the required minimum volumes.
Oil and Natural Gas Transportation and Gathering Agreements
We have entered into certain oil and natural gas transportation and gathering agreements with various pipeline carriers. Under these agreements, we are obligated to ship minimum daily quantities or pay for any deficiencies at a specified rate. We are also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity that we utilize. If we do not utilize the capacity, we can release it to others, thus reducing our potential liability. We recognized $6.6 million, $15.6 million and $4.5 million of transportation expense in our consolidated statements of operations related to minimum volume deficiencies for the years ended December 31, 2024, 2023 and 2022, respectively.
The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2024:
As of December 31, 2024
(in thousands)
2025 $ 164,314
2026 149,043
2027 141,658
2028 125,075
2029 105,053
Thereafter 220,761
Total minimum future commitments $ 905,904
NOTE 13 - Equity-Based Compensation Awards
Overview
We and certain of our subsidiaries have entered into incentive compensation award agreements to grant profits interest awards, restricted stock units ("RSUs"), performance stock units ("PSUs") and other incentive awards to our employees, our Manager, and non-employee directors. The following table summarizes compensation cost we recognized in connection with our equity-based compensation awards for the years indicated:
Year Ended December 31,
2024 2023 2022
(in thousands)
Equity-based compensation expense (income):
Liability-classified profits interest awards
$ 3,446 $ 298 $ 10,137
Equity-classified profits interest awards
(11,649) 12,799 2,403
Equity-classified LTIP RSU awards
2,999 1,685 1,192
Equity-classified LTIP PSU awards
639 118 -
Equity-classified Manager PSUs
188,138 68,036 24,331
SilverBow Merger awards
9,908 - -
Total equity-based compensation expense (income)
$ 193,481 $ 82,936 $ 38,063
Tax benefit related to equity-based compensation awards
$ 851 $ 277 $ -
Our incentive compensation awards may contain certain service-based, performance-based, and market-based vesting conditions, which are further discussed below.
Equity-based compensation awards
Liability-classified profits interest awards
We issue profits interests that are liability-classified stock-based compensation awards. These 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. Each of these profits interests is liability-classified because of certain features within these awards that predominantly contain characteristics of liability instruments. Compensation cost for these awards is presented within General and administrative expense on the consolidated statements of operations with a corresponding credit to other long-term liabilities on the consolidated balance sheets.
We did not have any unrecognized compensation cost related to time-based unvested liability-classified profits interest awards at December 31, 2024 and 2023. Unrecognized compensation cost related to performance-based unvested liability classified profits interest awards was $2.9 million as of December 31, 2024 and $3.8 million at December 31, 2023, respectively. As of December 31, 2024 and 2023, we carried $4.5 million and $5.8 million in Other liabilities on the consolidated balance sheets, respectively. Transactions involving all of our unvested liability-classified stock-based compensation profits interests awards is summarized below:
Year Ended December 31,
2024 2023 2022
(units in thousands)
Beginning balance 1 1 708
Granted 371 - -
Vested (371) - -
Forfeited - - (707)
Ending balance 1 1 1
(in millions)
Fair value of vested awards $ 7.3 $ - $ -
Cash settlements of liability-classified profits interest awards 7.3 - -
During the year ended December 31, 2022, we entered into amendments to the award agreements of certain of our liability-classified profits interests, which resulted in a modification from liability classification to equity classification. As a result, we recorded a reclassification of $7.3 million from other long-term liabilities to noncontrolling interest on the consolidated balances sheets during the year ended December 31, 2022.
Equity-classified profits interest awards
We issue equity-classified profits interests awards that 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. Each of these profits interests is equity-classified because of certain features within these awards that predominantly contain characteristics of equity instruments. Compensation cost for these awards is presented within General and administrative expense on the consolidated statements of operations with a corresponding credit to Additional paid-in capital on the consolidated balance sheets.
Unrecognized compensation cost related to time-based unvested equity-classified profits interest awards was $0.8 million and $25.4 million at each of December 31, 2024 and 2023 and is expected to be recognized over a remaining weighted average service period of 1.0 year and 2.7 years, respectively. Unrecognized compensation cost related to our performance based equity-classified profits interest awards was $1.5 million and $37.7 million as of December 31, 2024 and 2023, respectively. Transactions involving all of our unvested equity-classified profits interest awards, including weighted average grant date fair values, are summarized below:
Units Weighted average grant date fair value
(in thousands)
Unvested at December 31, 2022 118,801 $ 0.66
Granted 433 54.97
Vested (15) -
Forfeited (12,630) 0.78
Unvested at December 31, 2023 106,589 $ 0.86
Granted - -
Modified - -
Vested (43,905) 0.14
Forfeited (2,784) 29.23
Unvested at December 31, 2024
59,900 $ 0.07
Year Ended December 31,
2024 2023 2022
(in thousands)
Cash settlement of awards during the period $ - $ - $ -
Fair value of awards vested during the period 6,361 - 2,403
Equity-classified LTIP RSU Awards
During the years ended December 31, 2024 and 2023, we granted equity-classified LTIP RSUs under the Crescent Energy Company 2021 Equity Incentive Plan to certain directors, officers and employees. Each LTIP RSU represents the contingent right to receive one share of Class A Common Stock. LTIP RSUs will vest over a period of one to three years, with equity based compensation expense recognized ratably over the applicable vesting period. Compensation cost for these awards is presented within General and administrative expense on the consolidated statements of operations with a corresponding credit to Additional paid-in capital and Redeemable noncontrolling interest on the consolidated balance sheets.
At December 31, 2024 and 2023, we had $2.4 million and $2.4 million of unrecognized compensation cost related to unvested equity-classified LTIP RSU awards, which are expected to be recognized over a remaining weighted average period of 2.1 years and 1.4 years, respectively. The fair value of vested LTIP RSUs during the years ended December 31, 2024 and 2023 was $1.4 million and $1.0 million respectively. Transactions involving all of our unvested equity-classified LTIP RSU awards, including weighted average grant date fair values, are summarized below:
Restricted Stock Units
Weighted average grant date fair value
(in thousands)
Unvested at December 31, 2022 130 $ 18.41
Granted 243 11.74
Vested (86) 18.41
Forfeited - -
Unvested at December 31, 2023 287 $ 12.77
Granted 301 11.45
Vested (116) 11.99
Forfeited (26) 17.42
Unvested at December 31, 2024
446 $ 11.82
Equity-classified LTIP PSU Awards
During the years ended December 31, 2024 and 2023, we granted equity-classified LTIP PSUs under the Crescent Energy Company 2021 Equity Incentive Plan to certain employees. Each LTIP PSU represents the right to receive one share of Class A Common Stock, on such LTIP PSU's performance period end date, modified by an amount ranging from 0% to 240% based on certain absolute and relative shareholder return components. Compensation cost for these awards is presented within General and administrative expense on the consolidated statements of operations with a corresponding credit to Additional paid-in capital and Redeemable noncontrolling interest on the consolidated balance sheets.
At December 31, 2024 and 2023, we had $1.6 million and $2.2 million of unrecognized compensation cost related to unvested equity-classified LTIP PSU Awards, which are expected to be recognized over a remaining weighted average period of 2.4 years and 3.7 years. Transactions involving all of our unvested equity-classified LTIP PSU awards, including weighted average grant date fair value, are summarized below:
Target Class A Shares Weighted average grant date fair value
(in thousands)
Unvested at December 31, 2022 - $ -
Granted 102 22.75
Vested - -
Forfeited - -
Unvested at December 31, 2023 102 $ 22.75
Granted - -
Vested - -
Forfeited - -
Unvested at December 31, 2024 102 $ 22.75
Equity-classified Manager PSU Awards
We have equity-classified Manager PSUs that were granted in accordance with the Manager Incentive Plan. The Manager PSU performance periods are generally three years with the performance period end dates ranging from December 2024 through December 2028. Each Manager PSU represents the right to receive a target 2% of our issued and outstanding Class A Common Stock on such Manager PSU's performance period end date, modified by an amount ranging from 0% to 240% based on certain absolute and relative shareholder return components. Compensation cost for these awards is presented within General and administrative expense on the consolidated statements of operations with a corresponding credit to Additional paid-in capital and Redeemable noncontrolling interest on the consolidated balance sheets.
During the year ended December 31, 2024, in conjunction with the 2024 Equity Transactions, the closing of the SilverBow Merger, 2024 Class A Repurchases and LTIP RSU award vesting, we increased our Class A Common Stock share count by 95.5 million shares. As a result, the number of equity-classified Manager PSU target shares of Class A Common Stock related to the Crescent Energy Company 2021 Manager Incentive Plan increased by approximately 9.5 million shares. We accounted for this increase as a change in estimate and recognized additional expense of $121.8 million during the year ended December 31, 2024. See NOTE 3 - Acquisitions and Divestitures for more information. The certification of the Company's level of achievement with respect to the first Target PSU for the first three-year-performance period under the Incentive Compensation is in process and is expected to be completed in 2025.
During the year ended December 31, 2023, in conjunction with the 2023 Equity Issuance, Class A Conversions and LTIP RSU award vesting, we increased our Class A Common Stock share count by 43.3 million shares. As a result, the number of equity-classified Manager PSU target Class A Shares granted under the Crescent Energy Company 2021 Manager Incentive Plan increased by 4.3 million shares. We accounted for this increase as a change in estimate and recognized additional expense of $30.4 million during the year ended December 31, 2023.
Unrecognized compensation cost related to unvested awards was $144.0 million and $114.9 million, at a weighted average grant date fair value of $22.75 per share as of December 31, 2024 and 2023, and is expected to be recognized over a remaining weighted-average period of 2.4 years and 2.9 years, respectively. Transactions involving all of our unvested Manager PSUs are summarized below:
Target Class A Shares
(in thousands)
Unvested at December 31, 2022 4,827
Granted 4,333
Vested -
Forfeited -
Unvested at December 31, 2023 9,160
Granted 9,546
Vested (3,741)
Forfeited -
Unvested at December 31, 2024
14,965
SilverBow Merger Awards
On July 30, 2024, in accordance with the Agreement and Plan of Merger, certain of the outstanding SilverBow Equity Awards were modified to be accelerated to vest immediately and certain of the outstanding SilverBow Equity Awards were modified to vest at the maximum level of performance. Accordingly, we recognized a portion of this settlement as consideration transferred in the SilverBow Merger and the remaining settlement was recognized as a one-time charge to equity based compensation expense within General and administrative expense on the consolidated statements of operations during the year ended December 31, 2024. See NOTE 3 - Acquisitions and Divestitures for more information.
NOTE 14 - Related Party Transactions
KKR Group
Management Agreement
Crescent Energy Company has a management agreement (the "Management Agreement") with KKR Energy Assets Manager LLC (the "Manager"). Pursuant to the Management Agreement, the Manager provides the Company with its senior executive management team and certain management services. The Management Agreement had an initial term of three years that began in 2021 and was automatically renewed in December 2024 for an additional three-year term ending December 7, 2027 and will have automatic three-year renewals thereafter, unless the Company or the Manager elects not to renew the Management Agreement.
As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive compensation from the Company equal to $51.3 million per annum ("Manager Compensation") (calculated based on the Company's pro rata relative ownership of OpCo multiplied by $69.4 million (the "Base Input"), which is included in General administrative expenses on our consolidated statements of operations. As the Company's business and assets expand, the Base Input will increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our primary equity securities by the Company (including in connection with acquisitions) and increased by $14.0 million during the year ended December 31, 2024 in conjunction with the closing of the SilverBow Merger and December 2024 Equity Issuance. However, the Base Input will not increase from the issuance of the Company's shares upon the redemption or exchange of OpCo Units. See NOTE 3 - Acquisitions and Divestitures for more information.
The Company expects its ownership percentage of OpCo will increase over time through the redemption of OpCo Units for shares of Class A Common Stock or the issuance of additional shares of Class A Common Stock. As this occurs, the Manager Compensation pursuant to the formula defined in the Management Agreement, which is reflected in our consolidated statements of operations, will increase. In order to pay the Manager Compensation, the Company must first receive a cash distribution from OpCo, and any such cash distribution necessitates a concurrent pro rata cash distribution to the holders of redeemable noncontrolling interests. This cash distribution to the holders of redeemable noncontrolling interests does not represent additional Manager Compensation; rather, it represents an ordinary cash distribution to the holders of redeemable noncontrolling interests. In certain instances in our financial statements and other disclosures, we clarify the underlying event that requires us to make such distributions, not because the distributions to the holders of redeemable noncontrolling interests are made for such purpose (e.g. Cash distributions to redeemable noncontrolling interests initiated by Class A common stock dividend, Cash distributions to redeemable noncontrolling interests initiated by Manager Compensation and Cash contributions from (cash distributions to) redeemable noncontrolling interests initiated by income taxes).
During the years ended December 31, 2024, 2023 and 2022, we recorded general and administrative expense of $41.3 million, $23.8 million and $14.3 million, respectively, related to the Manager Compensation and concurrently made cash distributions of $22.2 million, $33.2 million and $32.3 million in 2024, 2023 and 2022 to our redeemable noncontrolling interests. At December 31, 2024, we reduced redeemable noncontrolling interests by $4.5 million for the OpCo distribution declaration to redeemable noncontrolling interests that will be paid during the first quarter of 2025. At December 31, 2024, we had $17.4 million and $13.9 million, included within Accounts payable - affiliates on the consolidated balance sheets for Crescent Energy Company's fee associated with the Manager Compensation and cash distributions to be paid to our redeemable noncontrolling interests in the first quarter of 2025.
Additionally, the Manager is entitled to receive incentive compensation ("Incentive Compensation") under which the Manager is targeted to receive 10% of our outstanding Class A Common Stock based on the achievement of certain performance-based measures. The Incentive Compensation consists of five tranches that settle over a five-year period beginning in 2024, and each
tranche relates to a target number of shares of Class A common stock equal to 2% of the outstanding Class A common stock as of the time such tranche is settled. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A common stock ranging from 0% to 4.8% of the outstanding Class A Common Stock at the time each tranche is settled. During the years ended December 31, 2024, 2023 and 2022, we recorded general and administrative expense of $188.1 million, $68.0 million and $24.3 million, respectively, related to the Incentive Compensation. See NOTE 13 - Equity-Based Compensation Awards for more information.
KKR Funds
From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds ("KKR Funds") pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a quarterly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of December 31, 2024 and 2023, we had a related party receivable of $4.3 million and $0.1 million, respectively, included within Accounts receivable - affiliates and a related party payable of $1.2 million and $27.9 million, respectively, included within Accounts payable - affiliates on our consolidated balance sheets associated with KKR Funds transactions.
KKR Capital Markets LLC ("KCM")
We engage KCM, an affiliate of KKR Group, for capital market transactions including notes offerings, credit facility structuring and equity offerings. The following table summarizes fees, discounts and commissions paid to KCM by Crescent in connection with our debt and equity transactions:
Year Ended December 31,
2024 2023 2022
(in millions)
Amounts paid to KCM $ 8.7 $ 5.2 $ 3.5
We recorded these fees to debt issuance costs within Long-term debt (note offerings) and Other assets (credit facility structuring) or APIC (equity offerings). At December 31, 2023 we had a related party payable of $0.3 million, included within Accounts payable - affiliates on our consolidated balance sheet associated with KCM transactions.
Other Transactions
In March 2024, OpCo repurchased 2.3 million OpCo Units from Independence Energy Aggregator L.P., the entity through which certain private investors in affiliated KKR entities held their interests in us, for $22.7 million. See NOTE 10 - Equity and Redeemable Noncontrolling Interests for more information. During the years ended December 31, 2024, 2023 and 2022, we made cash distributions of $32.5 million, $57.1 million and $97.0 million to our redeemable noncontrolling interests related to their pro rata share of cash distributions made to Crescent Energy Company to pay dividends and income taxes. In addition, during the years ended December 31, 2024, 2023 and 2022, we reimbursed KKR $2.4 million, $1.5 million and $1.8 million for costs incurred on our behalf. At December 31, 2024 we had $0.7 million accrued within Accounts payable - affiliates for reimbursable costs and distributions to our redeemable noncontrolling interests for their pro rata share of taxes which will be paid during the first quarter of 2025.
During the year ended December 31, 2023, we signed a ten-year office sublease agreement with KKR. The terms of the lease provide for an annual base rent of approximately $0.7 million. Upon lease commencement in December 2023, we recorded a $5.3 million right-of-use asset in Other assets, an operating lease liability of $0.4 million in Other current liabilities and $4.9 million in Other liabilities on the consolidated balance sheets. At December 2023 we also recorded our allocated share of leasehold improvement cost from KKR of $6.6 million to Accounts payable - affiliates and Field and other property and equipment, at cost on the consolidated balance sheets that was subsequently paid during 2024.
Board of Directors
During the year ended December 31, 2023, we signed a ten-year office lease with an affiliate of Crescent Real Estate LLC. John C. Goff, the Chairman of our Board of Directors, is affiliated with Crescent Real Estate LLC. The terms of the lease provide for annual base rent of approximately $0.3 million, increasing over the term of the lease, and the payment by one of our subsidiaries of certain other customary expenses. In addition, the lease provides for reimbursement of our costs up to $1.1 million for tenant improvements, which we were reimbursed the full amount during the year ended December 31, 2024. In addition, during the year ended December 31, 2024 we entered into an amendment to the original lease agreement for additional office space. Under the amended agreement our annual base rent is $0.4 million increasing to $0.5 million over the life of the agreement. Upon lease commencement in April 2023, we recorded a $2.4 million right-of-use asset in Other assets, an operating lease liability of $0.1 million in Other current liabilities and $2.3 million in Other liabilities on the consolidated balance sheets.
We may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to producing assets held by Chama, an Investment in equity affiliates on our consolidated balance sheets. During the year ended December 31, 2024, we funded $4.7 million to Chama associated with the plugging and abandonment costs.
NOTE 15 - Earnings Per Share
We have two classes of common stock in the form of Class A Common Stock and Class B Common Stock. Our shares of Class A Common Stock are entitled to dividends, and shares of Class B Common Stock do not have rights to participate in dividends or undistributed earnings. However, shareholders of Class B Common Stock receive pro rata distributions from OpCo through their ownership of OpCo Units. We apply the two-class method for purposes of calculating earnings per share (“EPS”). The two-class method determines earnings per share of common stock and participating securities according to dividends or dividend equivalents declared during the period and each security's respective participation rights in undistributed earnings and losses. Net income (loss) per share - diluted excludes the effect of 3.3 million PSUs and 0.2 million of RSUs for the year ended December 31, 2024 that were not included in the computation of earnings per share because to do so would have been antidilutive to our net loss.
Net income (loss) attributable to Crescent Energy is allocated to Class A Common Stock and Class B Common Stock based on the participation rights of each class to share in undistributed earnings and losses after giving effect to dividends declared during the period, if any.
The following table sets forth the computation of basic and diluted net income (loss) per share:
Year Ended December 31,
2024 2023 2022
(in thousands, except share and per share amounts)
Numerator:
Net income (loss) $ (137,683) $ 321,991 $ 480,600
Less: net (income) loss attributable to noncontrolling interests
1,215 (472) (2,669)
Less: net (income) loss attributable to redeemable noncontrolling interests
21,863 (253,909) (381,257)
Net income (loss) attributable to Crescent Energy - basic $ (114,605) $ 67,610 $ 96,674
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of RSUs - 46 25
Add: Reallocation of net income attributable to redeemable noncontrolling interest for the dilutive effect of PSUs - 869 490
Net income (loss) attributable to Crescent Energy - diluted $ (114,605) $ 68,525 $ 97,189
Denominator:
Weighted-average Class A Common Stock outstanding - basic 130,715,482 66,597,580 43,865,176
Add: dilutive effect of RSUs - 39,999 11,867
Add: dilutive effect of PSUs - 764,643 234,780
Weighted-average Class A common stock outstanding - diluted 130,715,482 67,402,222 44,111,823
Weighted-average Class B Stock outstanding - basic and diluted 70,519,162 104,271,400 124,856,941
Net income (loss) per share:
Class A Common Stock - basic
$ (0.88) $ 1.02 $ 2.20
Class A Common Stock - diluted
$ (0.88) $ 1.02 $ 2.20
Class B Common Stock - basic and diluted $ - $ - $ -
NOTE 16 - Segment Information
We have evaluated how we are organized and managed and have identified one reportable segment, which is the exploration and production of crude oil, natural gas and NGLs. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. Substantially all of our operations and assets are located onshore in the United States, and substantially all of our revenues are attributable to United States customers.
The Company’s Chief Operating Decision Maker ("CODM") is the Chief Executive Officer. The CODM uses measures of profitability including Net income (loss) on the Consolidated statement of operations to assess performance and determine resource allocation. The CODM uses these metrics to make key operating decisions, including the determination of allocation of capital between development of existing oil and gas properties and the acquisition of additional oil and gas properties, and the identification and divestiture of non-core assets. The measure of segment assets is reported on the Consolidated balance sheets as Total assets. We do not have intra-entity sales or transfers.
The table below provides information about the Company’s single reportable segment:
Year Ended December 31,
2024 2023 2022
(in thousands)
Total revenues $ 2,930,919 $ 2,382,602 $ 3,057,065
Less:
Lease operating expense 528,822 495,380 438,753
Workover expense 60,312 58,441 66,864
Asset operating expense 103,220 86,593 78,709
Gathering, transportation and marketing 312,931 235,153 177,078
Production and other taxes 162,634 162,963 238,381
Depreciation, depletion and amortization 949,480 675,782 532,926
Impairment of oil and natural gas properties 161,542 153,495 142,902
Midstream and other operating expense 110,136 39,809 13,513
General and administrative expense excluding equity-based compensation 142,738 57,982 46,927
Equity-based compensation expense 193,481 82,936 38,063
Interest expense 216,263 145,807 95,937
Other segment items
127,043 (133,730) 706,412
Net income (loss) $ (137,683) $ 321,991 $ 480,600
Total development of oil and natural gas properties 745,198 578,316 624,880
Other segment items include Exploration expense, Gain (loss) on derivatives, (Gain) loss on sale of assets and Loss from extinguishment of debt from our consolidated statements of operations.
NOTE 17 - Subsequent Events
Subsequent events have been evaluated through the date of issuance of these financial statements, and there have been no events subsequent to December 31, 2024, other than those items disclosed below, that would require additional adjustments to our disclosure in our financial statements.
Dividend
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 our 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. Management and the Board of Directors will evaluate any future changes in cash dividends on a quarterly basis.
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”). We are currently evaluating the Ridgemar Acquisition and have not completed the purchase accounting.
Webb Gas Acquisition
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.
NOTE 18 - Supplemental Oil and Natural Gas Disclosures (Unaudited)
Geographic Area of Operation
All of the oil and natural gas properties in which we have working interests and mineral and royalty interests are located within the continental U.S., with the majority concentrated in Texas and the Rockies. Therefore, the following disclosures about our costs incurred and proved reserves are presented on a consolidated basis. In addition, at December 31, 2021, we had a 37% ownership in our equity method investment, Exaro, that operates in the Jonah Field in Wyoming. During the year ended December 31, 2022, our equity method investment, Exaro, sold its operations, see NOTE 3 - Acquisitions and Divestitures for additional information.
Oil and Natural Gas Reserve Information
The following table presents our net proved reserves for the years ended December 31, 2024, 2023 and 2022 and the changes in net proved oil, natural gas and NGL reserves during such years. The net proved reserves for our equity method investment, Exaro, are presented based on our 37% ownership percentage. Exaro was acquired in 2021 and subsequently sold in 2022, thus no values are presented for 2024, 2023 and 2022.
Developed and Undeveloped Oil
(MBbls) Natural Gas
(MMcf) Natural Gas Liquids
(MBbls) Total
(MBoe)
Consolidated operations
Net proved reserves at December 31, 2021 210,160 1,469,953 76,493 531,645
Revisions of previous estimates (1)
(18,859) (14,815) 4,167 (17,158)
Extensions, discoveries, and other additions (2)
37,208 60,312 7,751 55,011
Sales of reserves in place (6,006) (19,365) (2,680) (11,915)
Purchases of reserves in place (3)
42,444 138,920 - 65,597
Production (21,865) (128,470) (7,110) (50,387)
Net proved reserves at December 31, 2022 243,082 1,506,535 78,621 572,793
Revisions of previous estimates (4)
(15,501) (472,337) (11,676) (105,901)
Extensions, discoveries, and other additions (5)
2,808 16,240 1,635 7,150
Sales of reserves in place (1,655) (15,075) (1,774) (5,942)
Purchases of reserves in place (6)
46,018 271,682 43,301 134,599
Production (24,287) (130,629) (8,475) (54,533)
Net proved reserves at December 31, 2023
250,465 1,176,416 101,632 548,166
Revisions of previous estimates (7)
(17,316) (210,432) (11,263) (63,648)
Extensions, discoveries, and other additions (8)
16,626 70,632 10,604 39,002
Sales of reserves in place (3,344) (5,318) (767) (4,998)
Purchases of reserves in place (9)
81,204 746,988 58,664 264,366
Production (29,945) (183,227) (13,154) (73,637)
Net proved reserves at December 31, 2024 297,690 1,595,059 145,716 709,251
Equity affiliate
Net proved reserves at December 31, 2021 204 20,765 - 3,665
Sales of reserves in place (200) (20,357) - (3,593)
Production (4) (408) - (72)
Net proved reserves at December 31, 2022 - - - -
Net proved reserves at December 31, 2023
- - - -
Developed and Undeveloped Oil
(MBbls) Natural Gas
(MMcf) Natural Gas Liquids
(MBbls) Total
(MBoe)
Net proved reserves at December 31, 2024 - - - -
Total company
Net proved reserves at December 31, 2022 243,082 1,506,535 78,621 572,793
Net proved reserves at December 31, 2023 250,465 1,176,416 101,632 548,166
Net proved reserves at December 31, 2024 297,690 1,595,059 145,716 709,251
(1)Revisions of previous estimates primarily relate to increased expected future costs driven by inflation and a higher commodity price environment.
(2)Extensions, discoveries and other additions of 55.0 MMBoe primarily relate to PUD extensions most of which related to our Eagle Ford asset.
(3)Purchases of reserves in place of 65.6 MMBoe primarily related to our Uinta Acquisition.
(4)Revisions of previous estimates primarily relate to a 133 MMBoe downward revision from lower oil and natural gas prices, partially offset by 27 MMBoe in upward revisions from a variety of factors primarily driven by new contracts, operating expense revisions and upward forecast revisions in certain basins.
(5)Extensions, discoveries and other additions of 7.2 MMBoe primarily relate to PUD extensions all of which related to our Eagle Ford and Uinta assets.
(6)Purchases of reserves in place of 134.6 MMBoe primarily related to our Western Eagle Ford Acquisitions.
(7)Revisions of previous estimates relate to 79.6 MMBoe downward revisions, driven primarily by a 44.0 MMBoe downward revision from lower oil and natural gas prices, partially offset by 16.0 MMBoe in upward revisions from a variety of factors primarily driven by new contracts and operating expense revisions in certain basins.
(8)Extensions, discoveries and other additions of 39.0 MMBoe primarily relate to PUD extensions all of which related to our Eagle Ford and Uinta assets.
(9)Purchases of reserves in place of 264.4 MMBoe primarily related to our the SilverBow Merger and Central Eagle Ford Acquisition.
The following table sets forth our net proved oil, natural gas and NGL reserves for both our consolidated operations and our investment in Exaro as of the years ended December 31, 2024, 2023 and 2022:
Proved Developed Reserves
Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 2024 193,611 1,342,718 109,223 526,622
December 31, 2023 176,546 1,032,578 87,316 435,958
December 31, 2022 160,113 1,398,770 66,803 460,046
Equity affiliate
December 31, 2024 - - - -
December 31, 2023 - - - -
December 31, 2022 - - - -
Proved Undeveloped Reserves
Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas Liquids
(MBbls)
Total
(MBoe)
Consolidated operations
December 31, 2024 104,079 252,341 36,493 182,629
December 31, 2023 73,919 143,838 14,316 112,208
December 31, 2022 82,969 107,765 11,818 112,747
Equity affiliate
December 31, 2024 - - - -
December 31, 2023 - - - -
December 31, 2022 - - - -
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table summarizes the capitalized costs relating to our oil and natural gas producing activities for our consolidated operations as of December 31, 2024 and 2023:
As of December 31,
2024 2023
(in thousands)
Consolidated operations
Proved oil and natural gas properties (successful efforts method) $ 11,471,299 $ 8,574,478
Unproved oil and natural gas properties 374,306 283,324
Oil and natural gas properties, at cost 11,845,605 8,857,802
Less: accumulated depreciation, depletion, amortization and impairment (3,840,344) (2,865,095)
Net capitalized costs $ 8,005,261 $ 5,992,707
Equity affiliate
Net capitalized costs $ - $ -
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. For a description and allocation of costs incurred for our significant acquisitions included in the table below, see NOTE 3 - Acquisitions and Divestitures. Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.
The following table summarizes costs incurred related to our oil and natural gas activities for both our consolidated operations and our investment in Exaro for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31,
2024 2023 2022
(in thousands)
Consolidated operations
Acquisition costs:
Proved $ 2,163,000 $ 836,159 $ 793,081
Unproved 219,326 35,474 71,387
Field and other property and equipment 25,734 - 8,200
Exploration costs 16,591 9,328 3,425
Development 745,198 578,316 624,880
Total costs incurred $ 3,169,849 $ 1,459,277 $ 1,500,973
Equity affiliate
Total costs incurred $ - $ - $ -
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing procedures prescribed by ASC Topic 932, Extractive Industries - Oil and Gas, and based on crude oil, NGL and natural gas reserves and production volumes estimated by our engineering staff. The estimates were based on a 12-month average for first-day-of-the month commodity prices. The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating our performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of our current value.
The future cash flows presented below are based on sales prices and cost rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future,
development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
Future net cash flows were calculated at December 31, 2024, 2023 and 2022 by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, with consideration of known contractual price changes. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category:
Year Ended December 31,
2024 2023 2022
Average benchmark price per unit:
Crude oil (Bbl) $ 75.48 $ 78.22 $ 93.67
Natural gas (MMBtu) $ 2.13 $ 2.64 $ 6.36
The following table sets forth the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro from projected production of oil and natural gas reserves and excludes the midstream revenue impact on a portion of our operations that could reduce future production costs, for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31,
2024 2023 2022
(in thousands)
Consolidated operations
Future cash inflows $ 27,890,094 $ 24,267,134 $ 33,628,495
Future production costs (12,981,064) (11,897,791) (14,077,136)
Future development costs (1)
(3,801,466) (2,713,247) (2,380,931)
Future income taxes (2)
(1,055,147) (410,721) (773,479)
Future net cash flows 10,052,417 9,245,375 16,396,949
Annual discount of 10% for estimated timing
(4,348,722) (3,956,193) (7,262,283)
Standardized measure of discounted future net cash flows $ 5,703,695 $ 5,289,182 $ 9,134,666
Equity affiliate
Future cash inflows $ - $ - $ -
Future production costs - - -
Future development costs - - -
Future income taxes - - -
Future net cash flows - - -
Annual discount of 10% for estimated timing
- - -
Standardized measure of discounted future net cash flows $ - $ - $ -
(1) Future development costs include future abandonment and salvage costs.
(2) Our future income taxes are based upon on our allocable share of any taxable income of OpCo. Estimated future taxable income or loss generated by OpCo is generally allocated and passed through to Crescent at our proportionate share of OpCo unit ownership which at December 31, 2024, 2023 and 2022 was 74%, 51% and 29%, respectively.
Changes in standardized measure of discounted future net cash flows
The following table sets forth the changes in the standardized measure of discounted future net cash flows for both our consolidated operations and our investment in Exaro for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31,
2024 2023 2022
(in thousands)
Consolidated operations
Balance at beginning of period $ 5,289,182 $ 9,134,666 $ 4,958,300
Net change in prices and production costs (47,265) (2,859,297) 4,156,736
Net change in future development costs (92,580) (141,382) (132,213)
Sales and transfers of oil and natural gas produced, net of production expenses
(1,715,764) (1,354,856) (2,083,147)
Extensions, discoveries, additions and improved recovery, net of related costs 318,421 119,025 1,105,549
Purchases of reserves in place 2,493,077 1,338,224 1,333,452
Sales of reserves in place (70,549) (90,157) (118,253)
Revisions of previous quantity estimates (817,132) (2,244,012) (952,958)
Previously estimated development costs incurred 369,595 301,839 488,934
Net change in taxes (478,046) 190,444 (251,714)
Accretion of discount 556,612 960,208 575,440
Changes in timing and other (101,856) (65,520) 54,540
Balance at end of period $ 5,703,695 $ 5,289,182 $ 9,134,666
Equity affiliate
Balance at beginning of period $ - $ - $ 23,178
Net change in prices and production costs - - -
Net change in future development costs - - -
Sales and transfers of oil and natural gas produced, net of production expenses - - (2,063)
Extensions, discoveries, additions and improved recovery, net of related costs - - -
Purchases of reserves in place - - -
Sales of reserves in place - - (22,845)
Revisions of previous quantity estimates - - -
Previously estimated development costs incurred - - -
Net change in taxes - - 1,730
Accretion of discount - - -
Changes in timing and other - - -
Balance at end of period $ - $ - $ -
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CRESCENT ENERGY COMPANY
PARENT COMPANY BALANCE SHEETS
December 31, 2024 December 31, 2023
(in thousands, except share and unit data)
ASSETS
Current assets:
Cash and cash equivalents
$ 3,001 $ 2,305
Income tax receivable 523 1,938
Accounts receivable - affiliates 12,872 7,558
Total current assets 16,396 11,801
Investment in subsidiary 4,722,280 3,889,449
TOTAL ASSETS $ 4,738,676 $ 3,901,250
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY
Current liabilities:
Accounts payable - affiliates $ 12,947 $ 7,183
Income tax payable
1,272 -
Total current liabilities 14,219 7,183
Deferred tax liability 356,497 258,349
Total liabilities 370,716 265,532
Contingencies (Note 3)
Redeemable noncontrolling interests 1,228,329 1,901,208
Equity:
Class A common stock, $0.0001 par value; 1,000,000,000 shares authorized and 189,505,209 and 92,680,353 shares issued and 187,070,725 and 91,608,800 shares outstanding as of December 31, 2024 and 2023, respectively
19 9
Class B common stock, $0.0001 par value; 500,000,000 shares authorized and 65,948,124 and 88,048,124 shares issued and outstanding as of December 31, 2024 and 2023, respectively
7 9
Preferred stock, $0.0001 par value; 500,000,000 shares authorized and 1,000 Series I preferred shares issued and outstanding as of December 31, 2024 and 2023
- -
Treasury stock, at cost; 2,434,484 and 1,071,553 shares of Class A common stock as of December 31, 2024 and 2023, respectively
(32,430) (17,143)
Additional paid-in capital 3,227,450 1,626,501
Retained earnings (accumulated deficit)
(64,751) 95,447
Noncontrolling interests 9,336 29,687
Total equity 3,139,631 1,734,510
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS AND EQUITY $ 4,738,676 $ 3,901,250
The accompanying notes to financial statements are an integral part of these condensed financial statements.
SCHEDULE I - CONTINUED
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CRESCENT ENERGY COMPANY
PARENT COMPANY STATEMENTS OF OPERATIONS
Year Ended December 31,
2024 2023 2022
(in thousands, except per share amounts)
Revenues $ - $ - $ -
Expenses:
General and administrative expense 41,262 23,829 14,313
Total expenses 41,262 23,829 14,313
Income (loss) before taxes and equity in income (losses) of subsidiary (41,262) (23,829) (14,313)
Income tax benefit (expense) 39,166 (21,553) (31,979)
Income (loss) before equity in income (losses) of subsidiary (2,096) (45,382) (46,292)
Equity in income (losses) of subsidiary, net of tax (135,587) 367,373 526,892
Net income (loss) (137,683) 321,991 480,600
Less: net (income) loss attributable to noncontrolling interests 1,215 (472) (2,669)
Less: net (income) loss attributable to redeemable noncontrolling interests
21,863 (253,909) (381,257)
Net income (loss) attributable to Crescent Energy $ (114,605) $ 67,610 $ 96,674
Net income (loss) per share:
Class A common stock - basic $ (0.88) $ 1.02 $ 2.20
Class A common stock - diluted $ (0.88) $ 1.02 $ 2.20
Class B common stock - basic and diluted $ - $ - $ -
Weighted average shares outstanding:
Class A common stock - basic 130,715 66,598 43,865
Class A common stock - diluted 130,715 67,402 44,112
Class B common stock - basic and diluted 70,519 104,271 124,857
The accompanying notes to financial statements are an integral part of these condensed financial statements.
SCHEDULE I - CONTINUED
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CRESCENT ENERGY COMPANY
PARENT COMPANY STATEMENTS OF CASH FLOWS
Year Ended December 31,
2024 2023 2022
(in thousands)
Cash flows from operating activities:
Net income (loss)
$ (137,683) $ 321,991 $ 480,600
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Equity in (income) losses of subsidiary 135,587 (367,373) (526,892)
Deferred income taxes (benefit) (42,549) 21,068 30,611
Changes in operating assets and liabilities:
Income tax receivable 1,415 3,366 (5,304)
Accounts receivable - affiliates 449 (487) -
Accounts payable - affiliates 5,763 3,329 2,940
Income tax payable
1,272 (1,051) 983
Net cash used in operating activities (35,746) (19,157) (17,062)
Cash flows from investing activities:
Acquisition of oil and gas properties, net of cash acquired (376,950) - -
Net cash provided by investing activities (376,950) - -
Cash flows from financing activities:
Distributions from OpCo 101,517 59,582 44,571
Cash received from sale of OpCo Units
392,236 - -
Dividend to Class A common stock
(65,075) (34,120) (27,509)
Proceeds from Equity Issuance after underwriting fees
330,573 145,665 -
Cash contribution to OpCo
(330,573) (149,665) -
Cash paid for treasury stock acquired for equity-based compensation tax withholding (7,441) - -
Repurchases of Class A common stock (7,845) - -
Other
- - -
Net cash provided by financing activities 413,392 21,462 17,062
Net change in cash, cash equivalents and restricted cash 696 2,305 -
Cash, cash equivalents and restricted cash, beginning of period 2,305 - -
Cash, cash equivalents, and restricted cash, end of period $ 3,001 $ 2,305 $ -
The accompanying notes to financial statements are an integral part of these condensed financial statements.
SCHEDULE I - CONTINUED
CRESCENT ENERGY COMPANY
NOTES TO PARENT COMPANY FINANCIAL STATEMENTS
NOTE 1 - Corporate Structure and Basis of Presentation
Corporate Structure
Our Class A Common Stock is listed on The New York Stock Exchange under the symbol “CRGY.” We are structured as an “Up-C,” with substantially all of our assets and operations held by Crescent Energy OpCo LLC ("OpCo"). Crescent is a holding company, the sole material assets of which are units of OpCo ("OpCo Units"). The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities with the exception of certain current and deferred taxes and certain liabilities under the Management Agreement, as defined within “Notes to Consolidated Financial Statements-NOTE 14 - Related Party Transactions" included elsewhere in of this Annual Report. Certain restrictions and covenants related to the transfer of assets from OpCo are discussed further in "Notes to Consolidated Financial Statements-NOTE 8 - Debt" included elsewhere in this Annual Report. Shares of Crescent Class A common stock, par value $0.0001 per share ("Class A Common Stock") have both voting and economic rights with respect to Crescent. Holders of Crescent Class B common stock, par value $0.0001 per share ("Class B Common Stock"), which shares of Class B Common Stock have voting (but no economic) rights with respect to Crescent, hold a corresponding amount of economic, non-voting OpCo Units. 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 (“OpCo LLC Agreement”). Additionally, an affiliate of the KKR Group (as defined in -Basis of Presentation) is the sole holder of Crescent's non-economic Series I preferred stock, $0.0001 par value per share, which entitles the holder thereof to appoint the Board of Directors of Crescent and to certain other approval rights.
Basis of Presentation
As the sole managing member of OpCo, we are responsible for all operational, management and administrative decisions related to OpCo’s business. Because the unit holders of OpCo lack the characteristics of a controlling financial interest, OpCo was determined to be a variable interest entity. Crescent is considered the primary beneficiary of OpCo as it has both the power to direct OpCo and the right to receive benefits from OpCo. As a result, we consolidate the financial results of OpCo and its subsidiaries, including Crescent Energy Finance LLC. During the year ended December 31, 2024 and 2023, our ownership of OpCo increased due to the 2022 Equity Transactions as described in "Notes to Consolidated Financial Statements-NOTE 1 - Organization and Basis of Presentation" included elsewhere in this Annual Report. At December 31, 2024 and 2023, our ownership of OpCo was 74% and 51%, respectively, and 26% and 49%, respectively, of OpCo was owned by holders of our redeemable noncontrolling interests.
These condensed parent company financial statements reflect the activity of Crescent as the parent company to OpCo and have been prepared in accordance with Rules 5-04 and 12-04 of Regulation S-X, as the restricted net assets of OpCo and its consolidated subsidiaries exceed 25% of the consolidated net assets of Crescent. This information should be read in conjunction with the consolidated financial statements of Crescent included elsewhere in this Annual Report.
NOTE 2 - Acquisitions
For details regarding acquisitions, see "Notes to Consolidated Financial Statements-NOTE 3 - Acquisitions and Divestitures" included elsewhere in this Annual Report.
NOTE 3 - Income Taxes
For details regarding income taxes, see "Notes to Consolidated Financial Statements-NOTE 11 - Income Taxes" included elsewhere in this Annual Report.
NOTE 4 - Contingencies
For details regarding contingencies related to litigation, see "Notes to Consolidated Financial Statements-NOTE 12 - Commitments and Contingencies" included elsewhere in this Annual Report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Limitations on Effectiveness of Controls and Procedures
We maintain disclosure controls and procedures ("Disclosure Controls") within the meaning of Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Our Disclosure Controls are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Our Disclosure Controls are also designed to ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our Disclosure Controls, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives.
Evaluation of Disclosure Controls and Procedures
The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company's Disclosure Controls, as of December 31, 2024. Based on such evaluation, such officers have concluded that, as of December 31, 2024, the Company's disclosure controls and procedures are designed and effective to ensure that information required to be included in the Company's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information required to be disclosed in the Company's reports filed or submitted under the Exchange Act is accumulated and communicated to the Company's management including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating the Company's disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company's controls will succeed in achieving their goals under all potential future conditions.
Changes in Internal Control over Financial Reporting
There were no changes in the Company's internal control over financial reporting (as defined by Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2024, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Management's Assessment of Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. As of December 31, 2024, management assessed the effectiveness of our internal control over financial reporting. In making this assessment, management, including our Chief Executive Officer and Chief Financial Officer, used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on this assessment, our Chief Executive Officer and Chief Financial Officer have concluded that our internal control over financial reporting was effective as of December 31, 2024.
Deloitte & Touche LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2024 and has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2024. Please see their "Report of Independent Registered Public Accounting Firm" included below.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Crescent Energy Company
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Crescent Energy Company and subsidiaries (the “Company”) as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024 of the Company and our report dated February 26, 2025 expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment on Internal Control over Financial Reporting, appearing under Part II, Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Houston, Texas
February 26, 2025

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
Trading Arrangements
During the three months ended December 31, 2024, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, terminated or modified a “Rule 10b5-1 trading arrangement” or non-Rule 10b5-1 trading arrangement (as each term is defined in Item 408 of Regulation S-K).

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
Board of Directors and Executive Officers
The following table sets forth information regarding the members (each, a “Director”) of our Board of Directors and officers (each, an “Executive Officer”).
Name Age Position
David C. Rockecharlie 52 Chief Executive Officer and Director
Brandi Kendall 40 Chief Financial Officer and Director
Todd N. Falk 44 Chief Accounting Officer
John Clayton “Clay” Rynd 35 Executive Vice President
Bo Shi 36 General Counsel and Corporate Secretary
John C. Goff 69 Chairman and Director
Claire S. Farley 66 Director
Robert G. Gwin 61 Director
Ellis L. “Lon” McCain 77 Director
Karen J. Simon 65 Director
Erich Bobinsky 36 Director
Bevin Brown 48 Director
Marcus C. Rowland
72 Director
Michael Duginski
58 Director
The following are biographical summaries of the business experience of each Director and Executive Officer.
David C. Rockecharlie has served as Crescent Energy Company’s Chief Executive Officer and a director on our Board since December 2021. Mr. Rockecharlie previously served as the Chief Executive Officer of Independence's managing member since March 2021, prior to which he served as Manager and President of Independence's managing member beginning in June 2020. Mr. Rockecharlie also served on Independence's Board since June 2020. Mr. Rockecharlie joined KKR in 2011 and is currently a Partner and Head of KKR’s Energy Real Assets business and Chairman of KKR’s Energy Investment Committee. Prior to joining KKR, Mr. Rockecharlie was co-founder and co-CEO of RPM Energy, LLC, a privately-owned oil and gas company. Previously, Mr. Rockecharlie served as co-head of Jefferies & Company’s Energy Investment Banking Group and before that was an executive with El Paso Corp., where he led a variety of corporate activities. Mr. Rockecharlie began his career as an energy investment banker with S.G. Warburg and Donaldson, Lufkin & Jenrette. Mr. Rockecharlie received an A.B., magna cum laude, from Princeton University. We believe Mr. Rockecharlie’s extensive industry experience and longstanding relationship with KKR make him well-suited to serve as a Director.
Brandi Kendall has served as Crescent Energy Company’s Chief Financial Officer and a director since December 2021. Ms. Kendall previously served as Chief Financial Officer of Independence's managing member since March 2021, prior to which she served as Vice President of Independence's managing member beginning in June 2020. Ms. Kendall has also served as a director on Independence's Board since August 2020. Ms. Kendall joined KKR in 2013 and is responsible for a broad range of portfolio management activities for its Energy Real Assets team, including finance, planning, risk management and corporate development. Prior to joining KKR, Ms. Kendall served as director, finance and planning at Marlin Midstream and finance associate at NFR Energy. Ms. Kendall began her career in the energy investment banking industry, having held positions at JP Morgan and Tudor, Pickering, Holt & Co. Ms. Kendall earned a B.A. in Economics, Managerial Studies and Kinesiology from Rice University. We believe Ms. Kendall’s financial expertise and energy industry experience make her well-suited to serve as a Director.
Todd N. Falk has served as Crescent Energy Company’s Chief Accounting Officer since December 2021. Mr. Falk previously served as Chief Accounting Officer of Independence's managing member since March 2021, prior to which he served as Vice President, Finance of Independence's managing member beginning in June 2020. Mr. Falk joined KKR in 2018 and is currently a Managing Director and member of KKR’s Energy Real Assets business. Prior to joining KKR, Mr. Falk served as Director of
Finance and Controller of Vitruvian Exploration from October 2013 to September 2018. Mr. Falk began his career at Deloitte, where as a senior manager he assisted clients with complex financial reporting issues, specializing in initial public offerings and other interactions with the SEC. Mr. Falk has over 20 years of finance and accounting experience in the energy industry, is a Certified Public Accountant and holds a B.S., magna cum laude, in Accounting and an M.S. in Finance from Texas A&M University.
John Clayton “Clay” Rynd has served as Crescent Energy Company’s Executive Vice President since March 2021. Mr. Rynd joined KKR in 2015 and is a member of the Energy Real Assets team. He has been involved in numerous oil and gas investments across KKR’s Energy Real Assets strategy, including the creation of Crescent Energy. In addition, Mr. Rynd has been involved in KKR's investments in FlowStream Commodities and Resource Environmental Solutions. Prior to joining KKR, Mr. Rynd was with Tudor, Pickering, Holt & Co. in the investment banking division, where he focused primarily on strategic advisory and M&A transactions for companies across the energy sector. Prior to that, he worked within the equity research division at Tudor, Pickering, Holt & Co. Mr. Rynd holds a B.A. in both Economics and History from Texas A&M University.
Bo Shi has served as Crescent Energy Company’s General Counsel and Corporate Secretary since December 2021. Mr. Shi previously served as General Counsel for Independence since October 2021. Prior to joining Independence, Mr. Shi worked as a Senior Associate at Vinson & Elkins L.L.P from October 2014 to January 2018, and from December 2018 to October 2021. While at Vinson & Elkins L.L.P., his practice focused on capital markets transactions, corporate governance and mergers and acquisitions, primarily within the oil and gas industry. From January 2018 until December 2018, Mr. Shi served as Senior Counsel at IPSCO Tubulars Inc., a producer and supplier of oil country tubular goods. He received a J.D. from Harvard Law School and a B.A. in Political Science and Policy Studies from Rice University.
John C. Goff, a private investor based in Fort Worth, Texas, has served as Chairman of the Crescent Energy Company Board of Directors since December 2021. He was elected to the board of directors of Contango in August 2018 and as Non-Executive Chairman of the board in October 2019. Mr. Goff founded his family office, Goff Capital, in 2009. Goff Capital invests in a variety of public and private industries and is presently focused on investments in real estate, aerospace, oil & gas, entertainment, and wellness. Mr. Goff co-founded Crescent Real Estate with Richard Rainwater in the early 1990’s, designing the strategy and orchestrating the acquisitions leading to its initial public offering (NYSE) in May 1994. Under his leadership as CEO, Crescent Real Estate grew from approximately $500 million at its IPO to $6.5 billion upon its sale to Morgan Stanley in August 2007. Crescent Real Estate provided its shareholders with a 15.4 percent compounded annual return and more than $2.5 billion in cash dividends during its 13 years as a public company. In November 2009, Mr. Goff reacquired Crescent Real Estate in a partnership with Barclays Capital, and in December 2017 he purchased Barclays Capital’s interest to become the principal owner of Crescent Real Estate and its subsidiaries. Crescent Real Estate currently has assets under management, development and investment capacity of more than $10 billion. Mr. Goff graduated from The University of Texas at Austin and is a member of McCombs Business School Hall of Fame. He was named EY Entrepreneur of the Year for the Southwest Region in 2014 and more recently, was inducted to the North Texas Real Estate, the Dallas Business and the Fort Worth Business Halls of Fame. Mr. Goff brings investment and financial acumen, including expertise in analyzing opportunities, risks and strategy in investments in various industries, including energy investments, and providing guidance regarding corporate governance matters, which makes him well-suited to serve as a Director.
Claire S. Farley has served as a Director since December 2021 and previously served as a Director of Independence from August 2020 through December 2021. Ms. Farley served as a Senior Advisor to KKR’s Energy Real Assets team from 2011 through 2021, after having joined KKR in 2011 as a Partner. Prior to joining KKR, she was co-founder and co-CEO of RPM Energy LLC. Ms. Farley previously was an advisory director of Jefferies Randall & Dewey, also serving as co-president. She was CEO of Randall & Dewey before it combined with Jefferies & Company. Prior to that, she served in various roles at Texaco, Inc., including CEO of HydroTexaco, president of the North American production division and president of worldwide exploration and new ventures. She has also served as CEO of two start-up ventures: Intelligent Diagnostics Corporation, and Trade-Ranger Inc. Ms. Farley serves on the board of directors of Technip FMC and LyondellBasell Industries, N.V. Ms. Farley holds a B.S. from Emory University. We believe that Ms. Farley’s leadership, investing and energy experience make her well-suited to serve as a Director.
Robert G. Gwin has served as a Director since December 2021. Mr. Gwin was previously President of Anadarko Petroleum Corporation (“Anadarko”), one of the world’s largest independent oil and natural gas exploration and production companies, until August of 2019, when the company was purchased by Occidental Petroleum Corporation. He previously was Executive Vice President, Finance and Chief Financial Officer of Anadarko from 2009 to 2018. Mr. Gwin is also currently a director of TechnipFMC plc. He has previously served as a director of Pembina Pipeline Corporation, Enable Midstream Partners, LP, where he served as Chairman of its board of directors, and Western Gas Partners LP and its general partner Western Gas Equity Partners LP, where he served as Chairman of their boards of directors. He has served on numerous community and charitable
organization boards throughout his career, currently including the MD Anderson Cancer Center and Communities in Schools - Houston. He holds a Bachelor of Science degree from the University of Southern California and a Master of Business Administration degree from the Fuqua School of Business at Duke University, and is a Chartered Financial Analyst (CFA). We believe Mr. Gwin’s business and industry experience make him well-suited to serve as a Director.
Ellis L. “Lon” McCain has served as a Director since December 2021. Mr. McCain was previously a director of Contango from February 2006 through December 2021, at which time he was serving as Chairman of Contango’s Audit Committee. Mr. McCain also served as Contango’s Lead Director from the 2014 Annual Meeting through the 2016 Annual Meeting. Mr. McCain served as Executive Vice President and Chief Financial Officer of Ellora Energy, Inc. (“Ellora”) from July 2009 through August 2010, when Ellora was merged into a subsidiary of Exxon Mobil Corporation. Prior to Ellora, Mr. McCain was Vice President, Treasurer, and Chief Financial Officer of Westport Resources Corporation (“Westport”), a publicly traded exploration and production company, from 2001 until the sale of Westport to Kerr McGee Corporation and his retirement from Westport in 2004. From 1992 until joining Westport in 2001, Mr. McCain was Senior Vice President and Principal of Petrie Parkman & Co., an investment banking firm specializing in the oil and gas industry. From 1978 until joining Petrie Parkman & Co., Mr. McCain held senior financial management positions with Presidio Oil Company, Petro-Lewis Corporation, and Ceres Capital. He was an Adjunct Professor of Finance at the University of Denver from 1982 through 2005. In addition to the board of Crescent Energy Company, Mr. McCain currently serves on the board of Cheniere Energy Partners, GP, LLC, the general partner of Cheniere Energy Partners, L.P., a publicly traded partnership. Previously, he served on the board of Continental Resources, Inc. from 2006 to November 2022. Mr. McCain received a B.A. in business administration and an M.B.A. with a major in finance from the University of Denver. Mr. McCain brings extensive business, financial and management expertise to the Company from his background as Chief Financial Officer of Ellora and Westport and from his tenure as an investment banker specializing in the oil and gas industry. Mr. McCain also brings considerable experience from his position as a director with several other energy companies. We believe Mr. McCain’s extensive business, financial, management and director expertise qualify him to serve on our Board and as Chairman of our Audit Committee.
Karen J. Simon has served as a Director since December 2021. Ms. Simon was previously a director of Contango from April 2021 through December 2021. Ms. Simon previously served as Vice Chairman, Investment Banking, at JPMorgan before retiring in December 2019. Over her 36 year banking career, she held a number of leadership positions, including Global Co-Head of Financial Sponsor Coverage, providing M&A and capital raising investment banking services to private equity funds; Co-Head of EMEA Debt Capital Markets and Head of EMEA Oil & Gas coverage, both in London, and most recently she founded JPMorgan’s Director Advisory new client group focused on providing advice to public company Directors. Ms. Simon is currently a director of two European public companies; one of which she chairs, Energean plc in London (LON: ENOG) since March 2018 and Aker ASA in Oslo (OSL: AKER) since April 2013. At Energean, Ms. Simon is a member of Remuneration committee and Chairs the Nomination & Governance committee. Additionally, Ms. Simon has served as a Senior Advisor Consultant with Independence Point Advisors, the first female-owned investment bank based in the United States, since 2022. In 2024, she also joined the Executive Advisory Council of the Bush Institute. Ms. Simon received dual graduate business degrees in 1983: an M.B.A. from Southern Methodist University in Dallas and a Master of International Management from the American Graduate School of International Management (Thunderbird) in Arizona. Earlier, she graduated from the University of Colorado, earning a Bachelor of Arts cum laude in Economics. We believe Ms. Simon’s business and investment experience make her well-suited to serve as a Director.
Erich Bobinsky has served as a Director since December 2021. Mr. Bobinsky previously served as a director of Independence from August 2020 through December 2021. Mr. Bobinsky is a Director at Liberty Mutual Investments (“LMI”), a position he has held since April 2019. Mr. Bobinsky joined LMI in 2010. Mr. Bobinsky holds a B.S. in Corporate Finance and Accounting from Bentley University. Mr. Bobinsky also holds a Chartered Financial Analyst (CFA) designation and is a member of the Boston Security Analysts Society. We believe that Mr. Bobinsky’s investment experience and relationship with LMI make him well-suited to serve as a Director.
Bevin Brown has served as a Director since December 2021. Ms. Brown previously served as a director of Independence from August 2020 through December 2021. Ms. Brown is the Managing Director of Portfolio Strategy & Management for Global Partnerships and Innovation at LMI, a position she has held since February 2020, prior to which she served as a Director at LMI beginning in 2013. Prior to joining LMI, Ms. Brown was a Director at a private equity firm and a Manager at PwC. Ms. Brown holds a B.S. from Stonehill College. We believe that Ms. Brown’s investment experience and relationship with LMI make her well-suited to serve as a Director.
Marcus Rowland has served as a director on our Board since July 2024. Mr. Rowland is a seasoned oil and gas corporate executive, director and investment manager with more than 40 years of experience in all aspects of upstream and midstream business segments. Previously, Mr. Rowland has served as the Founder and Director of IOG Capital, an energy investment firm. Prior to this, Mr. Rowland held various roles at FTS International, including President and Chief Financial Officer and
Chief Executive Officer. Before that, he served as Executive Vice President and Chief Financial Officer of Chesapeake Energy when the company became publicly traded. Mr. Rowland also served as the Chief Operating Officer of Anglo-Suisse Capital Limited and owned his own operating company earlier in his career. Mr. Rowland has served as a director on the boards of a number of public and private companies. He was previously Chairman of the Board at SilverBow Resources from September 2016 to July 2024, Chairman of the Board at Chaparral Energy, Inc. from 2019 to 2020 and also served as a director at SAExploration Holdings from 2020 to 2022, Warrior Technologies Acquisition Company from 2021 to 2022, Key Energy Services from 2020 to 2022, MIND Technology from 2015 to 2022, Warren Resources from 2012 to 2014 and Chesapeake Midstream Partners from 2010 to 2011. Mr. Rowland holds a B.A. from Wichita State University. We believe that Mr. Rowland’s executive leadership experience and industry knowledge make him well-suited to serve as a director.
Michael Duginski has served as a director on our Board since July 2024. Mr. Duginski is an experienced public company executive and director with operational industry-related expertise. Since 2015, Mr. Duginski has served as the President and Chief Executive Officer of Sentinel Peak Resources. Prior to this, Mr. Duginski served in several roles at Berry Petroleum, including Chief Operating Officer and Executive Vice President when it sold to Linn Energy in 2013. He previously served in various roles at Texaco, including Production Manager, Director of New Business Development and Gas and Power Operations Manager. Mr. Duginski has served on the public board of SilverBow Resources from April 2016 to July 2024, Madagascar Oil Limited from April 2015 to April 2016 and several private boards. Mr. Duginski holds a B.S. from the University of Arizona and an MBA from California State University, Bakersfield. We believe that Mr. Duginski’s executive leadership experience and industry knowledge make him well-suited to serve as a director.
Composition of our Board of Directors
Members of our Board of Directors are designated by the Preferred Stockholder, and, as applicable, any successor thereto. Our current Board of Directors consists of eleven Directors. Mr. Goff as Chairman and eight other Directors were designated by the Preferred Stockholder, including Messrs. Rockecharlie, Bobinsky, McCain and Gwin and Msses. Kendall, Brown, Simon and Farley, subject to the Specified Rights Agreement and Voting Agreement, as described below.
On July 30, 2024 we consummated the SilverBow Merger as contemplated by the Merger Agreement. In connection with the closing of the SilverBow Merger, we increased the size of our Board of Directors to eleven members and appointed two additional directors designated by SilverBow.
The Board has determined that each of Mses. Brown, Farley and Simon and Messrs. Bobinsky, Duginski, Goff, Gwin, McCain and Rowland is “independent” under the relevant standards of the NYSE. Because the Preferred Stockholder is the sole owner of our Non-Economic Series I Preferred Stock and accordingly has the exclusive right to appoint our Board of Directors, we are a “controlled company” under the Sarbanes-Oxley Act and NYSE rules; therefore, our Compensation Committee and Nominating & Governance Committee are not required to consist entirely of independent directors. See Item 1A. Risk Factors-“Risks related to our governance structure-We are a “controlled company” within the meaning of NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements.”
For information regarding procedure by which a presiding director is selected for each executive session and the process by which any interested party may communicate with the non-management directors or independent directors as a group, please see the Company’s Corporate Governance Guidelines at www.crescentenergyco.com.
Specified Rights Agreement & Voting Agreement
The Specified Rights Agreement, dated as of June 7, 2021, by and among PT Independence and Independence Energy Aggregator GP LLC ("Aggregator GP"), a Delaware limited liability company (the “Specified Rights Agreement”) grants PT Independence the right to designate two Directors to our Board of Directors (one of whom must be an Independent Director), so long as Liberty Mutual Insurance Co. beneficially owns a number of shares of Common Stock equal to at least 33.33% of its initial ownership of shares of Class B Common Stock. For so long as PT Independence owns at least one share of Common Stock, PT Independence shall have the right to designate one Director to our Board of Directors. Presently, the PT Independence designees to our Board of Directors are Mr. Bobinsky and Ms. Brown.
Pursuant to the Voting Agreement, dated as of June 7, 2021, by and between John C. Goff, Independence and the other signatories thereto (the “Voting Agreement”), Mr. Goff was granted the right to be appointed to our Board of Directors. Mr. Goff may only be removed for cause by a majority vote of Independent Directors.
There are no arrangements or understandings between any Director and any other person pursuant to which the Director was selected as a Director, other than as described above, relating to the appointment of directors. Except as otherwise disclosed herein and other than Mr. Rockecharlie’s and Ms. Kendall’s indirect interest in the Management Agreement as employees of KKR, none of the directors is a participant in any related party transaction required to be reported pursuant to Item 404(a) of Regulation S-K.
Audit Committee
We have a separately-designated Audit Committee of the Board of Directors (the “Audit Committee”) in accordance with Section 3(a) (58)(A) of the Exchange Act. Our Audit Committee has three members: Messrs. McCain and Bobinsky and Ms. Simon. Mr. McCain currently serves as the chairperson of the Audit Committee. Our Board of Directors has determined that each of Messrs. McCain and Bobinsky and Ms. Simon constitute “Audit Committee Financial Experts” as defined in Section 11 of the Securities Act. Likewise, each of the members serving on our Audit Committee are “independent” under the relevant standards of the NYSE and the SEC.
Compensation Committee Interlocks and Insider Participation
The members of the Compensation Committee of the Board during the year ending December 31, 2024 were Mses. Brown, Farley and Kendall. Ms. Kendall was an officer of the Company during fiscal year 2024. None of the members who served on the Compensation Committee at any time during fiscal year 2024 had any relationship requiring disclosure in “Part III., Item 13. Certain Relationships and Related Transactions, and Director Independence,” except for Ms. Kendall’s indirect interest in the Management Agreement as an employee of KKR. See “Part III., Item 13. Certain Relationships and Related Transactions, and Director Independence-Registration Rights Agreement-Management Agreement.” No executive officer of the Company served as a member of the compensation committee of another entity that had an executive officer serving as a member of our Board of Directors or our Compensation Committee. No executive officer of the Company served as a member of the board of another entity that had an executive officer serving as a member of our Compensation Committee.
Code of Business Conduct and Ethics
Our Board of Directors has adopted a Code of Business Conduct and Ethics ("Code of Ethics") that applies to all of our directors, officers and employees, including our principal executive, principal financial and principal accounting officers, or persons performing similar functions. Our Code of Ethics is available free of charge on our website, www.crescentenergyco.com. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Ethics by posting such information at the website address location specified above within four business days following the date of the amendment or waiver.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
Compensation Discussion and Analysis
This Compensation Discussion and Analysis reviews the compensation policies and programs for individuals who were deemed our “named executive officers” or “NEOs,” as determined under applicable SEC rules.
The narrative discussion set forth in this Compensation Discussion and Analysis is intended to provide additional information related to the data presented in the compensation-related tables included throughout the “Executive Compensation” section of this Annual Report and largely describes the compensation program that was in place from January 1, 2024 to December 31, 2024.
Executive Summary
Named Executive Officers
The following individuals were deemed our named executive officers for the year ended December 31, 2024:
•David C. Rockecharlie, Chief Executive Officer and Director;
•Brandi Kendall, Chief Financial Officer and Director;
•Todd N. Falk, Chief Accounting Officer;
•John Clayton "Clay" Rynd, Executive Vice President; and
•Bo Shi, General Counsel and Corporate Secretary.
We have been externally managed by our Manager since December 2021 pursuant to the terms of the Management Agreement. During fiscal year 2024, all of our executive officers other than Mr. Shi, which consists of four of the five individuals deemed to be our named executive officers above, were employed by the Manager (such named executive officers who are employed by the Manager, the “Manager Executives”). Because our Management Agreement provides that our Manager is responsible for managing our day-to-day affairs, the Manager Executives did not currently receive any cash or equity-based compensation from us or any of our subsidiaries for serving as our executive officers. Additionally, the Management Agreement does not require the Manager Executives to dedicate a specific amount of time to fulfilling our Manager’s obligations to us under the Management Agreement and does not require a specified amount or percentage of the fees paid to the Manager to be allocated to the Manager Executives. Our Manager does not compensate its employees specifically for such services because these individuals also provide investment management and other services to other investment vehicles that are sponsored, managed or advised by affiliates of our Manager. As a result, our Manager has informed us that it cannot identify the portion of the compensation awarded to the Manager Executives by our Manager that relates solely to their services to us. Accordingly, we are unable to provide complete compensation information for any of the Manager Executives, including our Chief Executive Officer, as the total compensation of the Manager Executives reflects the performance of all the investment vehicles for which these individuals provide services, including, but not limited to, us.
Mr. Shi is the only named executive officer who was employed by us during fiscal year 2024 and the only named executive officer for whom we made compensation determinations during fiscal year 2024. Accordingly, unless specified otherwise, the following disclosures regarding the compensation paid to our named executive officers relates only to the compensation paid to Mr. Shi. As described below under the heading “Item 13. Certain Relationships and Related Transactions, and Director Independence-KKR Funds,” certain of our consolidated subsidiaries have entered into MSAs with entities owned by KKR Funds. Pursuant to the MSAs, certain of our employees, including Mr. Shi, provide services to such entities and the Company is reimbursed for compensation paid by the Company to our employee in respect of services provided to such entities. However, the disclosures related to Mr. Shi’s compensation set forth herein reflect 100% of the compensation paid to Mr. Shi by the Company and have not been reduced by amounts, if any, for which the Company was reimbursed by entities owned by KKR Funds.
Compensation Objectives
Our compensation program is intended to attract, motivate and retain talented individuals, such as Mr. Shi, who are committed to high performance and achieving successful company results. Our compensation program is not only designed to align the incentives of executives with our stockholders’ interests, but also to promote the achievement of key corporate performance measures.
Summary of Compensation Practices
We strive to maintain judicious governance standards and compensation practices by regularly reviewing best practices. We incorporated many best practices when forming our 2024 compensation program, including the following:
What We Do
R Align our executive compensation with Company performance
R Align executives’ interests with those of stockholders through awards of stock-based compensation
R Engage an independent compensation consultant, Meridian Compensation Partners (“Meridian”), to assess our practices with its independence reviewed on an annual basis by us
R Require that all annual equity awards have a minimum of one year before any initial vesting
R Maintain policies that:
•Prohibit all employees from short selling our securities, entering into any derivative transactions with respect to our securities, or otherwise hedging the risk and rewards of our securities
•Prohibit Section 16 officers and directors from pledging our securities
•Claw back incentive-based compensation under certain circumstances
R Provide for limited perquisites
What We Don’t Do
Q Automatically increase salaries each year or make lock-step changes in compensation based on peer group compensation levels or metrics
Q Pay guaranteed or multi-year cash bonuses
Q Provide significant perquisites
Q Provide tax gross-ups
Q Provide single-trigger payments upon a change in control
To help retain and motivate executives, our compensation committee aims to offer competitive compensation packages through a mix of cash and long-term, equity-based incentives. The compensation committee does not have any formal policies for allocating total compensation among the various components. Instead, the compensation committee uses its judgment, in consultation with Meridian, to establish an appropriate balance of short-term and long-term compensation for such named executive officers. The balance may change from year to year based on corporate strategy, financial performance and non-financial objectives, among other considerations.
Process for Determining 2024 Compensation
We do not determine the cash or other compensation payable by our Manager to the Manager Executives. Our Manager and its affiliates determine the salaries, bonuses and other wages earned by the Manager Executives from our Manager and its affiliates. Our Manager and its affiliates also determine whether and to what extent the Manager Executives will be provided with the opportunity to participate in employee benefit plans. The process for determining the compensation paid to Mr. Shi and our non-employee directors during 2024 is described below.
Role of Compensation Committee
The compensation committee oversees our executive compensation and employee benefit programs, and, as a result, reviews and approves all compensation decisions relating to Mr. Shi. The compensation committee also approves its report for inclusion in this Annual Report and has reviewed and discussed this Compensation Discussion and Analysis with management.
The compensation committee reviews and approves, or recommends that our Board of Directors approve, the compensation of Mr. Shi and our non-employee directors, administers our incentive compensation and benefit plans, selects and retains independent compensation consultants and assesses whether any of our compensation policies and programs have the potential to encourage excessive risk-taking. The compensation committee may delegate, to any subcommittee it may form, responsibility and authority for any particular matter as it deems appropriate under the circumstances. The compensation committee may also delegate approval of award grants and other responsibilities regarding the administration of compensatory programs to a subcommittee consisting solely of members of the compensation committee or to members of the Board who are “non-employee directors” for purposes of Rule 16b-3 of the Exchange Act.
Role of Independent Compensation Consultant
During fiscal year 2024, the compensation committee continued to engage Meridian as its independent compensation consultant to assist the committee with its responsibilities related to our executive officer and director compensation programs. A representative of Meridian attends compensation committee meetings as requested. Meridian provides no services to management or the compensation committee that are unrelated to the duties and responsibilities of the compensation committee, and the compensation committee makes all decisions regarding the compensation of Mr. Shi and our non-employee directors. Meridian reports directly to the compensation committee, and all work conducted by Meridian for us is on behalf of the compensation committee.
Role of Chief Executive Officer and Senior Management
Our named executive officers regularly interact with the compensation committee and its chair to suggest and discuss our compensation structure and programs. Our chief executive officer makes recommendations for the annual cash and equity incentive awards for Mr. Shi and other employees of the Company.
Use of Market Data and Peer Group Analysis
From time to time, Meridian provides the compensation committee with market and peer group data for comparison purposes, such as to compare equity and pay mix practices. Meridian provides the compensation committee with a general survey of total compensation benchmarks that are reviewed by the compensation committee in its compensation determinations.
Risk Assessment of Compensation Plans
Each year, the Committee assesses the Company’s risk profile relative to the executive compensation program and confirms that its compensation programs and policies do not create or encourage excessive risks that are reasonably likely to have a material adverse impact on the Company. As a result, we believe that our compensation program does not encourage excessive or unnecessary risk taking. This is primarily due to the fact that our compensation programs and the compensation arrangements with the Manager are designed to encourage our named executive officers and employees to focus on both short-term and long-term strategic goals, thereby creating an ownership culture and helping to align the interests of our employees and our stockholders. Accordingly, our compensation program is balanced between short-term and long-term incentive compensation. Short-term incentive compensation is paid to Mr. Shi annually in cash, but is dependent on satisfying quantitative and qualitative factors determined in the discretion of the Compensation Committee each year.
2024 Compensation Decisions
Base Salary
Base salaries serve to provide fixed cash compensation to our employees, including Mr. Shi, for performing their ongoing responsibilities to the Company. During 2024, Mr. Shi’s base salary was $400,000. Effective January 1, 2025, based on an analysis of the competitive marketplace provided by Meridian and Mr. Shi's contributions, performance and experience, the Compensation Committee approved the increase of Mr. Shi’s base salary to $465,000.
While we do not pay the Manager Executives any cash compensation, we pay the Management Compensation to our Manager. The Management Compensation compensates our Manager for the services that it provides to the Company, including making the Manager Executives available to serve as our executive officers. The Manager Compensation is described in more detail under the heading “Items 1 and 2. Business and Properties-Management Agreement.”
Annual Cash Incentive Awards
Annual cash incentive awards are used to motivate and reward our employees, including Mr. Shi. We do not maintain a formal annual cash incentive award program, as such awards are instead determined on a discretionary basis and are generally based on individual performance and the financial health and performance of the Company. The target amount of Mr. Shi’s annual cash incentive compensation for 2024 was set at 115% of Mr. Shi’s base salary (“Target Bonus”). Due to strong company and individual performance, the Compensation Committee awarded Mr. Shi annual cash incentive compensation for 2024 at 105% of Target Bonus. The Compensation Committee reviewed input from Meridian and the considerations outlined above and modified Mr. Shi’s target annual cash incentive compensation target to 90% of Mr. Shi’s base salary for 2025.
Equity-Based Compensation
We have adopted two equity incentive plans pursuant to which we may grant equity-based compensation to our service providers. Our Compensation Committee believes that awards under these plans promote alignment of the interests of management with those of our stockholders and promote creation of value for our stockholders. The Manager Incentive Plan governs the Incentive Compensation granted to our Manager, and the Equity Incentive Plan governs awards granted to our service providers, including the Manager Executives and Mr. Shi. However, during fiscal years 2022, 2023 and 2024, none of the Manager Executives were granted an award under the Equity Incentive Plan.
During 2023 and 2024, we issued restricted stock unit awards subject to time-based vesting to certain of our employees, including Mr. Shi, and our non-employee directors pursuant to the Equity Incentive Plan. On April 1, 2024, Mr. Shi was granted an award of 22,361 RSUs, with the number of such RSUs determined by dividing Mr. Shi’s target equity award value (which was $250,000) by $11.18, which was the volume-weighted average closing price per share of our Class A Common Stock for the 20 trading days preceding December 7, 2023 (matching the 20 trading day measurement period under the Incentive Compensation). Mr. Shi’s 2024 award of RSUs will vest in substantially equal installments on each of the first three anniversaries of April 1, 2024, subject to his continuous employment with the Company through each such vesting date. The actual value realized by Mr. Shi with respect to his RSU awards will be dependent on the value of the Class A Common Stock on the relevant settlement date.
While we did not grant the Manager Executives any awards under the Equity Incentive Plan during fiscal years 2022, 2023 and 2024, we pay our Manager the Incentive Compensation. The Incentive Compensation serves to further align the interests of our Manager and the Manager Executives with those of the Company and its stockholders and mitigates the possibility of excessive
risk taking. The Incentive Compensation is described in more detail under the headings “Items 1 and 2. Business and Properties-Management Agreement” and “Item 12. Security Ownership of Certain Beneficial Owner and Management and Related Stockholder Matters-Equity Compensation Plan Information.”
Employment Agreements and Severance and Change in Control Benefits
We have not entered into employment agreements with any of our named executive officers. Further, we do not have any arrangements that would obligate us to make payments to the Manager Executives upon the termination of their services to us or in the event of a change in control of us. However, the award agreements governing the RSU awards granted to Mr. Shi in 2023 and 2024 provide for “double trigger” acceleration of vesting in the event that Mr. Shi experiences a qualifying termination in the 12-month period following a change in control. Mr. Shi is not entitled to any payments or benefits in connection with a termination of his employment that occurs prior to, or more than 12 months following, a change in control. The arrangement with Mr. Shi is described in more detail under the heading “-Potential Payments Upon Termination or Change in Control.”
Other Benefits
Employee Benefits
We offer a comprehensive array of benefits to our employees, including Mr. Shi. These benefits are offered in order to attract and retain qualified employees. Subject to the terms of any applicable plans, policies or programs, Mr. Shi is entitled to receive employee benefits, including any and all vacation, deferred compensation, retirement, health and welfare insurance as we may provide from time to time to salaried employees generally, and such other benefits as the Compensation Committee may from time to time establish for our management-level employees.
Retirement Benefits
We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code whereby employees, including Mr. Shi, are allowed to contribute a portion of their base salaries to a tax qualified retirement account. In fiscal years 2023 and 2024, matching contributions were made to participating employees equal to 100% of the employee’s deferral contributions up to 5% of the employee’s compensation, subject to applicable nondiscrimination limitations imposed by the Code. The contributions made on behalf of Mr. Shi for fiscal year 2024 are disclosed in the footnotes to the Summary Compensation Table.
Other Compensation Policies and Practices
Anti-Hedging and Pledging Policies
All directors, officers and other employees of the Company are prohibited from making any short sales of any securities of the Company and from engaging in transactions involving Company-based derivative securities. This prohibition includes, but is not limited to, trading in Company-based option contracts, transacting in straddles or collars, hedging (generally purchasing any financial instrument or engaging in any transactions that hedge or offset, or are designed to hedge or offset, any decrease in the market value of the Company’s securities), transacting in convertible debt and writing puts or calls. In addition, pursuant to the Company’s Insider Trading Policy, directors, officers and employees are prohibited from holding the Company’s securities in a margin account or pledging securities of the Company as collateral for a loan. Pledging of the company securities in conjunction with hedging transactions is prohibited.
Stock Ownership Guidelines
To further align the interests of our directors with the interests of the Company’s other stockholders, our Nominating Committee established stock ownership and retention guidelines for our non-employee directors during 2023 that continued to apply during 2024. These guidelines are described in detail under the heading “-Director Compensation” below.
Clawback Policy
On October 31, 2023, our Board of Directors adopted a clawback policy (the “Clawback Policy”) that complies with the final rule adopted by the SEC in November 2022 and the applicable listing standards adopted by the New York Stock Exchange. The Clawback Policy requires us to recoup certain incentive-based compensation erroneously awarded to our current and former executive officers in the event of an accounting restatement.
Say on Pay Vote
In accordance with Dodd-Frank and as required by Rule 14a-21 of the Exchange Act, because we have not yet solicited proxies from our stockholders related to the election of directors, we have not yet held a non-binding, advisory note on the compensation of our named executive officers. We will hold such a vote at the first meeting for which we are required to do so. We value the opinions of our stockholders and are committed to excellence in corporate governance, and as part of this commitment, our Compensation Committee and Board of Directors intend to consider the results of future shareholder advisory votes when determining the compensation we pay to our named executive officers.
2024 Compensation Committee Report
Our compensation committee has furnished the following report. The information contained in this “Compensation Committee Report is not to be deemed “soliciting material” or “filed” with the SEC, nor is such information to be incorporated by reference into any future filings under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filings.
The compensation committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K under the Exchange Act with management. Based on such review and discussions, the compensation committee recommended to our board of directors that the Compensation Discussion and Analysis be included in this Annual Report.
Compensation Committee of the Board of Directors
Claire Farley
Bevin Brown
Brandi Kendall
2024 Executive Compensation Tables
Summary Compensation Table
The following table sets forth the compensation paid to our named executive officers by us for their services for the fiscal years presented.
Name and Principal Position Year Salary
($) Bonus
($) Stock Awards
($) (1)
All Other Compensation
($) (2)
Total
($)
Bo Shi 2024 400,000 483,000 261,176 19,301 1,163,477
General Counsel and Corporate Secretary 2023 400,000 460,000 105,013 18,920 983,933
2022 300,000 345,000 134,485 14,182 793,667
David C. Rockecharlie 2024 - - - - -
Chief Executive Officer 2023 - - - - -
2022 - - - - -
Brandi Kendall 2024 - - - - -
Chief Financial Officer 2023 - - - - -
2022 - - - - -
Todd N. Falk 2024 - - - - -
Chief Accounting Officer 2023 - - - - -
2022 - - - - -
John Clayton "Clay" Rynd 2024 - - - - -
Executive Vice President 2023 - - - - -
2022 - - - - -
_______________
(1) The amount reported in this column represents the aggregate grant date fair value, determined in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, of RSUs awarded in 2024 and 2023 under our
Equity Incentive Plan to Mr. Shi. The assumptions used in calculating the aggregate grant date fair value of such award are described in "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. As described in the Compensation Discussion and Analysis, the amount reported in this column does not reflect the actual value that will be realized by Mr. Shi in respect of his 2023 and 2024 RSU awards. We have not granted equity or equity-based awards to any of the Manager Executives.
(2) Amounts reported in this column for Mr. Shi reflect Company-paid life insurance premiums and 401(k) matching contributions in the amounts of $120 and $19,181 for the fiscal year ended December 31, 2024.
Grants of Plan-Based Awards for Fiscal Year 2024
The table below includes information regarding RSUs granted under our Equity Incentive Plan to our named executive officers during the fiscal year ended December 31, 2024.
Name Grant Date Approval Date All Other Stock Awards: Number of Shares of Stock or Units
(#) (1)
Grant Date Fair Value of Stock and Option Awards
($) (2)
Bo Shi 04/01/2024 3/3/2024 22,361 261,176
David C. Rockecharlie - - - -
Brandi Kendall - - - -
Todd N. Falk - - - -
John Clayton "Clay" Rynd - - - -
_______________
(1) The amount included in this column represents the number of RSUs granted to Mr. Shi pursuant to the Equity Incentive Plan during fiscal year 2024. These RSUs will vest in substantially equal installments on each of the first three anniversaries of April 1, 2024. For more information, see the section titled “Compensation Discussion and Analysis-Equity-Based Compensation” above.
(2) The amount reported in this column represents the aggregate grant date fair value, determined in accordance with FASB ASC 718, of the RSUs granted to Mr. Shi in 2024. The assumptions used in calculating the aggregate grant date fair value of such award are described in "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.
Narrative to Summary Compensation Table and Grants of Plan Based Awards Table
Employment Agreements
We have not entered into employment agreements with any of our named executive officers. More information on the agreements we have entered into with our named executive officers is provided in the Compensation Discussion and Analysis above under the heading “-Compensation Discussion and Analysis-Employment Agreements and Severance and Change in Control Benefits.”
Salary and Bonus in Proportion to Total Compensation
The table below reflects the aggregate amount of Mr. Shi’s 2024 salary and bonus in proportion to the total compensation paid to Mr. Shi during 2024. The amounts reported in this table for Mr. Shi were calculated using the amounts reported in the “Salary” and “Bonus” columns of the Summary Compensation Table above. More information regarding Mr. Shi’s salary and bonus arrangements is provided in the Compensation Discussion and Analysis above under the headings “-Compensation Discussion and Analysis-2024 Compensation Decisions-Base Salary” and “-Compensation Discussion and Analysis-2024 Compensation Decisions-Annual Cash Incentive Awards.”
Name Year Salary and Bonus
($) Salary and Bonus as a Percentage of Total Compensation
Bo Shi 2024 883,000 76%
We do not pay any cash or other compensation to the Manager outside of the Manager Incentive Plan as described in more detail in the Compensation Discussion and Analysis above.
Equity Incentive Plan Awards
We granted awards of time-based RSUs to Mr. Shi under the Equity Incentive Plan during 2023 and 2024. Mr. Shi will have no right to receive any dividends or other distribution with respect to a RSU unless and until shares of Class A Common Stock have been delivered in respect of the RSUs that become vested, if any, in accordance with the terms and conditions of the corresponding RSU award. The terms and conditions, including vesting, applicable to Mr. Shi’s 2023 and 2024 RSU awards are further described in the Compensation Discussion and Analysis above under the heading “-Compensation Discussion and Analysis-Equity-Based Compensation.” The potential acceleration and forfeiture events relating to Mr. Shi’s 2023 and 2024 RSU awards are described, as of December 31, 2024, in greater detail under the heading “-Potential Payments Upon Termination or Change in Control” below.
Outstanding Equity Awards at 2024 Fiscal Year End
The following table reflects information regarding outstanding equity-based awards held by our named executive officers as of December 31, 2024, which consist of RSUs granted under the Equity Incentive Plan to Mr. Shi.
Name Stock Awards
Number of Shares or Units of Stock That Have Not Vested
(#) (1)
Market Value of Shares or Units of Stock That Have Not Vested
($) (2)
Bo Shi 30,986 $452,705
David C. Rockecharlie - -
Brandi Kendall - -
Todd Falk - -
John Clayton "Clay" Rynd - -
_______________
(1) Each RSU award granted to Mr. Shi represents the contingent right to receive one share of our Class A Common Stock upon vesting. The 2023 RSU award vested as to one-third of the RSUs granted on April 1, 2024 and will vest as to an additional one-third of the RSUs granted on April 1 of 2025 and 2026. The 2024 RSU award will vest in substantially equal one-third installments on April 1 of 2025, 2026, and 2027.
(2) The amount included in this column represents the market value of our Class A Common Stock underlying the RSU awards granted to Mr. Shi, computed based on the closing price of our Class A Common Stock on December 31, 2024, the last trading day of 2024, which was $14.61 per share.
Option Exercises and Stock Vested in Fiscal Year 2024
Name Stock Awards
Number of Shares Acquired on Vesting
(#) (1)
Value Realized on Vesting
($) (1)
Bo Shi 5,530 $65,807
David C. Rockecharlie - -
Brandi Kendall - -
Todd Falk - -
John Clayton "Clay" Rynd - -
_______________
(1) Reflects shares received pursuant to the vesting, on April 1, 2024, of RSUs subject to Mr. Shi's 2022 and 2023 RSU awards. The value realized on vesting reflects the closing price of our Class A Common Stock on March 28, 2024 (the last trading day preceding the vesting date), which was $11.90, multiplied by the number of shares of our Class A Common Stock received by Mr. Shi.
Pension Benefits and Nonqualified Deferred Compensation
We have not maintained, and do not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits to our employees, including the named executive officers.
Potential Payments Upon Termination or Change in Control
Termination and Change in Control Arrangements
Since the Manager Executives are employees of our Manager or its affiliates, we do not have any obligations to make any payments to the Manager Executives upon a termination of employment or upon a change of control. However, we are obligated to make certain payments to the Manager in connection with certain terminations of the Management Agreement. Such payments are described above under the heading “Items 1 and 2. Business and Properties-Management Agreement.”
The award agreements governing Mr. Shi’s 2023 and 2024 RSU awards provide that, upon a termination of Mr. Shi’s employment by the Company without “cause” or a resignation by Mr. Shi for “good reason” that, in each case, occurs within the 12 month period following a “change in control” of the Company, any RSUs that remain unvested as of the date of such termination will immediately vest in full, provided Mr. Shi has remained continuously employed by us from the grant date of such award through the date of termination. Upon a termination of Mr. Shi’s employment for any other reason, any unvested RSUs held by him as of the applicable termination date will be forfeited without consideration. Mr. Shi is not entitled to any payments or benefits in connection with a termination of his employment that occurs prior to, or more than 12 months following, a change in control of the Company.
The terms set forth below are generally defined as follows for purposes of Mr. Shi’s award agreement:
•“cause” means one or more of the following: (i) gross negligence or willful misconduct in the performance of duties to the Company or its affiliates, (ii) material breach of any material provision of any written agreement with the Company or an affiliate, or the material breach of an applicable corporate policy or code of conduct, (iii) willful conduct that is materially injurious to the Company or an affiliate, or (iv) conviction of, plea of no contest to, or the receipt of deferred adjudication or adjudicated probation in connection with a felony involving fraud, dishonesty or moral turpitude (or a crime of similar import in a foreign jurisdiction);
•“good reason” means a material diminution in base salary, provided that good reason exists only if such diminution occurs without consent, written notice is provided to the Company of such diminution within 45 days of its occurrence, such diminution remains uncorrected for 30 days following receipt of such notice and the date of termination occurs within 90 days of the date such notice is received by the Company; and
•“change in control” means one of the following: (i) the acquisition of more than 50% of the then outstanding Class A Common Stock or total voting power of the Company, (ii) a majority of the members of the Board are replaced with individuals who are not incumbent directors over any two year period, (iii) a sale, merger or similar transaction or series of related transactions involving the Company, as a result of which the owners of the Company’s securities prior to such transaction cease to hold more than 50% of the voting securities of the surviving entity, any single person owns more than 50% of the securities entitled to vote for the election of directors or the incumbent directors prior to such transaction cease to represent at least a majority of the board of the surviving entity or its parent, or (iv) the sale of all or substantially all of the assets of the Company in a transaction or series of related transactions.
Quantification of Benefits
The following table provides information concerning the estimated payments and benefits that would be provided in the circumstances described above to each of our named executive officers. Except where otherwise noted, payments and benefits are estimated assuming both qualifying termination of employment and a change in control occurred on December 31, 2024. There can be no assurance that a triggering event would produce the same or similar results as those estimated below if such event occurs on any other date or at any other price, or if other circumstances affect the assumptions used to estimate these potential payments and benefits. Due to the number of factors that affect the nature and amount of any potential payments or benefits, any actual payments and benefits paid in such circumstances may be different than those set forth in the table below.
Benefits and Payments Termination Without Cause or for Good Reason During 12 Month Period Following Change in Control
($) Change in Control
($) (1)
All Other Terminations
($) (1)
Bo Shi
Cash Severance $ - $ - $ -
Accelerated Equity Awards 452,705 (2)
- -
Total $ 452,705 $ - $ -
David C. Rockecharlie
Cash Severance $ - $ - $ -
Accelerated Equity Awards - - -
Total $ - $ - $ -
Brandi Kendall
Cash Severance $ - $ - $ -
Accelerated Equity Awards - - -
Total $ - $ - $ -
Todd N. Falk
Cash Severance $ - $ - $ -
Accelerated Equity Awards - - -
Total $ - $ - $ -
John Clayton "Clay" Rynd
Cash Severance $ - $ - $ -
Accelerated Equity Awards - - -
Total $ - $ - $ -
_______________
(1) None of the Manager Executives are eligible to receive any payments or benefits in the event of a change in control of us or a termination of employment. Further, Mr. Shi is not eligible to receive any payments or benefits in any of the following scenarios: the occurrence of a change in control without a qualifying termination of employment, a termination of employment by the Company with or without Cause outside the 12 month period following a change in control, a termination of employment due to a named executive officer’s resignation with or without good reason outside the 12 month period following a change in control, or a termination due to a named executive officer’s death or disability.
(2) This amount was calculated by multiplying (a) the number of shares of our Class A Common Stock underlying Mr. Shi’s RSU awards that would accelerate upon a qualifying termination of Mr. Shi’s employment that occurred in December 31, 2024, assuming that such termination occurred during the 12-month period following a change in control, by (b) $14.61, the closing price of our Class A Common Stock on December 31, 2024, the last trading day of 2024.
CEO Pay Ratio
Section 953(b) of Dodd-Frank, and Item 402(u) of Regulation S-K, requires that we provide information about the relationship of the annual total compensation of David C. Rockecharlie, our chief executive officer, to the median annual total compensation of other employees providing services to us. However, as disclosed in the “Compensation Discussion and Analysis” section above, Mr. Rockecharlie did not receive any direct cash or other compensation from us nor did our Manager allocate any cash or other compensation solely for Mr. Rockecharlie’s services as our chief executive officer, and we did not reimburse our Manager or any of its affiliates for any compensation paid to Mr. Rockecharlie. As a result, we are unable to provide a ratio of the median employee’s annual total compensation to the total annual compensation of Mr. Rockecharlie.
Director Compensation
2024 Compensation
The following table sets forth information concerning the compensation paid by us to our directors for the fiscal year ended December 31, 2024.
Name Fees Earned or Paid in Cash
($) Stock Awards
($)(2)(3)
All Other Compensation
($) Total
($)
John C. Goff 80,000 297,747 - 377,747
Claire S. Farley 99,500 167,153 - 266,653
Robert G. Gwin 80,000 167,153 - 247,153
Ellis L. “Lon” McCain 100,000 167,153 - 267,153
Karen J. Simon 80,000 167,153 25,000 (4)
272,153
Erich Bobinsky (1)
80,000 167,153 - 247,153
Bevin Brown (1)
80,000 167,153 - 247,153
_______________
(1) Erich Bobinsky and Bevin Brown are officers and employees of Liberty Holdco and serve on our Board of Directors as nominees of PT Independence. Mr. Bobinsky and Ms. Brown have agreed that they will not receive any separate compensation for serving as directors of the Company and have agreed to transfer to Liberty Holdco any director compensation that they receive from us, including any shares received in respect of equity or equity-based awards. As such, all amounts reported for Mr. Bobinsky and Ms. Brown in this table will not be retained by them, but instead will be transferred to Liberty Holdco. As such, Mr. Bobinsky and Ms. Brown will not retain any compensation with respect to their service on our Board of Directors in 2024. The aggregate number of outstanding RSUs held, as of December 31, 2024, by Mr. Goff was 25,492 and by each other non-management director was 14,311.
(2) The amounts reported in this column represent the aggregate grant date fair value, determined in accordance with FASB ASC 718, of 25,492 RSUs that were granted to Mr. Goff and the 14,311 RSUs that were granted to each other non-management director pursuant to the Equity Incentive Plan on April 1, 2024. The assumptions used in calculating the aggregate grant date fair value of such awards are described in "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. The RSU awards will vest in full on April 1, 2025, subject to the director continuously providing services on our Board of Directors through such date.
(3) As described below, the target value of the annual equity-based compensation granted to our non-management directors is $160,000 plus an additional award with a target value of $125,000 to the non-executive Chairman of the Board. The number of RSUs issued pursuant to the 2024 awards was determined by dividing such target value by $11.18, which was the volume-weighted average closing price per share of our Class A Common Stock for the 20 trading days preceding December 7, 2023 (matching the 20 trading day measurement period under the Incentive Compensation).
(4) The amount reported represents a charitable donation made on Ms. Simon's behalf in connection with her service on the Company's Sustainability Council.
Director Compensation Policy
We established a comprehensive non-management director compensation policy. The policy is designed to provide competitive compensation necessary to attract and retain high quality non-management directors and to encourage ownership of our Class A Common Stock to further align their interests with those of the Company’s stockholders. No compensation is paid to management directors. The non-management director compensation policy in effect for the fiscal year ended December 31, 2024, provided for the following compensation to our non-management directors:
•An annual cash retainer of $80,000;
•An annual equity-based award with a value of $160,000 (adjusted for partial periods of service) granted in the form restricted stock units, subject to a one-year vesting period;
•An additional equity-based award to the non-executive Chairman of the Board with a value of $125,000 granted in the form of restricted stock units, subject to a one-year vesting period;
•An additional annual cash retainer for the following committee chairs:
•$20,000 for the chairperson of the Audit Committee,
•$10,000 for the chairperson of the Compensation Committee, and
•$9,500 for the chairperson of the Nominating Committee.
We also provide for the reimbursement of out-of-pocket expenses incurred by directors in the performance of their duties, including reasonable travel expenses incurred attending meetings. Each director is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.
Stock Ownership Requirements
To further align the interests of our non-employee directors with those of our stockholders, in November 2022, our Nominating Committee adopted stock ownership and retention requirements for all non-management directors, other than Mr. Bobinsky or Ms. Brown who were appointed to serve on our Board pursuant to the director nominee rights held by their employer, Liberty, and are prohibited by Liberty from owning securities of the Company in their individual capacities.
Pursuant to the stock ownership guidelines, the applicable non-management directors are required to own common stock of the Company equal in value to at least five times their total annual cash retainer, which includes any additional annual retainer paid for service on a committee. Share equivalents (including restricted stock units) are counted for purposes of satisfying the stock ownership requirement. Non-management directors must attain such ownership within five years of the date the guidelines were adopted, or five years of joining the Board, whichever is later.
Manager Incentive Plan
In 2021, we adopted and our stockholders approved, the Manager Incentive Plan. The purpose of the Manager Incentive Plan is to provide a means through which we may provide equity-based compensation to the Manager, as required by the Management Agreement. The description of the Manager Incentive Plan set forth below is a summary of the material features of the Manager Incentive Plan. This summary does not purport to be a complete description of all of the provisions of the Manager Incentive Plan and is qualified in its entirety by reference to the Manager Incentive Plan, which is attached hereto as Exhibit 10.6.
Manager Incentive Plan Share Limit. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the Manager Incentive Plan, 4,306,745 were initially reserved for issuance pursuant to awards under the Manager Incentive Plan. The aggregate number of shares of Class A Common Stock reserved for delivery shall be increased on January 1 of each calendar year that occurs before the tenth anniversary of the Effective Date (as defined in the Manager Incentive Plan) by 10% of the additional Class A Common Stock issued, if any, during the immediately preceding calendar year. If an award under the Manager Incentive Plan is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the Manager Incentive Plan.
Administration. The Manager Incentive Plan is administered by the board or a committee later appointed by the board.
Awards. The Manager Incentive Plan provides for the grant of (i) stock options; (ii) stock appreciation rights; (iii) restricted or unrestricted Class A Common Stock; (iv) restricted stock units; (v) other equity-based awards; (vi) incentive awards; (vii) cash awards; (viii) performance awards; and (ix) substitute awards.
Certain Transactions. If any change is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of Class A Common Stock, appropriate adjustments will be made by the committee in the shares subject to awards under the Manager Incentive Plan. The committee will also have the discretion to make certain adjustments to awards in the event of a Change in Control (as defined in the Manager Incentive Plan), such as accelerating the vesting or exercisability of awards, requiring the assumption of awards or substitution of awards for new awards or cancelling awards in exchange for payments of consideration in forms determined by the committee.
Clawback Policy. All awards under the Manager Incentive Plan will be subject to our clawback or recapture policy, as in effect from time to time.
Amendment and Termination. The board may amend or terminate the Manager Incentive Plan at any time; however, no amendment may adversely impair the rights of participants with respect to outstanding awards and shareholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing standards. The committee will not have the authority, without the approval of shareholders, to amend any outstanding stock option or stock appreciation right to reduce its exercise price per share. The Manager Incentive Plan will remain in effect for a period of ten years following the effective date of the Manager Incentive Plan (unless earlier terminated by the Board).
Other. As described under “The Transaction Agreement and Related Agreements-OpCo LLC Agreement”, the OpCo LLC Agreement provides that, subject to certain exceptions, at any time we issue a share of Class A Common Stock or any other equity security (including awards granted under the Manager Incentive Plan) following December 7, 2021, the net proceeds received by us with respect to such issuance, if any, will be concurrently contributed to OpCo, which, in turn, will issue one Unit (if we issue a share of Class A Common Stock) or such other equity security (if we issue equity securities other than Class A Common Stock) corresponding to the equity securities issued by us to the Company Group.
The Incentive Compensation
In 2021, the Manager was granted the Incentive Compensation, which is an award of PSUs under the Manager Incentive Plan, as required by the Management Agreement. This summary does not purport to be a complete description of all of the provisions of the Incentive Compensation and is qualified in its entirety by reference to the award agreement governing the Incentive Compensation (the “Award Agreement”), the form of which is included as Exhibit 10.5 hereto.
General Description. The Incentive Compensation is a grant of five “Target PSUs,” each of which corresponds to a number of shares of Class A Common Stock equal to 2% of the total number of shares of Class A Common Stock outstanding on each Performance Period End Date (as defined in the Award Agreement). The Incentive Compensation represents the right to receive shares of Class A Common Stock in an amount ranging from 0% to 240% of each Target PSU, subject to the Company’s achievement of certain performance-based vesting conditions.
Vesting. Each Target PSU will become earned, if at all, following the determination of the Company’s level of achievement of certain performance goals during a three-year performance period. For each performance period, the performance goals for (i) 60% of the Target PSU shall be based on the Company’s absolute total stockholder return (the “Absolute TSR Portion”) during the applicable performance period and (ii) 40% of the Target PSU shall be based on the relative total stockholder return (the “Relative TSR Portion”) ranking of the Company as compared to our peer group during the applicable performance period.
The certification of the Company's level of achievement with respect to the first Target PSU for the first three-year-performance period under the Incentive Compensation is in process and is expected to be completed in 2025.
For each performance period, the Absolute TSR Portion of the Target PSU will become earned based on the committee’s determination of the Company’s Absolute TSR Portion in accordance with the table below.
Absolute TSR (%) Earned Amount (% of Absolute TSR Portion)*
<25%
0%
25%
100%
55%
150%
85%
200%
115%
250%
145%
300%
For each performance period, the Relative TSR Portion of the Target PSU will become earned based on the committee’s determination of the Company’s Relative TSR in accordance with the table below.
Relative TSR Percentile Ranking Earned Amount (% of Relative TSR Portion)*
<20th Percentile
0%
20th Percentile
50%
40th Percentile
75%
60th Percentile
100%
70th Percentile
125%
≥80th Percentile
150%
Acceleration of Vesting. The Award Agreement provides that unearned Target PSUs will immediately be deemed earned with respect to 100% of such Target PSUs upon the occurrence of a Change in Control or a complete liquidation or dissolution of the Company, provided that the Management Agreement has not been terminated prior to such date.
Equity Incentive Plan
In 2021, we adopted, and our stockholders approved, the Equity Incentive Plan. On May 10, 2023, the Board adopted, and stockholders holding a majority of the shares of voting power of our Class A Common Stock and Class B Common Stock approved the adoption of, the First Amendment to the Equity Incentive Plan (the “First Amendment”). The First Amendment increases the number of shares of our Class A Common Stock authorized to be delivered under the Equity Incentive Plan by 2,477,201 shares.
On October 29, 2024, our Board of Directors adopted the Second Amendment (the “Second Amendment”) to the Crescent Energy Company 2021 Equity Incentive Plan (as amended from time to time, the “Plan”). Pursuant to the Second Amendment, an additional 2,848,006 shares of our Class A Common Stock may be issued pursuant to the Plan as a result of the assumption of the authorized but unused shares that remained available under the SilverBow Resources, Inc. 2016 Equity Incentive Plan (the SilverBow Plan”) following the completion of the SilverBow Merger. For the avoidance of doubt, in accordance with Section 303A.08 of the New York Stock Exchange Listed Company Manual, the authorized but unused shares that remained available under the SilverBow Plan were adjusted to reflect the SilverBow Merger in order to determine the 2,848,006 shares of
Class A Common Stock added to the Plan pursuant to the Second Amendment. The additional shares of our Class A Common Stock authorized to be issued under the Plan pursuant to the Second Amendment were registered pursuant to a registration statement on Form S-8, which is included as Exhibit 10.6 hereto.
The purpose of the Equity Incentive Plan is to incentivize individuals providing services to the Company or its affiliates as its employees, officers or non-employee directors through grants of equity-based incentive awards. Any individual employed by the Manager or any of its parent companies is not be eligible to participate in the Equity Incentive Plan. As such, none of our executive officers, including the named executive officers, except for Mr. Shi are eligible to participate in the Equity Incentive Plan. The description of the Equity Incentive Plan set forth below is a summary of the material features of the Equity Incentive Plan. This summary does not purport to be a complete description of all of the provisions of the Equity Incentive Plan and is qualified in its entirety by reference to the Equity Incentive Plan.
Equity Incentive Plan Share Limits. Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the Equity Incentive Plan, 3,338,550 shares of Class A Common Stock are reserved for issuance pursuant to awards under the Equity Incentive Plan (after giving effect to the First Amendment). The total number of shares reserved for issuance under the Equity Incentive Plan may be issued pursuant to incentive stock options (which generally are stock options that meet the requirements of Section 422 of the Code). If an award under the Equity Incentive Plan is forfeited, settled for cash or expires without the actual delivery of shares, any shares subject to such award will again be available for new awards under the Equity Incentive Plan.
Administration. The Equity Incentive Plan is administered by the board or a committee later appointed by the board.
Awards. The Equity Incentive Plan provides for the grant of (i) stock options; (ii) stock appreciation rights; (iii) restricted or unrestricted Class A Common Stock; (iv) restricted stock units; (v) other equity-based awards; (vi) incentive awards; (vii) cash awards; (viii) performance awards; and (ix) substitute awards.
Maximum Calendar Year Award. No non-employee director may receive, in any one calendar year, more than $1,000,000 in the aggregate in awards granted under the Equity Incentive Plan and cash compensation (including retainers and cash-based awards). Notwithstanding the foregoing, awards and cash compensation may be granted or paid to non-employee directors in excess of such limits for any calendar year in which the director first commences service on the Board of Directors, serves on a special committee of the Board of Directors, or serves as lead director or chairman of the Board of Directors.
Certain Transactions. If any change is made to the Company’s capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, which results in an increase or decrease in the number of outstanding shares of Class A Common Stock, appropriate adjustments will be made by the committee in the shares subject to awards under the Equity Incentive Plan. The committee will also have the discretion to make certain adjustments to awards in the event of a Change in Control (as defined in the Equity Incentive Plan), such as accelerating the vesting or exercisability of awards, requiring the assumption of awards or substitution of awards for new awards or cancelling awards in exchange for payments of consideration in forms determined by the committee.
Clawback Policy. All awards under the Equity Incentive Plan will be subject to our clawback or recapture policy, as in effect from time to time.
Amendment and Termination. The board may amend or terminate the Equity Incentive Plan at any time; however, no amendment may adversely impair the rights of participants with respect to outstanding awards and shareholder approval will be required for any amendment to the extent necessary to comply with applicable law or exchange listing standards. The committee will not have the authority, without the approval of shareholders, to amend any outstanding stock option or stock appreciation right to reduce its exercise price per share. The Equity Incentive Plan will remain in effect for a period of ten years following the effective date (unless earlier terminated by the board).

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information known to us, based on filings made under Section 13(d) and 13(g) of the Exchange Act, regarding the beneficial ownership of our common stock as of January 31, 2025 by:
•each person, or group of affiliated persons, known to us to beneficially own more than 5% of our common stock;
•each member of the Board of Directors;
•each of our Named Executive Officers; and
•all of our directors and executive officers as a group.
Beneficial ownership is determined in accordance with the rules of the SEC. These rules generally attribute beneficial ownership of securities to persons who possess sole or shared voting power or investment power with respect to such securities. Except as otherwise indicated, all persons listed below have sole voting and investment power with respect to the shares beneficially owned by them, subject to applicable community property laws. Unless otherwise indicated, the address of each person or entity named in the table below is c/o Crescent Energy Company, 600 Travis Street, Suite 7200, Houston, Texas 77002.
As of January 31, 2025, there were 192,525,271 shares of our Class A Common Stock and 65,948,124 shares of our Class B Common Stock outstanding.
Shares Beneficially Owned by Certain Beneficial Owners and Management
Class A Common Stock Class B Common Stock Combined Voting Power (1)
Number % of class Number % of class Number % of class
5% Stockholders
Independence Energy Aggregator LP and its affiliates (2)
- - % 29,134,496 44.2 % 29,134,496 11.3 %
KKR Upstream Associates LLC (3)
572,354 0.3 % 29,134,496 44.2 % 29,706,850 11.5 %
PT Independence Energy Holdings LLC and its affiliates (4)(5)
41,118 * 36,813,628 55.8 % 36,854,746 14.3 %
The Vanguard Group (6)
20,749,509 10.8 % - - % 20,749,509 8.0 %
BlackRock, Inc. (7)
22,723,221 11.8 % - - % 22,723,221 8.8 %
American Century Investment Management, Inc. (8)
12,147,839 6.3 % - - % 12,147,839 4.7 %
Directors and Named Executive Officers
John C. Goff (9)
9,786,117 5.1 % - - % 9,786,117 3.8 %
David C. Rockecharlie 110,000 * - - % 110,000 *
Brandi Kendall 22,415 * - - % 22,415 *
John Clayton "Clay" Rynd 7,000 * - - % 7,000 *
Todd N. Falk 7,000 * - - % 7,000 *
Bo Shi (11)
45,811 * - - % 45,811 *
Karen J. Simon (10)
75,294 * - - % 75,294 *
Ellis L. McCain (10)
67,935 * - - % 67,935 *
Erich Bobinsky - - % - - % - - %
Bevin Brown - - % - - % - - %
Claire S. Farley (10)
34,870 * - - % 34,870 *
Robert G. Gwin (10)
34,870 * - - % 34,870 *
Marcus C. Rowland
82,492 - % - - % 82,492 *
Michael Duginski
220,000 - % - - % 220,000 *
Directors and Executive Officers as a group (14 persons)
10,493,804 5.5 % - - % 10,493,804 4.1 %
(1)Represents the percentage of voting power of our Class A Common Stock and Class B Common Stock voting together as a single class. OpCo unitholders hold one share of Class B Common Stock for each OpCo Unit that they own. Each share of Class B Common Stock has no economic rights, but entitles the holder thereof to one vote for each share of Class B Common Stock held by such holder. Accordingly, the holders of Class B Common Stock (who are also OpCo unitholders) collectively have a number of votes equal to the number of shares of Class B Common Stock that they hold.
(2)Aggregator L.P. is the direct beneficial owner of the securities reported and is the entity through which certain unaffiliated limited partners and affiliated entities hold their interests in the Company and OpCo. Aggregator GP is the general partner of Aggregator. KKR Upstream Associates LLC is the sole member of Aggregator GP. KKR Group
Assets Holdings III L.P. and KKR Financial Holdings LLC are the controlling members of KKR Upstream Associates LLC. KKR Group Assets III GP LLC is the general partner of KKR Group Assets Holdings III L.P. KKR Group Partnership L.P. is the sole member of each of KKR Group Assets III GP LLC and KKR Financial Holdings LLC. KKR Group Holdings Corp. is the general partner of KKR Group Partnership L.P. KKR & Co. Inc. is the sole shareholder of KKR Group Holdings Corp. KKR Management LLP is the Series I preferred stockholder of KKR & Co. Inc. Henry R. Kravis and George R. Roberts are the founding partners of KKR Management LLP. Each of such beneficial owners disclaims beneficial ownership of such securities in excess of their pecuniary interest therein.
(3)KKR Upstream Associates LLC is the direct beneficial owner of the 572,354 shares of Class A Common Stock reported and may be deemed to beneficially own the shares of Class B Common Stock held of record by Aggregator. KKR Group Assets Holdings III L.P. and KKR Financial Holdings LLC are the controlling members of KKR Upstream Associates LLC. KKR Group Assets III GP LLC is the general partner of KKR Group Assets Holdings III L.P. KKR Group Partnership L.P. is the sole member of each of KKR Group Assets III GP LLC and KKR Financial Holdings LLC. KKR Group Holdings Corp. is the general partner of KKR Group Partnership L.P. KKR & Co. Inc. is the sole stockholder of KKR Group Holdings Corp. KKR Management LLP is the Series I preferred stockholder of KKR & Co. Inc. Henry R. Kravis and George R. Roberts are the founding partners of KKR Management LLP. Each of such beneficial owners disclaims beneficial ownership of such securities in excess of their pecuniary interest therein.
(4)PT Independence is the direct beneficial owner of the securities reported. Liberty Holdco, a member of PT Independence, has the sole right to vote or dispose of the shares of Class B Common Stock and OpCo LLC Units held by PT Independence. Therefore, Liberty Holdco is deemed to have beneficial ownership of the shares of Class B Common Stock and OpCo LLC Units. The sole member of Liberty Holdco is LMI, which is wholly owned by Liberty Mutual Group Inc. The sole shareholder of Liberty Mutual Group Inc. is LMHC Massachusetts Holdings Inc., whose sole shareholder is Liberty Mutual Holding Company Inc. Because Liberty Mutual Holding Company Inc. is a mutual holding company, its members are entitled to vote at meetings of the company. No such member is entitled to cast 5% or more of the votes.
(5)Includes 28,622 shares of Class A Common Stock underlying RSU awards held by Erich Bobinsky and Bevin Brown granted in respect of service on our Board of Directors that will vest, subject to continued service on our Board, within 60 days of the date hereof. As described in the footnotes to the Director Compensation Table, Mr. Bobinsky and Ms. Brown have agreed to remit any shares of Class A Common Stock received as compensation for service on our Board of Directors to Liberty Holdco.
(6)The address of The Vanguard Group is 100 Vanguard Boulevard, Malvern, Pennsylvania 19355.
(7)The address of BlackRock, Inc. is 50 Hudson Yards, New York, New York 10001.
(8)The address of American Century Investment Management, Inc. is 4500 Main Street, 9th Floor, Kansas City, Missouri 64111.
(9)Includes 25,492 shares of Class A Common Stock underlying RSU awards granted as compensation in respect of service on our Board of Directors that will vest, subject to Mr. Goff's continued service on our Board, within 60 days of the date hereof. John C. Goff is the record holder of 714,357 shares of Class A Common Stock, and as the sole board member of The Goff Family Foundation, and the sole trustee of the Goff Family Trust, which is the managing member of GFT Strategies, LLC and the sole shareholder of Goff Capital, Inc. and JCG 2016 Management, LLC, he may be deemed to beneficially own the shares of Class A Common Stock held of record by those entities.
(10)Includes 14,311 shares of Class A Common Stock underlying RSU awards granted as compensation in respect of service on our Board of Directors that will vest, subject to continued service on our Board, within 60 days of the date hereof.
(11)Includes 13,000 shares of Class A Common Stock underlying RSU awards that will vest, subject to continued employment, within 60 days of the date hereof.
* less than 1%
Equity Compensation Plan Information
The following table provides information with respect to the shares of our Class A Common Stock that may be issued under our existing equity compensation plans as of December 31, 2024.
Plan Category
Number of shares of Class A Common Stock to be issued upon exercise of outstanding options, warrants and rights Weighted-average exercise price of outstanding options, warrants and rights (3)
Number of shares of Class A Common Stock remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(a) (b) (c)
Equity compensation plans approved by security holders
Crescent Energy Company 2021 Equity Incentive Plan
479,352 $- 5,505,452
Equity compensation plans not approved by shareholders
Crescent Energy Company 2021 Manager Incentive Plan (1)
9,271,644⁽²⁾ $- -
Total 9,750,996 $- 5,505,452
(1)The Manager Incentive Plan contains a formula for calculating the number of securities available for issuance under the Manager Incentive Plan. Pursuant to such formula, the total number of shares of our Class A Common Stock reserved for issuance under the Manager Incentive Plan is equal to the sum of (i) 4,306,745, plus (ii) on January 1 of each calendar year that occurs before the tenth anniversary of the effective date of the Manager Incentive Plan, 10% of the additional Class A Common Stock issued, if any, during the immediately preceding calendar year.
(2)The amount reported in this row represents the maximum number of shares issuable in respect of the Incentive Compensation. The exact number of shares of Class A Common Stock covered by the Incentive Compensation will not be determinable until the Incentive Compensation vests and is settled. However, the number of shares issuable in respect of the Incentive Compensation is limited by the number of shares available for issuance under the Manager Incentive Plan, which was equal to 9,271,644 as of December 31, 2024. If the performance goals applicable to the Incentive Compensation became earned at target performance as of December 31, 2024, 18,707,073 shares of Class A Common Stock would have become earned. If the Incentive Compensation became earned at a level in excess of the Class A Common Stock reserved for issuance under the Manager Incentive Plan, such excess would be settled in cash. For more information on the Incentive Compensation see the narrative disclosure following this table and the disclosure included elsewhere under the headings “Items 1 and 2. Business and Properties-Management Agreement.”
(3)All outstanding awards under the Manager Incentive Plan and the Equity Incentive Plan represent restricted stock units subject to time- or performance-based vesting, which do not have an exercise price.
Descriptions of the material terms of the Equity Incentive Plan and the Manager Incentive Plan are included herein under the heading “Item 11. Executive Compensation- Equity-Based Compensation,” which descriptions are incorporated to this Equity Compensation Plan Information disclosure by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
Policies and Procedures for Review of Related Party Transactions
A “Related Party Transaction” is a transaction, arrangement or relationship, or any series of similar transactions, arrangements or relationships, in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved will or may be expected to exceed $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:
•a person who is or was (since the beginning of the Company’s last completed fiscal year, even if they do not presently serve in that role) a director or director nominee of the Company;
•a person who is or was (since the beginning of the Company’s last completed fiscal year, even if they do not presently serve in that role) a senior officer of the Company, which, among others, includes each vice president and officer of the Company that is subject to reporting under Section 16 of the Exchange Act;
•any holder of the Company’s Series I Preferred Stock (a “Preferred Holder”);
•a greater than 5% beneficial owner of any class of the Company’s voting stock (a “5% Stockholder”);
•a person who is an immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law of a director, director nominee, senior officer or 5% Stockholder of Preferred Holder, and any person (other than a tenant or employee) sharing the household of the director, director nominee, senior officer or 5% Stockholder or Preferred Holder; or
•an entity that is owned or controlled by someone listed above, an entity in which someone listed above has a substantial ownership interest or control of the entity, or an entity which someone listed above is an executive officer or general partner, or holds a similar position.
Our Related Party Transactions Policy (the “RPT Policy”) was adopted by our Board of Directors in December 2021. The RPT Policy requires that, prior to entering into a Related Party Transaction, the Audit Committee shall review the material facts of the proposed transaction in advance. If advance Audit Committee review and approval of a Related Party Transaction is not feasible, then such Related Party Transaction will be reviewed and considered and, if the Audit Committee determines it to be appropriate and not inconsistent with the interests of the Company and its stockholders, ratified at the Audit Committee’s next regularly scheduled meeting. In determining whether to approve or ratify such a Related Party Transaction, the Audit Committee will take into account, among other factors it deems appropriate, (1) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances, (2) the extent of the Related Person’s interest in the transaction and (3) whether the Related Party Transaction is material to the Company.
Unless otherwise stated, each of the Related Party Transactions discussed below were authorized or consummated prior to our adoption of the RPT Policy.
Registration Rights Agreement
On December 7, 2021, the Company entered into a Registration Rights Agreement (the “2021 Registration Rights Agreement”) with holders associated with Independence’s former owners and John C. Goff (collectively, the “Holders”), relating to the registered resale of Class A Common Stock owned by such parties as of that date (the “Registrable Securities”). Under the 2021 Registration Rights Agreement, the Company has agreed to use its reasonable best efforts to obtain the effectiveness of a registration statement following its receipt of written request by a Holder of Registrable Securities. In January 2023, the Company registered the resale of 128,927,826 shares of our Class A Common Stock (including shares of Class A Common Stock to be issued upon redemption of a corresponding number of Class B Common Stock) by certain selling stockholders pursuant to the 2021 Registration Rights Agreement, which registration statement was amended in February 2025.
The Holders will also have “piggyback” registration rights exercisable at any time that allow them to include the shares of the Class A Common Stock that they own in certain registrations initiated by the Company or other holders of Class A Common Stock. Independence’s former owners also have customary rights to effect certain shelf take-downs, underwritten offering and block trades. The 2021 Registration Rights Agreement will terminate at such time as there are no Registrable Securities outstanding.
Management Agreement
Crescent Energy Company has a management agreement (the "Management Agreement") with KKR Energy Assets Manager LLC (the "Manager"). Pursuant to the Management Agreement, the Manager provides the Company with its senior executive management team and certain management services. The Management Agreement had an initial term of three years that began in 2021 and was automatically renewed in December 2024 for an additional three-year term ending December 7, 2027 and will have automatic three-year renewals thereafter, unless the Company or the Manager elects not to renew the Management Agreement.
As consideration for the services rendered pursuant to the Management Agreement and the Manager’s overhead, including compensation of the executive management team, the Manager is entitled to receive compensation from the Company equal to $51.3 million per annum ("Manager Compensation") (calculated based on the Company's pro rata relative ownership of OpCo multiplied by $69.4 million (the "Base Input"), which is included in General administrative expenses on our consolidated statements of operations. As the Company's business and assets expand, the Base Input will increase by an amount equal to 1.5% per annum of the net proceeds from all future issuances of our primary equity securities by the Company (including in connection with acquisitions) and increased by $14.0 million during the year ended December 31, 2024 in conjunction with the closing of the SilverBow Merger and December 2024 Equity Issuance. However, the Base Input will not increase from the issuance of the Company's shares upon the redemption or exchange of OpCo Units. See NOTE 3 - Acquisitions and Divestitures for more information. During the years ended December 31, 2024, we recorded general and administrative expense of $41.3 million and concurrently made cash distributions of $22.2 million to our redeemable noncontrolling interests. At December 31, 2024, we reduced redeemable noncontrolling interests by $4.5 million for the OpCo distribution declaration to redeemable noncontrolling interests that will be paid during the first quarter of 2025. At December 31, 2024, we had $17.4 million, included within Accounts payable - affiliates on the consolidated balance sheets for Crescent Energy Company's fee
associated with the Manager Compensation and cash distributions to be paid to our redeemable noncontrolling interests in the first quarter of 2025.
Additionally, the Manager is entitled to receive incentive compensation ("Incentive Compensation") under which the Manager is targeted to receive 10% of our outstanding Class A Common Stock based on the achievement of certain performance-based measures. The Incentive Compensation consists of five tranches that settle over a five-year period beginning in 2024, and each tranche relates to a target number of shares of Class A common stock equal to 2% of the outstanding Class A common stock as of the time such tranche is settled. So long as the Manager continuously provides services to us until the end of the performance period applicable to a tranche, the Manager is entitled to settlement of such tranche with respect to a number of shares of Class A common stock ranging from 0% to 4.8% of the outstanding Class A Common Stock at the time each tranche is settled. During the year ended December 31, 2024, we recorded general and administrative expense of $188.1 million related to the Incentive Compensation. 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 for more information.
KKR Funds
From time to time, we may invest in upstream oil and gas assets alongside EIGF II and/or other KKR funds ("KKR Funds") pursuant to the terms of the Management Agreement. In these instances, certain of our consolidated subsidiaries enter into Master Service Agreements ("MSA") with entities owned by KKR Funds, pursuant to which our subsidiaries provide certain services to such KKR Funds, including the allocation of the production and sale of oil, natural gas and NGLs, collection and disbursement of revenues, operating expenses and general and administrative expenses in the respective oil and natural gas properties, and the payment of all capital costs associated with the ongoing operations of the oil and natural gas assets. Our subsidiaries settle balances due to or due from KKR Funds on a quarterly basis. The administrative costs associated with these MSAs are allocated by us to KKR Funds based on (i) an actual basis for direct expenses we may incur on their behalf or (ii) an allocation of such charges between the various KKR Funds based on the estimated use of such services by each party. As of December 31, 2024, we had a related party receivable of $4.3 million included within Accounts receivable - affiliates and a related party payable of $1.2 million included within Accounts payable - affiliates on our consolidated balance sheets associated with KKR Funds transactions.
KKR Capital Markets LLC ("KCM")
We engage KCM, an affiliate of KKR Group, for capital market transactions including notes offerings, credit facility structuring and equity offerings. We paid $8.7 million in fees, discounts and commissions to KCM in connection with our debt and equity transactions during the year ended December 31, 2024.
Other Transactions
During the years ended December 31, 2024, 2023 and 2022, we made cash distributions of $32.5 million, $57.1 million and $97.0 million to our redeemable noncontrolling interests related to their pro rata share of cash distributions made to Crescent Energy Company to pay dividends and income taxes. In addition, during the years ended December 31, 2024, 2023 and 2022, we reimbursed KKR $2.4 million, $1.5 million and $1.8 million for costs incurred on our behalf. At December 31, 2024 we had $0.7 million accrued within Accounts payable - affiliates for reimbursable costs and distributions to our redeemable noncontrolling interests for their pro rata share of taxes which will be paid during the first quarter of 2025.
During the year ended December 31, 2023, we made cash distributions of $57.1 million to our redeemable noncontrolling interests related to their pro rata share of cash distributions made to Crescent Energy Company to pay dividends and income taxes. In addition, we reimburse KKR for any costs incurred on our behalf. At December 31, 2023, we had $1.3 million accrued within Accounts payable - affiliates for reimbursable costs and distributions to our redeemable noncontrolling interests for their pro rata share of taxes which was paid during the first quarter of 2024.
During the year ended December 31, 2023, we signed a ten-year office lease with an affiliate of Crescent Real Estate LLC. John C. Goff, the Chairman of our Board of Directors, is affiliated with Crescent Real Estate LLC. The terms of the lease provide for annual base rent of approximately $0.3 million, increasing over the term of the lease, and the payment by one of our subsidiaries of certain other customary expenses. In addition, the lease provides for reimbursement of our costs up to $1.1 million for tenant improvements, which we were reimbursed the full amount during the year ended December 31, 2024. In addition, during the year ended December 31, 2024 we entered into an amendment to the original lease agreement for additional office space. Under the amended agreement our annual base rent is $0.4 million increasing to $0.5 million over the life of the agreement. Upon lease commencement in April 2023, we recorded a $2.4 million right-of-use asset in Other assets, an
operating lease liability of $0.1 million in Other current liabilities and $2.3 million in Other liabilities on the consolidated balance sheets.
We may be required to fund certain workover costs, and we will be required to fund plugging and abandonment costs related to producing assets held by Chama, an Investment in equity affiliates on our consolidated balance sheets. During the year ended December 31, 2024, we funded $4.7 million to Chama associated with the plugging and abandonment costs.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
Our independent registered public accounting firm is Deloitte & Touche LLP, Houston, Texas, Auditor Firm ID: 34.
Aggregate fees for professional services rendered for the Company by Deloitte & Touche LLP for the years ended December 31, 2024 and 2023 are presented in the following table.
2024 2023
(in thousands)
Audit fees $ 3,330 $ 3,125
Audit-related fees 1,382 945
Tax fees 2,629 2,653
Total $ 7,341 $ 6,723
As presented in the preceding table, “Audit fees” represent amounts billed for each year in connection with (i) the annual audit of our consolidated financial statements filed on Form 10-K and related internal controls over financial reporting and (ii) the quarterly review of our consolidated financial statements filed on Form 10-Q. "Audit-related fees" represent amounts for services provided in connection with our statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters. We are prohibited from using Deloitte & Touche to perform general bookkeeping, human resources or management functions for us, and any other service not permitted by the PCAOB. "Tax fees" represent amounts for services rendered for tax compliance. All fees presented were approved by the Audit Committee in accordance with its pre-approval policy. We did not engage Deloitte & Touche to perform any other services for us during the last two years.
The Audit Committee has determined that Deloitte & Touche LLP is independent for purposes of providing external audit services to the Company.
Audit Committee Policy for Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services
The Audit Committee has adopted procedures for pre-approving all audit and non-audit services provided by its independent accounting firm. These procedures include reviewing fee estimates for audit services and permitted recurring non-audit services, and authorizing the Company to execute letter agreements setting forth such fees. Audit Committee approval is required for any services to be performed by the independent accounting firm that are not specified in the letter agreements. The Audit Committee has delegated approval authority to the chairman of the Audit Committee, but any exercises of such authority are reported to the Audit Committee at the next meeting.
Part IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, and Financial Statement Schedules
(a) Financial statements and financial statement schedules filed as part of this report are listed in the index included in "Part II., Item 8. Financial Statements and Supplementary Data" of this Annual Report. All valuation and qualifying accounts schedules have been omitted because they are either not material, not required, not applicable or the information required to be presented is included in our consolidated financial statements and related notes.
(b) Exhibits. The following is a list of exhibits required to be filed as a part of this Annual Report in Item 15(b).
Exhibit No. Description
2.1# Transaction Agreement, dated as of June 7, 2021, by and among Contango Oil & Gas Company, Independence Energy LLC, IE PubCo Inc., IE OpCo LLC, IE L Merger Sub LLC and IE C Merger Sub Inc. (incorporated by reference to Exhibit 2.1 to the Company's proxy statement/prospectus, filed with the Securities and Exchange Commission on October 8, 2021).
2.2# Membership Interest Purchase Agreement, dated as of February 15, 2022, by and between Verdun Oil Company II LLC and Javelin VentureCo, LLC, and Crescent Energy OpCo LLC, as guarantor (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 16, 2022).
2.3# Purchase and Sale Agreement, dated as of May 2, 2023, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 3, 2023).
2.4#
First Amendment to Purchase and Sale Agreement, dated as of July 3, 2023, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P. (incorporated by reference to Exhibit 2.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 2023 filed with the Securities and Exchange Commission on March 4, 2024).
2.5#
Second Amendment to Purchase and Sale Agreement, dated as of December 18, 2023, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P. (incorporated by reference to Exhibit 2.5 to the Company's Annual Report on Form 10-K for the year ended December 31, 2023 filed with the Securities and Exchange Commission on March 4, 2024).
2.6#
Third Amendment to Purchase and Sale Agreement, dated as of June 11, 2024, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P. (incorporated by reference to Exhibit 2.4 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 5, 2024).
2.7#
Fourth Amendment to Purchase and Sales Agreement, dated as of September 12, 2024, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P. (incorporated by reference to Exhibit 2.5 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2024).
2.8*#
Fifth Amendment to Purchase and Sales Agreement, dated as of October 30, 2024, by and among Mesquite Comanche Holdings, LLC, SN EF Maverick, LLC and Javelin EF L.P.
2.9#
Agreement and Plan of Merger, dated May 15, 2024, by and among Crescent Energy Company, Artemis Acquisition Holdings Inc., Artemis Merger Sub Inc., Artemis Merger Sub II LLC and SilverBow Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on May 16, 2024).
2.10#
Membership Interest Purchase Agreement, dated December 3, 2024, by and between Crescent Energy Finance LLC, Crescent Energy Company, Ridgemar Energy Operating, LLC and Ridgemar (Eagle Ford) LLC. (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2024).
3.1 Amended and Restated Certificate of Incorporation of Registrant (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
3.2 Amended and Restated By-Laws of Registrant (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
4.1 Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 9, 2022).
4.2 Voting Agreement, dated as of June 7, 2021, by and among John C. Goff, Independence Energy LLC and the signatories thereto (incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 9, 2022).
Exhibit No. Description
4.3 Indenture, dated as of May 6, 2021, among Crescent Energy Finance LLC (f/k/a Independence Energy Finance LLC), the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2022).
4.4 First Supplemental Indenture, dated as of January 14, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as successor to U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2022).
4.5 Second Supplemental Indenture, dated as of February 10, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 10, 2022).
4.6 Third Supplemental Indenture, dated as of April 1, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 10, 2022).
4.7 Fourth Supplemental Indenture, dated as of April 20, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 10, 2022).
4.8 Fifth Supplemental Indenture, dated as of October 12, 2022, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on November 9, 2022).
4.9 Sixth Supplemental Indenture, dated as of March 6, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 7, 2023).
4.10 Indenture, dated as of February 1, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on February 1, 2023).
4.11 First Supplemental Indenture, dated as of July 20, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 21, 2023).
4.12 Second Supplemental Indenture, dated as of September 12, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 12, 2023).
4.13 Third Supplemental Indenture, dated as of December 8, 2023, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 8, 2023).
4.14 Fourth Supplemental Indenture, dated as of September 3, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.14 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2024).
4.15*
Fifth Supplemental Indenture, dated as of November 7, 2024 among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee.
4.16 Indenture, dated as of March 26, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on March 28, 2024).
4.17 First Supplemental Indenture, dated as of September 3, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.16 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2024).
4.18 Second Supplemental Indenture, dated as of November 7, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 13 2024).
Exhibit No. Description
4.19 Third Supplemental Indenture, dated as of December 11, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 13 2024).
4.20 Indenture, dated as of June 14, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 18, 2024).
4.21 First Supplemental Indenture, dated as of September 3, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 9, 2024).
4.22 Second Supplemental Indenture, dated as of September 9, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 9, 2024).
4.23*
Third Supplemental Indenture, dated as of November 7, 2024, among Crescent Energy Finance LLC, the guarantors named therein, and U.S. Bank Trust Company, National Association, as trustee.
10.1 Registration Rights Agreement, dated as of December 7, 2021, by and among Crescent Energy Company and each of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.2 Amended & Restated Limited Liability Company Agreement of Crescent Energy OpCo LLC (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.3 Management Agreement, dated as of December 7, 2021, by and among Crescent Energy Company and KKR Energy Assets Manager LLC (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.4 First Amendment to Management Agreement, dated May 15, 2024, by and between Crescent Energy Company and KKR Energy Assets Manager LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on May 16, 2024).
10.5 Second Amendment to Management Agreement, dated December 3, 2024, by and between Crescent Energy Company and KKR Energy Assets Manager LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 3, 2024).
10.6 Specified Rights Agreement, dated as of June 7, 2021, by and among PT Independence Energy Holdings LLC and Independence Energy Aggregator GP LLC (incorporated by reference to Exhibit 10.1 to the Company’s Registration Statement on Form S-4, filed with the Securities and Exchange Commission on October 8, 2021).
10.7† Crescent Energy Company 2021 Manager Incentive Plan (incorporated by reference to Exhibit 10.5 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 9, 2022).
10.8†
Form of Manager Incentive Plan Award (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.9†
Crescent Energy Company 2021 Equity Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.10†
First Amendment to the Crescent Energy Company 2021 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 12, 2023).
10.11†
Second Amendment to the Crescent Energy Company 2021 Equity Incentive Plan (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2024).
10.12†
Form of Equity Incentive Plan RSU Agreement - Director Form (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on August 9, 2022).
10.13†
Form of Equity Incentive Plan RSU Agreement - Executive Form (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.14†
Form of Equity Incentive Plan PSU Agreement (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.15† Indemnification Agreement (David C. Rockecharlie) (incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
Exhibit No. Description
10.16† Indemnification Agreement (Brandi Kendall) (incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.17† Indemnification Agreement (Todd Falk) (incorporated by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.18† Indemnification Agreement (Clay Rynd) (incorporated by reference to Exhibit 10.14 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.19† Indemnification Agreement (Robert G. Gwin) (incorporated by reference to Exhibit 10.15 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.20† Indemnification Agreement (Claire S. Farley) (incorporated by reference to Exhibit 10.16 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.21† Indemnification Agreement (Erich Bobinsky) (incorporated by reference to Exhibit 10.17 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.22† Indemnification Agreement (Bevin Brown) (incorporated by reference to Exhibit 10.18 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.23† Indemnification Agreement (Karen J. Simon) (incorporated by reference to Exhibit 10.19 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.24†
Indemnification Agreement (Ellis L. McCain) (incorporated by reference to Exhibit 10.20 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.25†
Indemnification Agreement (John C. Goff) (incorporated by reference to Exhibit 10.21 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 7, 2021).
10.26†
Indemnification Agreement (Bo Shi) (incorporated by reference to Exhibit 10.22 the Company’s Registration Statement on Form S-1, filed with the Securities and Exchange Commission on April 8, 2022).
10.27†
Indemnification Agreement (Marcus C. Rowland) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 2, 2024).
10.28†
Indemnification Agreement (Michael Duginski) (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 2, 2024).
10.29 Credit Agreement, dated as of May 6, 2021, among Independence Energy Finance LLC, Wells Fargo, National Association, JP Morgan Chase Bank, N.A. and the lender parties thereto (Incorporated by reference to Exhibit 10.22 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 9, 2022).
10.30
First Amendment to Credit Agreement, dated as of September 24, 2021, among Independence Energy Finance LLC, Wells Fargo, National Association, and the lender parties thereto (Incorporated by reference to Exhibit 10.23 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 9, 2022).
10.31
Second Amendment to Credit Agreement, dated March 30, 2022, by and among Crescent Energy Company, certain subsidiaries of Crescent Energy Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on April 8, 2022).
10.32
Third Amendment to Credit Agreement, dated March 30, 2022, by and among Crescent Energy Company, certain subsidiaries of Crescent Energy Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on April 8, 2022).
10.33
Fourth Amendment to Credit Agreement, dated as of September 23, 2022, among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Company, as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on September 29, 2022).
10.34
Fifth Amendment to Credit Agreement, dated July 3, 2023, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 10, 2023).
10.35
Sixth Amendment to Credit Agreement, dated December 13, 2023, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on From 8-K, filed with the Securities and Exchange Commission on December 13, 2023).
Exhibit No. Description
10.36
Seventh Amendment to Credit Agreement, dated April 10, 2024, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on April 12, 2024).
10.37
Eighth Amendment to Credit Agreement, dated May 24, 2024, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on May 30, 2024).
10.38
Ninth Amendment to Credit Agreement, dated June 14, 2024, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on June 18, 2024).
10.39
Tenth Amendment to Credit Agreement, dated July 30, 2024, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on August 2, 2024).
10.40
Eleventh Amendment to Credit Agreement, dated December 17, 2024, by and among Crescent Energy Finance LLC, certain subsidiaries of Crescent Energy Finance LLC, as guarantors, Wells Fargo Bank, National Association, as administrative agent, collateral agent and a letter of credit issuer, and the other lenders and letter of credit issuers party thereto (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on December 20, 2024).
10.41
Form of Voting and Support Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, filed with Securities and Exchange Commission on May 16, 2024).
10.42†
Second Amendment to the Crescent Energy Company 2021 Equity Incentive Plan (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2024).
19.1*
Crescent Energy Company Insider Trading Policy
21.1* Subsidiaries of the Company.
23.1* Consent of Deloitte & Touche LLP.
23.2* Consent of Ryder Scott Company, LP.
31.1* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1** Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
97.1 Crescent Energy Company Clawback Policy (incorporated by reference to Exhibit 97.1 to the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 4, 2024).
99.1*
Report of Ryder Scott Company, LP.
101.INS** XBRL Instance Document.
101.SCH** XBRL Schema Document.
101.CAL** XBRL Calculation Linkbase Document.
101.LAB** XBRL Label Linkbase Document.
101.PRE** XBRL Presentation Linkbase Document.
101.DEF** XBRL Definition Linkbase Document.
104** Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
* Filed herewith
** These files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.
† Management contract or compensatory plan or agreement
# Certain annexes, schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby undertakes to furnish supplemental copies of any of the omitted annexes, schedules and exhibits upon request by the U.S. Securities and Exchange Commission.