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Oil and Gas

Crescent Energy Co.

11/02/2026 | Press release | Distributed by Public on 11/02/2026 15:39

Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)

Management's Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") 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 Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2025 ("Annual Report"), our Quarterly Reports on Form 10-Q for the periods ended March 31, 2026 and June 30, 2026, as well as our unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2026 and 2025. 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 three and nine months ended September 30, 2026 and 2025. 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 Quarterly Report and in our 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. Unless otherwise stated or the context otherwise indicates, all references to "we," "us," "our," "Crescent" and the "Company" or similar expressions refer to Crescent Energy Company ("CEC") and its subsidiaries.

Business

Crescent is a differentiated U.S. energy company committed to delivering value through a disciplined, returns-driven growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines significant cash flow from stable production with deep, high-quality development inventory. Our activities are focused in the Eagle Ford, Permian and Uinta Basins, and we own minerals and royalty interests across premier U.S. oil and natural gas basins, primarily operated by large, well-capitalized companies, with a core focus in the Eagle Ford.

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 geopolitical events, such as 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. For example, the ongoing military conflict with Iran, which began in February 2026, has heightened geopolitical risk in key global energy markets and contributed to increased volatility in oil and gas commodity prices. The conflict has resulted in disruptions and constraints on maritime transit, supply chains, and energy infrastructure in the Middle East, including in and around the Strait of Hormuz, a critical choke point for global oil and liquefied natural gas shipments and may continue to escalate with its potential interrelationship with the armed conflict in Ukraine. These developments have led to elevated risk premiums in energy commodity prices and greater short-term price uncertainty, causing global crude oil prices to surpass $100 per Bbl at times. Commodity prices and broader market conditions have also been affected by developments in Venezuela, supply chain constraints, elevated interest rates, U.S. international trade and tariff policies and responses thereto and costs of capital and political and regulatory uncertainties. 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 and market responses to the announcement of certain tariff policies by the Trump Administration, has contributed to concerns of a potential recession in the United States that has created further volatility. For example, actions taken by OPEC+ with respect to production levels, and announcements of potential changes in such levels, including production adjustments during 2025 and the first three quarters of 2026, and changes in participation by member countries have contributed, and may continue to contribute, to volatility in commodity prices and in 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.

There were no impairment charges recognized during the three and nine months ended September 30, 2026. During the three and nine months ended September 30, 2025, we recorded an impairment expense of $73.5 million and $122.2 million, respectively, to write down the value of certain assets classified as held for sale to expected net proceeds. A decline in future

commodity prices or a decrease in estimates of oil and natural gas reserves for our 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 remained relatively stable through 2024, 2025 and thus far through 2026, after an extended period of elevation; however, the full impact of recent geopolitical actions (including the conflict with Iran) on inflation cannot be fully determined at this time. 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. Recently announced tariffs and any further tariffs may also increase our operating costs. Sustained levels of inflation and certain other market pressures caused the Federal Open Market Committee to raise the target range for the federal funds rate by 25 bps in September 2026. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated interest rates and inflation remain, 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, any subsequent monetary policy changes (including as a result of recent changes to the composition of the Federal Reserve's Board of Governors), 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-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" in our Annual Report.

Capital market and financing transactions

Senior Secured Term Loan

In October 2026, we completed the pricing and syndication of a $1.5 billion senior secured term loan facility (the "Term Loan B"). The Term Loan B will have a five-year term and bear interest at a secured overnight financing rate ("SOFR") plus 2.25%, and was priced at 99.5% of par. Funding is expected to occur concurrently with the closing of the Devon EF Assets Acquisition.

October 2026 Primary Offering

In October 2026, we conducted an underwritten public offering of 92.0 million shares of Class A Common Stock at a price to the public of $12.50 per share (not including underwriter discounts and commissions) (the "October 2026 Primary Offering"). This included 12.0 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.

Independence Energy Aggregator L.P. ("Aggregator"), the entity through which certain private investors in affiliated KKR Group entities hold their interests in us, participated in the October 2026 Primary Offering by purchasing 40.0 million shares of Class A Common Stock from the underwriters at the public offering price and on the same terms as the other shares of Class A Common Stock.

After deducting underwriting fees and expenses, we received net proceeds of approximately $1.1 billion (inclusive of the net proceeds from the underwriters' exercise of their option) from the October 2026 Primary Offering, with which we intend to fund a portion of the cash consideration for the Devon EF Assets Acquisition.

2031 Convertible Notes

In March 2026, we issued $690.0 million aggregate principal amount of 2.750% Convertible Senior Notes due 2031 (the "2031 Convertible Notes") at par. The 2031 Convertible Notes bear interest at an annual rate of 2.750%, which is payable on March 15 and September 15 of each year, beginning on September 15, 2026, and mature on March 15, 2031, unless earlier converted or redeemed or purchased by the Company. The net proceeds of the 2031 Convertible Notes were approximately $671.0 million after deducting the initial purchasers' discount and offering expenses. The net proceeds of the 2031 Convertible Notes were used in part to redeem all of our outstanding 2028 Notes (as defined below) as discussed below.

Prior to December 15, 2030, the 2031 Convertible Notes are convertible only in certain circumstances and during specified periods. Thereafter, they are convertible at the noteholders' election until shortly before the maturity date. Upon conversion, we may settle the conversions by paying or delivering, as applicable, in cash, shares of Class A Common Stock, or a combination thereof, at our election. The 2031 Convertible Notes have an initial conversion rate of 67.1456 shares of Class A Common Stock per each $1,000 principal amount, which represents an initial conversion price of approximately $14.89 per share of Class A Common Stock. In connection with the issuance of the 2031 Convertible Notes, we paid $56.6 million to enter into capped call transactions with certain financial institution counterparties designed to reduce potential dilution upon conversion of the 2031 Convertible Notes and/or offset cash payments in excess of the principal amount of the converted notes, in each case subject to the initial cap price of $22.48 per share of Class A Common Stock.

The 2031 Convertible Notes are the Company's senior, unsecured obligations and are (i) equal in right of payment with CEC's, as the issuer of the 2031 Convertible Notes, senior unsecured indebtedness; (ii) senior in right of payment to the issuer's indebtedness that is expressly subordinated to the 2031 Convertible Notes; and (iii) effectively subordinated to the issuer's secured indebtedness, to the extent of the value of the collateral securing that indebtedness. The 2031 Convertible Notes are not guaranteed by any of the Company's subsidiaries, and the Company's subsidiaries do not have any obligations under the 2031 Convertible Notes. Because the 2031 Convertible Notes are not guaranteed by any of the Company's subsidiaries, the 2031 Convertible Notes are structurally subordinated to all indebtedness and other liabilities, including the Revolving Credit Facility, the CRF Credit Facility (as defined below), other series of our Senior Notes, trade payables and (to the extent the Company is not a holder thereof) preferred equity, if any, of the Company's subsidiaries.

2028 Notes

At December 31, 2025, we had $500.0 million outstanding aggregate principal amount of 9.250% senior notes due 2028 (the "2028 Notes"). In March 2026, we redeemed all of the remaining 2028 Notes (the "2028 Notes Redemption"), at a price of 102.3125%. As a result of the 2028 Notes Redemption, we incurred a loss on the extinguishment of debt of approximately $17.0 million, including $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums.

2029 Notes

At December 31, 2025, we had $298.2 million outstanding aggregate principal amount of 7.750% senior notes due 2029 (the "2029 Notes"). In March 2026, we repurchased $39.1 million of our outstanding 2029 Notes in open market transactions, at an average price of 101.014%. As a result of the repurchases, we incurred a loss on the extinguishment of debt of approximately $0.4 million. In July 2026, we redeemed all of the remaining 2029 Notes (the "2029 Notes Redemption") at a redemption price equal to 100.000% of the outstanding principal amount, or $258.7 million, plus accrued and unpaid interest to, but excluding, the redemption date.

2030 Notes

At December 31, 2025, we had $302.4 million outstanding aggregate principal amount of 9.750% senior notes due 2030 (the "2030 Notes"). In September 2026, we repurchased $0.3 million of our outstanding 2030 Notes in an open market transaction, at a price of 104.874%.

Acquisitions and divestitures

Acquisitions

Devon EF Assets Acquisition

On October 8, 2026, we entered into a purchase and sale agreement (the "Devon EF Assets Acquisition Agreement"), pursuant to which we intend to acquire the Devon EF Assets for approximately $4.2 billion in cash. The purchase price will be subject to customary purchase price adjustments set forth in the Devon EF Assets Acquisition Agreement, including reductions for proceeds received from sales of hydrocarbons from the Devon EF Assets after the economic effective date of July 1, 2026. The Devon EF Assets Acquisition is expected to close in the fourth quarter of 2026 or early 2027, and the closing is subject to customary conditions, including, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

Vital Energy Merger

In December 2025, we consummated the Vital Energy Merger. In connection with the Vital Energy Merger, Crescent issued 73.3 million shares of Class A Common Stock and paid $3.7 million in cash to settle outstanding Vital equity awards. In connection with the closing of the Vital Energy Merger, we repaid outstanding borrowings of $890.0 million and terminated the Vital revolving credit facility. See Notes to condensed consolidated financial statements, NOTE 3 - Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for additional information.

Ridgemar Acquisition

On January 31, 2025, we acquired all of the outstanding equity interests in Ridgemar (Eagle Ford) LLC ("Ridgemar") for $807.2 million in cash and 5.5 million shares of our Class A Common Stock (the "Ridgemar Acquisition"). We accounted for the Ridgemar Acquisition as an asset acquisition. In addition, up to $170.0 million in contingent earn-out consideration may be paid in fiscal years 2026 and 2027 if quarterly NYMEX WTI prices of crude oil are above certain thresholds in 2026 and 2027 (collectively, the "Ridgemar Contingent Consideration"). See Notes to condensed consolidated financial statements, NOTE 3 - Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for additional information.

Other Acquisitions

Minerals Acquisitions

In February 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $309.9 million, including transaction costs and certain customary purchase price adjustments (the "February 2026 Minerals Acquisition").

In January 2026, we acquired a portfolio of mineral and royalty interests located in the Eagle Ford from unrelated third-parties for an aggregate consideration of approximately $47.9 million, including transaction costs and certain customary purchase price adjustments (the "January 2026 Minerals Acquisition" and together with the February 2026 Minerals Acquisition, the "2026 Minerals Acquisitions").

In July 2025, we acquired a portfolio of oil and natural gas mineral interests located in various U.S. oil and gas basins from an unrelated third-party for total cash consideration of approximately $67.9 million, including transaction costs and certain customary purchase price adjustments (the "2025 Minerals Acquisition" and collectively with the 2026 Minerals Acquisitions, the "Minerals Acquisitions").

Webb Gas Acquisition

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

Divestitures

During 2025, we sold non-core assets as part of our 2025 non-core asset divestiture program for total consideration in excess of $900.0 million. During the nine months ended September 30, 2026, we received $11.5 million in additional net cash proceeds and recorded a gain of $13.6 million as part of the customary purchase price adjustments.

Separately, during the nine months ended September 30, 2026, we sold additional non-core assets to unrelated third-party buyers for $17.3 million in aggregate net cash proceeds and recorded a gain of $3.2 million.

During the three and nine months ended September 30, 2025, we recorded an impairment expense of $73.5 million and $122.2 million, respectively, to write down the carrying value of the associated oil and natural gas properties to the estimated transaction price less cost to sell. In addition, we recorded a loss of $1.6 million and a gain of $11.1 million on the sale of such assets for the three and nine months ended September 30, 2025, respectively.

Crescent Royalty Company

In November 2026, the Company announced that Crescent Royalty Company, a wholly owned subsidiary of the Company ("Crescent Royalty"), confidentially submitted a draft Registration Statement on Form S-1 with the U.S. Securities and Exchange Commission for a proposed initial public offering ("IPO") of Crescent Royalty's common stock, to be created and issued in connection with the IPO. The IPO is subject to market and other conditions, the completion of the review process of the U.S. Securities and Exchange Commission and our Board of Directors' approval.

Stewardship

We seek to improve the 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 in 2025, following consecutive years on OGMP 2.0 Gold Standard pathway, we achieved the OGMP 2.0 Gold Standard Reporting designation 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 previously established a Sustainability Advisory Council, an outside council comprising leading experts 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 by reference in this Quarterly Report.

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, and related facilities, 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 2026 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, natural 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.

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 members of its executive management team and certain management services. The Management Agreement has a term of three years, with automatic three-year renewals, unless the Company or the Manager elects not to renew the Management Agreement. The current term 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 members of its executive management team, the Manager is entitled to receive compensation from the Company equal to $78.5 million per annum ("Manager Compensation"), as of September 30, 2026, which is included in General and administrative expenses on our condensed consolidated statements of operations. As the Company's business and assets expand, Manager Compensation 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). See NOTE 3 - Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report for more information.

Prior to the Corporate Simplification, the Manager Compensation was reduced proportionally by the percentage of OpCo Units held as redeemable noncontrolling interests, with such amount distributed concurrently to the holders of redeemable noncontrolling interests. This cash distribution to the holders of redeemable noncontrolling interests did not represent additional Manager Compensation; rather, it represented 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.

Additionally, the Manager is entitled to receive Incentive Compensation under which the Manager is targeted to receive Class A Common Stock based on the achievement of certain performance-based measures. Initially, the Incentive Compensation consisted of five tranches, each of which featured a separate three-year performance period and 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 (each, a "Target PSU"). The first two tranches have vested and were fully expensed as of December 31, 2025. 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. Accordingly, as our Class A Common Stock share count increases, the number of equity-classified Manager PSU target shares of our Class A Common Stock granted under the Crescent Energy Company 2021 Manager Incentive Plan increases.

In connection with the October 2026 Primary Offering, the Company entered into an amendment to the Management Agreement, pursuant to which the incremental Management Fee (as defined in the Management Agreement) related to the equity issuances pursuant to the October 2026 Primary Offering (including shares of our Class A Common Stock purchased by Aggregator and shares issued pursuant to the underwriters' option to purchase additional shares), shall be reduced by $3.0 million. Accordingly, the incremental Manager Compensation related to the shares issued in the October 2026 Primary Offering is approximately $13.8 million. Additionally, as a result of the increase in outstanding shares of Class A Common Stock from the issuance, the target shares of Class A Common Stock related to the Incentive Compensation increased. We will account for this increase in target shares as a change in estimate and expect to recognize additional expense of approximately $104.1 million in the fourth quarter of 2026.

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. Commodity prices 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:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Oil	78	%	72	%	81	%	70	%
Natural gas	12	%	17	%	9	%	19	%
NGLs	10	%	11	%	10	%	11	%

In addition, revenue from our midstream assets is supported by commercial agreements that have established minimum volume commitments. These midstream revenues, as well as revenue associated with crude oil blending, comprise the majority of our midstream and other revenue. Midstream and other revenue accounts for 4% or less of our total revenues for the three and nine months ended September 30, 2026 and 2025.

Production volumes sold

The following table presents historical sales volumes for our properties:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2026	2025	2026	2025
Total consolidated
Oil (MBbls)	12,334	9,455	37,615	28,417
Natural gas (MMcf)	65,884	58,026	197,766	175,552
NGLs (MBbls)	6,820	4,109	20,679	12,685
Total (MBoe)	30,135	23,235	91,255	70,361
Daily average (MBoe/d)	328	253	334	258
Working interest (CEF)
Oil (MBbls)	11,853	9,247	36,212	27,817
Natural gas (MMcf)	63,654	55,494	190,085	169,963
NGLs (MBbls)	6,620	4,010	20,094	12,365
Total (MBoe)	29,082	22,506	87,987	68,509
Daily average (MBoe/d)	317	245	322	251
Minerals and royalties (CRF)
Oil (MBbls)	481	208	1,403	600
Natural gas (MMcf)	2,230	2,532	7,681	5,589
NGLs (MBbls)	200	99	585	320
Total (MBoe)	1,053	729	3,268	1,852
Daily average (MBoe/d)	11	8	12	7

Total consolidated sales volumes increased 6,900 MBoe and increased 20,894 MBoe during the three and nine months ended September 30, 2026, respectively, compared to the three and nine months ended September 30, 2025. Our Working interest sales volumes increased 6,576 MBoe and increased 19,478 MBoe during the three and nine months ended September 30, 2026, respectively, primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. Our Minerals and royalties sales volumes increased 324 MBoe and increased 1,416 MBoe during the three and nine months ended September 30, 2026, respectively, due to our 2026 Minerals Acquisitions.

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 geopolitical events, such as developments in Venezuela, Russia's invasion of Ukraine and the associated sanctions imposed on Russia, the Israel-Hamas conflict and the broader conflict in the Middle East, including the conflict with Iran and the disruption of shipments of crude oil and liquefied natural gas through the

Strait of Hormuz, actions taken by OPEC+ and other major producing countries, sustained levels of inflation and related interest rate increases by the Federal Reserve and increased U.S. drilling activity or otherwise. Uncertainty persists regarding OPEC+'s actions, changes in participation by member countries, increased U.S. drilling, proposed tariffs, inflation and the armed conflicts in Ukraine and the Middle East, including with Iran, and the potential for related supply disruptions and impacts on global energy markets. Additionally, recessionary concerns and broader macroeconomic conditions 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:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Oil	60	%	60	%	65	%	58	%
Natural gas	50	%	57	%	53	%	58	%
NGLs	-	%	9	%	-	%	9	%

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Oil (Bbl):
Average NYMEX	$	85.79	$	64.93	$	83.50	$	66.70
Realized price (excluding derivative settlements)	84.52		63.07		84.08		63.99
Realized price (including derivative settlements) (1)	71.55		64.93		69.54		65.42
Natural Gas (Mcf):
Average NYMEX	$	2.95	$	3.07	$	3.63	$	3.39
Realized price (excluding derivative settlements)	2.35		2.49		1.75		2.80
Realized price (including derivative settlements) (1)	2.70		2.56		2.22		2.75
NGLs (Bbl):
Realized price (excluding derivative settlements)	$	20.58	$	22.53	$	19.09	$	23.52
Realized price (including derivative settlements) (1)	20.58		22.57		19.09		23.39

(1) The realized price presented above does not include $33.7 million or $156.3 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three and nine months ended September 30, 2026, respectively, and does not include $14.7 million or $49.6 million received from the settlement of acquired oil, gas and NGL derivative contracts for the three and nine months ended September 30, 2025, respectively.

Results of operations:

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025

Revenues

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


	Three Months Ended September 30,
	2026		2025		$ Change		% Change
Revenues (in thousands):
Oil	$	1,042,500	$	596,288	$	446,212	75	%
Natural gas	154,593		144,462		10,131		7	%
Natural gas liquids	140,345		92,589		47,756		52	%
Midstream and other	13,774		33,240		(19,466)		(59)	%
Total revenues	$	1,351,212	$	866,579	$	484,633	56	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	84.52	$	63.07	$	21.45	34	%
Natural gas ($/Mcf)	2.35		2.49		(0.14)		(6)	%
NGLs ($/Bbl)	20.58		22.53		(1.95)		(9)	%
Total ($/Boe)	44.38		35.87		8.51		24	%
Net sales volumes:
Oil (MBbls)	12,334		9,455		2,879		30	%
Natural gas (MMcf)	65,884		58,026		7,858		14	%
NGLs (MBbls)	6,820		4,109		2,711		66	%
Total (MBoe)	30,135		23,235		6,900		30	%
Average daily net sales volumes:
Oil (MBbls/d)	134		103		31		30	%
Natural gas (MMcf/d)	716		631		85		13	%
NGLs (MBbls/d)	74		45		29		64	%
Total (MBoe/d)	328		253		75		30	%

Oil revenue. Oil revenue increased $446.2 million, or 75%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025. This increase was driven by higher realized oil prices that resulted in an increase of $264.6 million (an increase of 34% per Bbl) and a $181.6 million increase from higher sales volume (31 MBbls/d, or 30%). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures. The increase in realized oil prices was due to higher index pricing and more favorable price differentials.

Natural gas revenue. Natural gas revenue increased $10.1 million, or 7%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025. This increase was driven by higher sales volume (85 MMcf/d, or 13%) that resulted in a $19.5 million increase, partially offset by lower natural gas prices that resulted in a decrease of $9.3 million (a decrease of 6% per Mcf). The increase in sales volumes was primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. The decrease in realized natural gas prices was due to lower index pricing.

NGL revenue. NGL revenue increased $47.8 million, or 52%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025. This increase was driven primarily by a $61.1 million increase from higher sales volume (29 MBbls/d, or 64%), partially offset by lower realized NGL prices that resulted in a decrease of $13.3 million (a decrease of 9% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures.

Midstream and other revenue. Midstream and other revenue decreased $19.5 million, or 59%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, driven primarily by our 2025 divestitures.

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:


	Three Months Ended September 30,
	2026		2025		$ Change		% Change
Expenses (in thousands):
Operating expense	$	434,193	$	386,883	$	47,310	12	%
Depreciation, depletion and amortization	374,895		298,450		76,445		26	%
Impairment of oil and natural gas properties	-		73,527		(73,527)		NM*
General and administrative expense	65,275		74,275		(9,000)		(12)	%
Other operating costs	(1,840)		2,643		(4,483)		NM*
Total expenses	$	872,523	$	835,778	$	36,745	4	%
Selected expenses per Boe:
Operating expense	$	14.41	$	16.65	$	(2.24)	(13)	%
Depreciation, depletion and amortization	12.44		12.84		(0.40)		(3)	%

* NM = Not meaningful.

Operating expense. Operating expense increased $47.3 million, or 12%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, driven primarily by the following factors:

(i)Lease and asset operating expense increased $42.3 million, or 23%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, and decreased $0.44 per Boe, or 5%, to $7.61 per Boe. This $42.3 million increase was driven primarily by higher production from the Vital Energy Merger, which was more than offset on a per Boe basis with the additional acquired volumes and 2025 divestitures.

(ii)Gathering, processing and transportation expense decreased $3.2 million, or 3%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, and decreased $1.03 per Boe, or 26%, to $2.99 per Boe. These per Boe decreases were driven primarily by the Vital Energy Merger and our 2025 divestitures.

(iii)Production and other taxes increased $23.0 million, or 41%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, and increased $0.21 per Boe, or 9%, to $2.60 per Boe. This increase was driven primarily by the additional production from the Vital Energy Merger and higher oil prices.

(iv)Workover expense increased $7.8 million, or 34%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, and increased $0.03 per Boe, or 3%, to $1.02 per Boe. This increase was primarily driven by the Vital Energy Merger.

(v)Midstream and other operating expense decreased $22.5 million, or 81%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, primarily due to our 2025 divestitures.

Depreciation, depletion and amortization. In the three months ended September 30, 2026, depreciation, depletion and amortization increased $76.4 million, or 26%, compared to the three months ended September 30, 2025, driven primarily by increased production from the Vital Energy Merger.

Impairment expense. During the three months ended September 30, 2025, we recorded an impairment of $73.5 million to write down the value of certain assets classified as held for sale to expected net proceeds. We did not recognize impairment expense during the three months ended September 30, 2026.

General and administrative expense. General and administrative expense decreased $9.0 million, or 12%, for the three months ended September 30, 2026, compared to the three months ended September 30, 2025. The decrease was driven by a decrease in

equity-based compensation expense of $1.3 million and $14.9 million lower in transaction and nonrecurring related expenses, partially offset by higher recurring General and administrative expense primarily due to an increase in Manager Compensation as a result of the Vital Energy Merger.


	Three Months Ended September 30,
	2026		2025		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	37,710	$	30,522	$	7,188	24	%
Transaction and nonrecurring expenses	4,708		19,643		(14,935)		(76)	%
Equity-based compensation	22,857		24,110		(1,253)		(5)	%
Total general and administrative expense	$	65,275	$	74,275	$	(9,000)	(12)	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	1.25	$	1.31	$	(0.06)	(5)	%
Transaction and nonrecurring expenses	0.16		0.85		(0.69)		(81)	%
Equity-based compensation	0.76		1.04		(0.28)		(27)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $4.5 million, compared to the three months ended September 30, 2025, primarily driven by $3.2 million higher exploration expense recognized during the three months ended September 30, 2026 and a $7.7 million change in the gain or loss from the sale of assets.

Interest expense. In the three months ended September 30, 2026, we incurred interest expense of $94.2 million, as compared to $72.6 million in the three months ended September 30, 2025, a 30% increase. This increase was driven primarily by higher average debt balances as a result of the Vital Energy Merger.

Loss on extinguishment of debt. During the three months ended September 30, 2026, we incurred a nominal amount of loss on the extinguishment of debt. During the three months ended September 30, 2025, we incurred a loss on extinguishment of debt of our 2028 Notes of $29.2 million related to $22.3 million premium for the tender offer for and the partial redemption of the 2028 Notes in July 2025 and $6.9 million related to the write-off of outstanding deferred finance costs related to the 2028 Notes.

Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and have derivative gains and losses related to our contingent earn-out consideration. Our loss on derivatives during the three months ended September 30, 2026 changed by $461.5 million, from a comparable gain during the three months ended September 30, 2025, primarily due to changes in commodity prices relative to our strike prices.

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 table presents a reconciliation 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:


	Three Months Ended September 30,
	2026		2025		$ Change		% Change
(in thousands, except percentages)
Net income (loss)	$	(591)	$	(10,269)	$	9,678	(94)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	94,214		72,629
Loss from extinguishment of debt	16		29,248
Income tax expense (benefit)	5,983		(4,032)
Depreciation, depletion and amortization	374,895		298,450
Exploration expense	4,225		1,002
Non-cash (gain) loss on derivatives	244,973		(33,859)
Impairment expense	-		73,527
Non-cash equity-based compensation expense	20,773		23,788
(Gain) loss on sale of assets	(6,065)		1,641
Other (income) expense	(26,427)		(209)
Transaction and nonrecurring expenses (1)	40,133		19,938
Settlement of acquired derivative contracts	33,700		14,685
Adjusted EBITDAX (non-GAAP)	$	785,829	$	486,539	$	299,290	62	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums	(89,956)		(69,009)
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums	(16)		(22,360)
Current income tax benefit (expense)	(3,113)		14,680
Tax-related redeemable noncontrolling interest distributions made by OpCo	-		(605)
Development of oil and natural gas properties	(326,090)		(204,778)
Levered Free Cash Flow (non-GAAP)	$	366,654	$	204,467	$	162,187	79	%

(1)Transaction and nonrecurring expenses of $40.1 million for the three months ended September 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, legal settlements, and divestiture and restructuring costs. Transaction and nonrecurring expenses of $19.9 million for the three months ended September 30, 2025 were primarily related to Vital Energy Merger costs, divestiture transactions and legal settlements.


	Three Months Ended September 30,
	2026		2025		$ Change		% Change
(in thousands, except percentages)
Net cash provided by operating activities	$	608,495	$	473,060	$	135,435	29	%
Changes in operating assets and liabilities	60,751		(74,015)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo	-		(605)
Transaction and nonrecurring expenses (1)	40,133		19,938
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums	(16)		(22,360)
Exploration expense	4,225		1,002
Other adjustments and operating activities	(20,844)		12,225
Development of oil and natural gas properties	(326,090)		(204,778)
Levered Free Cash Flow (non-GAAP)	$	366,654	$	204,467	$	162,187	79	%

Adjusted EBITDAX (non-GAAP) increased by $299.3 million, or 62%, in the three months ended September 30, 2026, compared to the three months ended September 30, 2025, primarily driven by additional production from the Vital Energy Merger and increased oil pricing.

Levered Free Cash Flow (non-GAAP) increased by $162.2 million, or 79%, in the three months ended September 30, 2026 compared to the three months ended September 30, 2025, primarily driven by increased Adjusted EBITDAX, partially offset by $121.3 million of increased development of oil and natural gas properties expenditures and additional interest expense.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025

Revenues

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


	Nine Months Ended September 30,
	2026		2025		$ Change		% Change
Revenues (in thousands):
Oil	$	3,162,646	$	1,818,435	$	1,344,211	74	%
Natural gas	346,734		490,903		(144,169)		(29)	%
Natural gas liquids	394,823		298,306		96,517		32	%
Midstream and other	24,793		107,091		(82,298)		(77)	%
Total revenues	$	3,928,996	$	2,714,735	$	1,214,261	45	%
Average realized prices, before effects of derivative settlements:
Oil ($/Bbl)	$	84.08	$	63.99	$	20.09	31	%
Natural gas ($/Mcf)	1.75		2.80		(1.05)		(38)	%
NGLs ($/Bbl)	19.09		23.52		(4.43)		(19)	%
Total ($/Boe)	42.78		37.06		5.72		15	%
Net sales volumes:
Oil (MBbls)	37,615		28,417		9,198		32	%
Natural gas (MMcf)	197,766		175,552		22,214		13	%
NGLs (MBbls)	20,679		12,685		7,994		63	%
Total (MBoe)	91,255		70,361		20,894		30	%
Average daily net sales volumes:
Oil (MBbls/d)	138		104		34		33	%
Natural gas (MMcf/d)	724		643		81		13	%
NGLs (MBbls/d)	76		46		30		65	%
Total (MBoe/d)	334		258		76		29	%

Oil revenue. Oil revenue increased $1.3 billion, or 74%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025. This increase was driven by a $588.6 million increase from higher sales volume (34 MBbls/d, or 33%), and higher realized oil prices that resulted in an increase of $755.6 million (an increase of 31% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures. The increase in realized oil prices was due to higher index pricing and more favorable price differentials.

Natural gas revenue. Natural gas revenue decreased $144.2 million, or 29%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025. The decrease was driven by lower natural gas prices that resulted in a decrease of $206.3 million (a decrease of 38% per Mcf), partially offset by a $62.1 million increase from higher sales volume (81 MMcf/d, or 13%). The increase in sales volumes was primarily due to the Vital Energy Merger, partially offset by our 2025 divestitures. The decrease in realized natural gas prices was due to a decrease in our price differentials due to the Vital Energy Merger and resulting differentials in the Permian Basin.

NGL revenue. NGL revenue increased $96.5 million, or 32%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025. This increase was driven primarily by a $188.0 million increase from higher sales volume (30 MBbls/d, or 65%), partially offset by lower realized NGL prices that resulted in a decrease of $91.5 million (a decrease of 19% per Bbl). The increase in sales volumes was primarily driven by the Vital Energy Merger, partially offset by our 2025 divestitures.

Midstream and other revenue. Midstream and other revenue decreased $82.3 million, or 77%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, driven primarily by our 2025 divestitures.

Expenses


	Nine Months Ended September 30,
	2026		2025		$ Change		% Change
Expenses (in thousands):
Operating expense	$	1,270,881	$	1,180,425	$	90,456	8	%
Depreciation, depletion and amortization	1,087,024		878,079		208,945		24	%
Impairment of oil and natural gas properties	-		122,159		(122,159)		NM*
General and administrative expense	189,569		255,657		(66,088)		(26)	%
Other operating costs	(5,645)		(4,249)		(1,396)		NM*
Total expenses	$	2,541,829	$	2,432,071	$	109,758	5	%
Selected expenses per Boe:
Operating expense	$	13.93	$	16.78	$	(2.85)	(17)	%
Depreciation, depletion and amortization	11.91		12.48		(0.57)		(5)	%

* NM = Not meaningful.

Operating expense. Operating expense increased $90.5 million, or 8%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, driven primarily by the following factors:

(i)Lease and asset operating expense increased $111.1 million, or 20%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, and decreased $0.60 per Boe, or 8%, to $7.35 per Boe. This $111.1 million increase was driven primarily by higher production from the Vital Energy Merger, which was more than offset on a per Boe basis with the additional acquired volumes and our 2025 divestitures.

(ii)Gathering, processing and transportation expense decreased $18.0 million, or 6%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, and decreased $1.19 per Boe, or 27%, to $3.14 per Boe. The decrease was driven primarily by the Vital Energy Merger and our 2025 divestitures.

(iii)Production and other taxes increased $32.2 million, or 19%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, and decreased $0.20 per Boe, or 8%, to $2.23 per Boe. This increase was driven primarily by production from the Vital Energy Merger and higher commodity prices, partially offset by our 2025 divestitures that were subject to higher production tax rates.

(iv)Workover expense increased $35.6 million, or 61%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, and increased $0.20 per Boe, or 24%, to $1.03 per Boe. This increase was primarily driven by the Vital Energy Merger.

(v)Midstream and other operating expense decreased $70.4 million, or 81%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, primarily due to our 2025 divestitures.

Depreciation, depletion and amortization. In the nine months ended September 30, 2026, depreciation, depletion and amortization increased $208.9 million, or 24%, compared to the nine months ended September 30, 2025, driven primarily by increased production from the Vital Energy Merger.

Impairment expense. During the nine months ended September 30, 2025, we recorded an impairment of $122.2 million to write down the value of certain assets classified as held for sale to expected net proceeds. We did not have impairment expense during the nine months ended September 30, 2026.

General and administrative expense. General and administrative expense decreased $66.1 million, or 26%, for the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025. The decrease was driven by a decrease in equity-based compensation expense of $75.5 million (2026 and 2025 include an additional true-up expense of $2.6 million and $77.9 million, respectively, due to changes in estimate) and $9.7 million lower in transaction and nonrecurring related expenses,

partially offset by higher recurring General and administrative expense primarily due to an increase in Manager Compensation as a result of the Vital Energy Merger.


	Nine Months Ended September 30,
	2026		2025		$ Change		% Change
General and administrative expense (in thousands):
Recurring general and administrative expense	$	106,702	$	87,609	$	19,093	22	%
Transaction and nonrecurring expenses	14,003		23,732		(9,729)		(41)	%
Equity-based compensation	68,864		144,316		(75,452)		(52)	%
Total general and administrative expense	$	189,569	$	255,657	$	(66,088)	(26)	%
General and administrative expense per Boe:
Recurring general and administrative expense	$	1.17	$	1.25	$	(0.08)	(6)	%
Transaction and nonrecurring expenses	0.15		0.34		(0.19)		(56)	%
Equity-based compensation	0.75		2.05		(1.30)		(63)	%

Other operating costs. Other operating costs include exploration expense and gain on sale of assets. Other operating costs decreased by $1.4 million, compared to the nine months ended September 30, 2025, primarily driven by a $5.6 million higher gain on sale of assets partially offset by $4.2 million higher exploration expense recognized during the nine months ended September 30, 2026.

Interest expense. In the nine months ended September 30, 2026, we incurred interest expense of $298.6 million, as compared to $221.0 million in the nine months ended September 30, 2025. This increase was driven primarily by higher average debt balances as a result of the Vital Energy Merger.

Loss on extinguishment of debt. During the nine months ended September 30, 2026, we incurred a loss on extinguishment of debt of $17.4 million related to $12.0 million premium for the 2028 Notes Redemption and our repurchases of the 2029 Notes, and $5.4 million related to the non-cash write-off of outstanding deferred financing costs, discounts, and premiums. During the nine months ended September 30, 2025, we incurred a loss on extinguishment of debt of our 2028 Notes of $29.2 million related to $22.3 million premium for the tender offer for and the partial redemption of the 2028 Notes in July 2025 and $6.9 million related to the write-off of outstanding deferred finance costs related to the 2028 Notes.

Gain (loss) on derivatives. We have entered into derivative contracts to manage our exposure to commodity price risks that impact our revenues and have derivative gains and losses related to our contingent earn-out consideration. Our loss on derivatives during the nine months ended September 30, 2026 changed by $1.1 billion, from a comparable gain during the nine months ended September 30, 2025, primarily due to changes in commodity prices relative to our strike prices.

Income tax benefit (expense). We are a corporation that is subject to U.S. federal and state income taxes on our allocable share of any taxable income from OpCo. OpCo is a partnership and is generally not subject to U.S. federal and certain state taxes. For the nine months ended September 30, 2026 and 2025, we recognized income tax expense of $93.6 million and income tax expense of $39.6 million, respectively, for an effective tax rate of 55.9% and 20.0%, respectively. Historically, our effective tax rate has typically been 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. However, as part of our Corporate Simplification, we expect our effective rate to be more in line with the U.S. federal statutory income tax rate plus our blended state income tax rate. Our effective tax rate for the nine months ended September 30, 2026 was higher than the statutory rate primarily due to the significant discrete items, including permanent differences recognized in connection with the Manager PSUs that vested during the nine months ended September 30, 2026.

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


	Nine Months Ended September 30,
	2026		2025		$ Change		% Change
(in thousands, except percentages)
Net income (loss)	$	73,937	$	158,143	$	(84,206)	(53)	%
Adjustments to reconcile to Adjusted EBITDAX:
Interest expense	298,611		221,029
Loss from extinguishment of debt	17,413		29,248
Income tax expense (benefit)	93,631		39,638
Depreciation, depletion and amortization	1,087,024		878,079
Exploration expense	11,110		6,882
Non-cash (gain) loss on derivatives	426,512		(132,221)
Impairment expense	-		122,159
Non-cash equity-based compensation expense	65,482		143,281
(Gain) loss on sale of assets	(16,755)		(11,131)
Other (income) expense	(26,571)		(440)
Certain redeemable noncontrolling interest distributions made by OpCo (1)	-		(4,242)
Transaction and nonrecurring expenses (2)	86,774		29,844
Settlement of acquired derivative contracts	156,332		49,580
Adjusted EBITDAX (non-GAAP)	$	2,273,500	$	1,529,849	$	743,651	49	%
Adjustments to reconcile to Levered Free Cash Flow:
Interest expense, excluding non-cash amortization of deferred financing costs, discounts, and premiums	(286,120)		(209,868)
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums	(11,979)		(22,360)
Current income tax benefit (expense)	(4,292)		(2,806)
Tax-related redeemable noncontrolling interest distributions made by OpCo	-		(865)
Development of oil and natural gas properties	(994,938)		(677,031)
Levered Free Cash Flow (non-GAAP)	$	976,171	$	616,919	$	359,252	58	%

(1)In our calculation of Adjusted EBITDAX and Levered Free Cash Flow, we reflected 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. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo.

(2)Transaction and nonrecurring expenses of $86.8 million for the nine months ended September 30, 2026 were primarily related to earn-out payments for the Ridgemar Acquisition, Vital Energy Merger transaction costs, capital market transactions, legal settlements, and divestiture and restructuring costs. Transaction and nonrecurring expenses of $29.8 million for the nine months ended September 30, 2025 were primarily related to Vital Energy Merger and Ridgemar Acquisition costs, transaction costs related to our divestitures and the SilverBow Merger and legal settlement costs.


	Nine Months Ended September 30,
	2026		2025		$ Change		% Change
(in thousands, except percentages)
Net cash provided by operating activities	$	1,724,474	$	1,309,140	$	415,334	32	%
Changes in operating assets and liabilities	168,308		(52,257)
Certain redeemable noncontrolling interest distributions made by OpCo (1)	-		(4,242)
Tax-related redeemable noncontrolling interest contributions (distributions) made by OpCo	-		(865)
Transaction and nonrecurring expenses (2)	86,774		29,844
Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts, and premiums	(11,979)		(22,360)
Exploration expense	11,110		6,882
Other adjustments and operating activities	(7,578)		27,808
Development of oil and natural gas properties	(994,938)		(677,031)
Levered Free Cash Flow (non-GAAP)	$	976,171	$	616,919	$	359,252	58	%

Adjusted EBITDAX (non-GAAP) increased by $743.7 million, or 49%, in the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025, primarily driven by additional production from the Vital Energy Merger and increased oil pricing.

Levered Free Cash Flow (non-GAAP) increased by $359.3 million, or 58%, in the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025, primarily driven by increased Adjusted EBITDAX, partially offset by $317.9 million of increased development of oil and natural gas properties expenditures and additional interest expense.

Liquidity and capital resources

Our primary sources of liquidity are cash on hand, cash flow from operations, proceeds from equity and debt offerings and borrowings under our senior secured reserve-based revolving credit agreements. Our primary expected uses of capital are for dividends to shareholders, our share repurchase program, debt repayment, including open market repurchases of our Senior Notes, development of our existing assets and acquisitions. For example, we intend to fund the cash consideration for the Devon EF Assets Acquisition, which is expected to close in the fourth quarter of 2026 or early 2027, using a combination of these liquidity sources, including proceeds from the October 2026 Primary Offering and the Term Loan B, with the remaining portion funded with proceeds from debt financings, cash on hand, availability under our Revolving Credit Facility (as defined below) or other capital markets offerings as appropriate.

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" section 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 efforts 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.

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


	September 30, 2026		December 31, 2025
	(in thousands)
Cash and cash equivalents	$	6,126	$	10,157
Long-term debt	4,717,703		5,524,128

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 described under the heading "Contractual obligations" in our Annual Report, 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:


	Nine Months Ended September 30,
	2026		2025
	(in thousands)
Net cash provided by operating activities	$	1,724,474	$	1,309,140
Net cash used in investing activities	(1,361,835)		(1,519,029)
Net cash provided by (used in) financing activities	(1,085,338)		(7,568)

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2026 increased by $415.3 million, or 32%, compared to the nine months ended September 30, 2025 primarily due to higher net income after adjusting for non-cash items.

Net cash used in investing activities. Net cash used in investing activities for the nine months ended September 30, 2026 decreased by $157.2 million, or 10%, compared to the nine months ended September 30, 2025, primarily due to $583.2 million lower acquisitions of oil and natural gas properties in 2026 partially offset by $328.5 million additional cash used in our development capital expenditures.

Net cash provided by (used in) financing activities. Net cash used in financing activities for the nine months ended September 30, 2026 was $1,085.3 million, primarily a result of net repayments of our long-term debt balances and our dividend payments. Net cash used in financing activities for the nine months ended September 30, 2025 was $7.6 million, primarily a result of our Class A Common Stock dividend, repurchases of Class A Common Stock and cash distributions to our redeemable noncontrolling interests; partially offset by net cash received in our debt transactions and Revolving Credit Facility borrowings.

Debt agreements

Senior Notes

2031 Convertible Notes

2028 Notes

2029 Notes

2030 Notes

Revolving Credit Facility

We are party to a reserve-based revolving credit facility (as amended, restated or otherwise modified to date, the "Revolving Credit Facility") with Wells Fargo Bank, National Association as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto. On May 18, 2026, we entered into the Fifteenth Amendment to the credit agreement governing our Revolving Credit Facility (the "CEF Credit Agreement"), pursuant to which, among other things, the maturity date was extended to May 19, 2031. The borrowing base under the Revolving Credit Facility was $3.5 billion and $3.9 billion as of September 30, 2026 and December 31, 2025, respectively. At September 30, 2026, our elected commitment amount was approximately $2.0 billion and we had no borrowings outstanding, $14.1 million in outstanding letters of credit and approximately $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 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 September 30, 2026 is 0.375% per year. Our weighted average interest rate on loan amounts outstanding as of December 31, 2025 was 5.56%. We had no borrowings outstanding under the Revolving Credit Facility at September 30, 2026.

At September 30, 2026, 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.

In connection with the Devon EF Assets Acquisition, in October 2026, we entered into the Sixteenth Amendment (the "CEF 16th CA Amendment") to the CEF Credit Agreement to provide flexibility for acquisition financing. Among other things, the CEF 16th CA Amendment (i) permits the consummation of the Devon EF Assets Acquisition, (ii) subject to customary terms and conditions, permits the incurrence of an up to $2.0 billion 364-day unsecured bridge credit facility in order to fund, among other things, a portion of the cash consideration for the Devon EF Assets Acquisition, (iii) subject to certain customary terms and conditions, permits the incurrence of term loan indebtedness that is secured on a pari passu basis with the obligations under the CEF Credit Agreement in an aggregate principal amount not to exceed an amount equal to the lesser of (I) the borrowing base minus the aggregate elected commitments minus the aggregate outstanding principal amount of all permitted pari passu indebtedness at such time and (II) an amount equal to 50.0% of the sum of (x) the aggregate elected commitments plus (y) the aggregate outstanding principal amount of all permitted pari passu indebtedness (after giving effect to the incurrence of any permitted pari passu indebtedness), and (iv) provides that the incurrence of up to $1.0 billion of certain additional indebtedness during the period beginning on May 18, 2026 and ending on the scheduled redetermination date for the April 1, 2027 scheduled 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 as such debt is incurred during such period and does not exceed the $1.0 billion aggregate threshold. The CEF 16th CA Amendment maintains the aggregate elected commitments at $2.0 billion.

Senior Secured Term Loan

In October 2026, we completed the pricing and syndication of the $1.5 billion Term Loan B. The Term Loan B will have a five-year term and an interest rate of SOFR plus 2.25%, and was priced at 99.5% of par. Funding is expected to occur concurrently with the closing of the Devon EF Assets Acquisition.

Crescent Royalty Finance Credit Facility

In February 2026, one of our subsidiaries, CRF, entered into a senior secured reserve-based revolving credit agreement with Wells Fargo Bank, National Association as administrative agent for the lenders and letter of credit issuer, and the lenders from time to time party thereto (the "CRF Credit Facility"). The CRF Credit Facility provides for a $1.0 billion aggregate maximum credit amount senior secured reserve-based revolving credit facility, with an initial borrowing base and aggregate elected commitment amount of $365.0 million consisting of $230.0 million under the revolving facility and a $135.0 million term loan ("CRF Term Loan"). As of September 30, 2026, following the repayment of the initial term loan facility, we had no borrowings outstanding under the CRF Term Loan. Revolving loans under the CRF Credit Facility mature on February 23, 2031, and initial term loans under the CRF Credit Facility mature on February 23, 2029. The borrowing base is subject to semi-annual scheduled redeterminations on or about April 1st and October 1st of each year. The next scheduled borrowing base redetermination is expected to be completed in November 2026, following the filing of this report.

The obligations under the CRF Credit Facility are secured by liens on collateral granted by CRF, as borrower, and the guarantors under the related security documents, including, without limitation, oil and gas properties and related assets, as-extracted collateral in the form of production and proceeds attributable to mortgaged properties, equity interests in restricted

subsidiaries owned by the borrower or subsidiary guarantors, certain indebtedness owed to the borrower or subsidiary guarantors, and deposit and securities accounts, in each case subject to permitted liens, excluded assets and other exceptions. The security documents include the security agreement, pledge agreement, mortgages, account control agreements and other instruments executed to secure or perfect the obligations under the facility. In connection with each redetermination of the borrowing base, the borrower must maintain mortgages on properties sufficient to satisfy the collateral coverage minimum, which requires that mortgaged properties represent at least 85% of the PV-9 of the credit parties' total proved reserves included in the initial reserve report and, thereafter, the most recent reserve report. The borrower's domestic subsidiaries are required to be guarantors under the CRF Credit Facility, subject to certain exceptions.

Interest

Borrowings under the CRF 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 SOFR, plus an applicable margin or (ii) SOFR, plus an applicable margin, at the election of CRF. The applicable margin and fee payable for the unused revolving commitments varies based upon CRF's borrowing base utilization then in effect. The weighted average interest rate on the CRF Credit Facility amount outstanding as of September 30, 2026 was 6.825%.

Covenants

The CRF Credit Facility contains certain covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity and commodity swap agreements, liens and other transactions without 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, beginning with the fiscal quarter ending on June 30, 2026. The CRF 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. As of September 30, 2026, we were in compliance with each of the covenants under the CRF Credit Facility and expect to remain in compliance with these covenants for the foreseeable future.

Capital expenditures

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

We expect to fund our 2026 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 the 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:


	Nine Months Ended September 30,
	2026		2025
	(in thousands)
Total development of oil and natural gas properties	$	994,938	$	677,031
Change in accruals or other non-cash adjustments	24,889		14,342
Cash used in development of oil and natural gas properties	1,019,827		691,373
Cash used in acquisition of oil and natural gas properties	359,233		942,465
Non-cash acquisition of oil and natural gas properties	6,951		82,145
Total expenditures on acquisition and development of oil and natural gas properties	$	1,386,011	$	1,715,983

Our cash used in the development of oil and natural gas properties was higher during the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025. The increase is related to an increase in our operations. We used cash of $359.2 million in the nine months ended September 30, 2026 for the acquisition of oil and natural gas properties, primarily related to the 2026 Minerals Acquisitions, as compared to $942.5 million in 2025 for the acquisition of oil and natural gas properties, primarily related to the Ridgemar Acquisition and the Minerals Acquisitions (see Notes to condensed consolidated financial statements, NOTE 3 - Acquisitions and Divestitures included in Part I. Item 1. Financial Statements of this Quarterly Report).

Contractual obligations

As of September 30, 2026, there have been no material changes to the contractual obligations previously disclosed in our 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 Revolving Credit Facility and the indentures governing the Senior Notes.

We paid cash dividends of $0.36 per share of our Class A Common Stock to shareholders during the nine months ended September 30, 2026.

On November 2, 2026, 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 third quarter of 2026. The quarterly dividend is payable on November 30, 2026 to shareholders of record as of the close of business on November 16, 2026.

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 dividends on a quarterly basis.

Summarized Supplemental Subsidiary Financial Information (UNAUDITED)

CEC is a holding company that conducts substantially all of its business through its consolidated subsidiaries, including (i) OpCo, which is wholly owned by CEC, and (ii) Crescent Energy Finance LLC ("CEF") and Crescent Royalty Finance LLC ("CRF"), each of which is wholly owned by OpCo. OpCo has no material operations, cash flows, assets or liabilities other than its investments in CEF and CRF. The assets and liabilities of OpCo represent substantially all of our consolidated assets and liabilities, except for certain parent company items held by CEC such as current and deferred taxes, CEC's 2031 Convertible Notes (as defined within NOTE 7 - Debt), and certain liabilities under the Management Agreement (as defined within NOTE 11 - Related Party Transactions). Crescent's consolidated balance sheets and consolidated statement of operations are materially the same as CEF with the exception of the below information.

Selected Summarized Balance Sheet Information:


	As of
	September 30, 2026
	(in thousands)
Minerals and royalties (CRF)
Assets:
Current assets	$	46,735
Property and equipment, net	645,546
Other noncurrent assets	3,831
Liabilities:
Current liabilities	24,645
Long-term debt	82,020
Other liabilities	5,614
Equity:
Total equity	583,833

Other entities (CEF and CEC)
Debt:
CEF long-term debt	3,963,749
CEC long-term debt	671,934

Selected Summarized Statement of Operations:


	Three Months Ended		Nine Months Ended
	September 30, 2026
	(in thousands)
Minerals and royalties (CRF)
Revenues	$	54,956	$	162,034
Operating expense	3,524		12,925
Gain (loss) on derivatives	(18,580)		(33,285)
Interest expense	(2,694)		(10,959)
Net income (loss)	8,968		51,829

Critical accounting policies and estimates

This discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements. A complete list of our significant accounting policies is described in NOTE 2 - Summary of Significant Accounting Policies in our audited financial statements as of and for the year ended December 31, 2025 in our Annual Report. Refer also to "Critical accounting estimates" in Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report. There have been no changes to our significant accounting policies and critical accounting estimates as of September 30, 2026.

Non-GAAP financial measures

Our MD&A 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 to make our investment decisions. We believe that the presentation of these non-GAAP financial 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 adjust for certain redeemable noncontrolling interest distributions made by OpCo and settlement of acquired derivative contracts. We included "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. After giving effect to the Corporate Simplification, the Company owns 100% of outstanding OpCo Units and no longer makes distributions to the holders of redeemable noncontrolling interests in OpCo.

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, 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 condensed 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)" section above.

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