Slides
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August 2026 Q2’26 Earnings Presentation
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C R E S C E N T E N E R G Y Disclaimer 2 The information in this presentation relates to Crescent Energy Company (the “Company,” “Crescent,” “we,” “us,” “our” or “CRG Y”) and contains information that includes or is based upon “forward -looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Ex change Act of 1934, as amended. All statements, other than statements of historical fact, included in this presentation, including statements regarding business, strategy, financial position, prospe cts, plans, objectives, forecasts and projections of the Company, are forward -looking statements. The words such as “estimate,” “budget,” “projection,” “would,” “project,” “predict,” “believe,” “expect,” “potent ial,” “should,” “could,” “may,” “plan,” “will,” “guidance,” “outlook,” “goal,” “future,” “assume,” “focus,” “work,” “commitment,” “approach,” “continue” and similar expressions are intended to identify forward -looking statements; however, forward-looking statements are not limited to statements that contain these words. The forward -looking statements contained herein are based on management’s current expectations and bel iefs concerning future events and their potential effect on the Company and involve known and unknown risks, uncertainties and assumptions, which may cause actual results to differ materially from results expressed or implied by the forward -looking statements. These risks include, among other things, our ability to integrate operations or realize any anticipated operational or corpor ate synergies and other benefits of our acquisitions, including the acquisition of Vital Energy, Inc. (the “Permian Acquisition”); the risk that the Permian Acquisition may not be accretive, and may be dilutive, to Crescent’s earnings per share, which may negatively affect the market price of Crescent common stock; our ability to identify and select opportunities for additional acquisitions, dispositions and other s trategic transactions; federal and state regulations and laws, including the One Big Beautiful Bill Act (the “OBBBA”), the Inflation Reduction Act of 2022 (“IRA 2022”) and any impact thereon by the OBBBA, IRA 2 022, taxes, tariffs and international trade, safety and the protection of the environment; general economic conditions, including the impact of inflation, elevated interest rates and associated changes i n monetary policy; the impact of central bank policy actions, including any changes in its policy priorities, and disruptions in the banking industry and capital markets; political and economic conditions and events in the U.S. and in foreign oil, natural gas and NGL producing countries, including embargoes, political and regulatory changes implemented by the Trump Administration, continued hostilities in the M iddle East, including the Israel -Hamas conflict and conflict with Iran, and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions and devel opments in South America and in China and acts of terrorism or sabotage; our ability to predict and manage the effects of actions of Organization of Petroleum Exporting Countries and its allies and agre ements to set and maintain production levels, including compliance with, changes to or departures from such arrangements, the effects of which may be exacerbated by the continued hostilities in the Middle East , including the conflict with Iran, and developments in Venezuela and other major oil-producing countries; and the severity and duration of public health crises and any resultant impact on governmental actions, commodity prices, supply and demand considerations, and storage capacity. The Company believes that all such expectations and beliefs are reasonable, but such expectations and beliefs may prove inacc urate. Many of these risks, uncertainties and assumptions are beyond the Company’s ability to control or predict. Because of these risks, uncertainties and assumptions, readers are cautioned not to, and should not, place undue reliance on these forward -looking statements. The Company does not give any assurance (1) that it will achieve its expectations or (2) as to any business strategies, earnings or revenue trends or future financial results. The forward -looking statements contained herein speak only as of the date of this presentation. Although the Company may from time to time voluntarily updat e its prior forward-looking statements, it disclaims any commitment to correct, revise or update any forward -looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. All subsequent written and oral forward -looking statements concerning the Company or other matters and attributable thereto or to any person acting on its behalf are express ly qualified in their entirety by the cautionary statements above. For further discussions of risks and uncertainties, you should refer to the Company’s filings with the U.S. Securities and Exchange Commi ssion (“SEC”) that are available on the SEC’s website at http://www.sec.gov, including the “Risk Factors” section of the Company’s most recent Annual Report on Form 10 -K and any subsequently filed Quarterl y Reports on Form 10-Q. This presentation provides disclosure of the Company’s proved reserves. Reserve engineering is a process of estimating underg round accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Unless otherwise indicated, reserve and PV -10 estimates shown herein are based on reserves reports as of December 31, 2025, prepared by the Company’s independent reserve engineer in accordance with applicable rules and guidelines of the SEC. SEC pricing was calculated using the simple average of the first -of-the-month commodity prices for 2025, adjusted for location and quality differentials, with consideration of known contractual price changes. This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted acco unting principles (“GAAP”). These measures include ( i) EBITDA, (ii) Adjusted EBITDAX, (iii) Free Cash Flow (“FCF”), (iv) Levered Free Cash Flow (“LFCF”), (v) Adjusted Recurring Cash G&A, (vi) Adjusted O perating Expense Excluding Production & Other Taxes (“Adj. Opex”), (vii) Net Leverage and (viii) PV-10. See the Appendix of this presentation for definitions and discussion of the Company’s non -GAAP metrics and reconciliations to the most comparable GAAP metrics. These non - GAAP financial measures are not measures of financial performance prepared or presented in accordance with GAAP and may exclu de items that are significant in understanding and assessing the Company’s financial results. Therefore, these measures should not be considered in isolation, and users of any such informati on should not place undue reliance thereon. The Company cannot reconcile forward-looking non-GAAP financial measures without unreasonable efforts. Forward -looking non-GAAP financial measures provided w ithout the most directly comparable GAAP financial measures may vary materially from the corresponding GAAP financial measures. This presentation contains information obtained from third parties, including ratings from credit ratings agencies such as St andard & Poor’s Financial Services LLC (S&P), Moody’s Investors Service, Inc. (Moody’s) and Fitch Ratings, Inc. (Fitch). Reproduction and distribution of third party content in any form is prohibited except with the prior written permission of the related third party. Third party content providers do not guarantee the accuracy, completeness, timeliness or availability of any information, including ratings, and are not responsible for any errors or omissions (negligent or otherwise), regardless of the cause, or for the results obtained from the use of such content. 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This presentation has been prepared by us and includes market data and other statistical information from sources we believe to be reliable, including independent industry publications, governmental publications or other published independent sources. Some data is also based on our good faith estimates, which are derived f rom our review of internal sources as well as the independent sources described above. Although we believe these sources are reliable, we have not independently verified the information and cannot guarante e its accuracy and completeness. We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our businesses. This presentation also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in thi s presentation may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, the ir rights or the right of the applicable licensor to these trademarks, service marks and trade names.
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C R E S C E N T E N E R G Y 3 Consistent Execution Across the Portfolio Outperformance on all key metrics; enhancing 2026 guidance Building Momentum in the Permian Improving asset performance and driving structural changes in cost structure; synergies continue to exceed expectations Delivering on Free Cash Flow Value Proposition Record FCF reinforcing our strongest position yet Q2’26 Recap: Delivering on Our Strategic Priorities Operational Momentum Continues to Enhance Long-Term Value #1 #2 #3
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C R E S C E N T E N E R G Y A Differentiated Energy Company Well Positioned for Continued Execution and Long-Term Value Creation 4 (1) PV-10 is a non-GAAP financial measure. For a reconciliation to the comparable GAAP measure, see Appendix. (2) Based on YE’25 reserves. YE’25 SEC pricing calculated using the simple average of the first -of-the-month commodity prices for 2025, adjusted for location and quality differentials, with consideration of known contractual price changes. The average benchmark prices per unit, before location and quality differen tial adjustments, used to calculate the related reserve category were $65.34 / bbl for oil and $3.39 / MMBtu for gas. (3) Dividend yield based on CRGY share price of $11.27 as of 7/24/26. CRGY Key Metrics Permian Eagle Ford Uinta CRGY Footprint Minerals ~335 (~64% Liquids) $7.5 / $8.6 $0.12 / sh (~4% Yield) Q2’26 Net Production (Mboe/d): PD / Total Proved PV-10 ($ BN)(1)(2): Current Quarterly Dividend(3): High-Quality, Scaled Assets • Leading positions across the Eagle Ford, Permian and Uinta • 12+ years of high-quality, low- breakeven inventory Disciplined Capital Allocator • Cash-on-cash investment returns • Consistent focus on maximizing free cash flow Proven Execution Model • Track record of buying assets and making them better • Integration expertise driving outsized synergy capture
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C R E S C E N T E N E R G Y Substantial Cash Flow Generation 335 Mboe/d / 140 Mbo/d 42% Oil / 64% Liquids CRGY Q2 Results: Record Quarter of Outperformance 5 $798 MM Adj. EBITDAX(1) $418 MM Levered FCF(1) (1) Non-GAAP financial measure. For a reconciliation to the comparable GAAP measure, see Appendix. (2) Any payment of future dividends is subject to Board approval and other factors. (3) Dividend yield based on CRGY share price of $11.27 as of 7/24/26. (4) Liquidity based on 6/30/26 CEF RBL Elected Commitment of $2.0 BN less amount drawn less outstanding letters of credit plus cash outstanding as of 6/30/26. Scaled & Stable Base Production Balance Sheet Strength Attractive Return of Capital $0.12/sh Fixed Quarterly Dividend(2) 4% Fixed Dividend Yield(3) ~$2.2 BN of Liquidity(4) ~6 Year WA Maturity
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C R E S C E N T E N E R G Y #1: Consistent Execution Across the Portfolio Q2 Outperformance Demonstrates Repeatable Value Proposition 6 (1) Non-GAAP measure. Adjusted operating expense, excluding production and other taxes includes lease and asset operating expense, w orkover expense, gathering, processing and transportation and midstream and other revenue net of expense. (2) Represents the midpoint of previously issued annual guidance. Q2 Results 2026 Guidance Midpoint(2) Outperformance Total Production (Mboe/d) ~335 ~328 +2% Oil Production (Mbo/d) ~140 ~134 +4% Adj. Opex(1) ($/Boe) ~$10.95 ~$12.00 (9%) • Q2 volumes ahead of previously issued FY’26 plan, led by oil production strength • Adj. Opex(1) ~9% below the 2026 guidance midpoint
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C R E S C E N T E N E R G Y #1: Enhancing Guidance on Stronger Operational Performance Higher Volumes and Structural Cost Improvements Drive Additional FCF 7 Note: Based on current commodity environment as of 7/24/26. All amounts are approximations based on currently available infor mation and estimates and are subject to change based on events and circumstances after the date hereof. Please see “Cautionary Statement Regarding Forward -Looking Information” on Slide 2. (1) Non-GAAP measure. Adjusted operating expense, excluding production and other taxes includes lease and asset operating expense, w orkover expense, gathering, processing and transportation and midstream and other revenue net of expense. (2) Development Capital excludes leasing activity (acquisitions). Prior Outlook Current Outlook Change vs. Prior Midpoint Total Production (Mboe/d) Oil Production (% of Total) 320 - 335 40% - 42% 327 - 335 40% - 42% +1% Adj. Opex(1) ($/Boe) $11.50 - $12.50 $11.00 - $12.00 (4%) Production Taxes (% of Commodity Revenue) 6.0% - 7.0% 5.0% - 6.0% (15%) Development Capital(2) ($ MM) $1,325 - $1,425 $1,325 - $1,425 -- • Raising total and oil production guidance on unchanged development capital following stronger-than-expected first-half performance • Structural operating improvements are lowering operating costs
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C R E S C E N T E N E R G Y #2: Building Momentum in the Permian 8 Same Assets. Better Performance. Lower Costs. More Free Cash Flow. 1 Stabilization Completed 2 Optimization In Progress 3 Transformation Upcoming At Announcement Q2 Update Long-Term Potential Synergy Target $90 - 100 MM $250 - $300 MM ~3x Well Costs Prior Operator Baseline ~20 - 25% Further Upside Operating Costs Prior Operator Baseline >10% Further Upside Free Cash Flow >20% 5-Year Accretion >50% 5-Year Accretion(1) Further Upside $190 MM captured to date (1) Updated accretion metrics based on underlying projections at acquisition announcement, adjusted for the midpoint of the lates t synergy target.
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C R E S C E N T E N E R G Y $277 $484 $310 $630 $856 ~$1,000 2021A 2022A 2023A 2024A 2025A 2026E 9 #3: Strong FCF Demonstrates the Value Proposition FCF Provides Flexibility To: ✓ Sustain a Strong, Fixed Dividend (4% Yield(5)) ✓ Accelerate Deleveraging ✓ Repurchase Shares(6) ✓ Fund Accretive M&A (1) Based on consensus estimates as of 7/24/26. Levered Free Cash Flow is a non-GAAP measure. For a reconciliation to the comparable GAAP measure, see Appendix. (2) Forward-looking, non-GAAP measure that cannot be quantitatively reconciled without unreasonable efforts on the Company. (3) Based on CRGY share price of $11.27 as of 7/24/26. (4) Based on consensus estimates as of 7/24/26. Peers include CHRD, CRC, MGY, MTDR, NOG, OVV, PR and SM. (5) Assumes $0.12 per share quarterly CRGY dividend. Dividend yield based on CRGY share price of $11.27 as of 7/24/26. (6) ~$336 MM of buyback authorization remaining as of 6/30/26. Record Quarterly Free Cash Flow Reinforces Crescent’s Financial Flexibility Substantial FCF Generation (Annual CRGY LFCF(1) - $ MM) ~$3.3 BN of 5-Yr Cumulative Free Cash Flow 2026E FCF Yield(2) CRGY(3) 25%+ Peer Median(4) 14%
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C R E S C E N T E N E R G Y 10 ✓ Optimizing Base Production • Workover and artificial lift optimization driving increased production Driving Capital Efficiency • >25% well cost reduction since 2023 • Lower costs continue to improve breakevens Expanding the Resource Opportunity Set • Strong Austin Chalk performance supports further economic inventory expansion 10 hCRGY Royalties CRGY Eagle Ford Acreage Q2 Operational Results(1) Net Production Mboe/d 169 % Oil 39% Capital Spend – $ MM $147 D&C Activity (Gross / Net) Spuds 26 / 16 TILs 16 / 12 Eagle Ford Quarterly Highlights: Premier Position with Commodity Flexibility & Significant Growth Opportunity ✓ (1) Does not include Crescent Royalties. Peer Leading Operations Driving Strong Returns and Consistent FCF ✓
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C R E S C E N T E N E R G Y ~$950 ~$850 ~$735 <$700 2023 Program 2024 Program 2025 Program Current ~1,700 ~1,900 ~2,200 ~2,400 2023 Program 2024 Program 2025 Program 2026 YTD ~20% ~60% ~75% ~90% 2023 Program 2024 Program 2025 Program 2026 YTD Increasing Simulfrac Utilization (% of gross wells) >4x Since 2023 DC&F Cost Reduction ($/ft) >25% Since 2023 11Note: Data includes all South Texas wells currently operated by CRGY. 2026 YTD data as of 6/30/26. Well costs reflect Drilling, Completions & Facilities costs. Completion Efficiency Gains (lateral ft/day) >40% Since 2023 Eagle Ford Quarterly Highlights: Capital Efficiencies Increasing Returns & Free Cash Flow Best-in-Class Execution Demonstrates the CRGY Playbook
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C R E S C E N T E N E R G Y Permian Quarterly Highlights: Scaled Position with Significant Synergy and Growth Opportunity 12 ✓ Synergy Outperformance • $190 MM captured to date; increased target by ~45% Structural Cost Improvements • Reduced LOE through field optimization and integration • Additional opportunity across workovers, artificial lift and field operations Increasing Economic Inventory • Initial well cost improvements lower breakevens • Delineation opportunities across the footprint ✓ Q2 Operational Results(1) Net Production Mboe/d 124 % Oil 42% Capital Spend – $ MM $104 D&C Activity (Gross / Net) Spuds 9 / 7 TILs 12 / 10 Permian Acreage Early Results Demonstrate Meaningful Progress with Significant Upside Remaining hCRGY ✓ (1) Does not include Crescent Royalties. Includes CRGY legacy conventional assets.
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C R E S C E N T E N E R G Y Updated Synergy Range ~3x Higher Than Initial Target 13 Incremental Synergies Driven By: Permian Quarterly Highlights: Synergies Exceeding Expectations Synergy Target $90 - $100 MM $190 MM $250 - $300 MM Initial Target Q1'26 Increase Current Target ~$190 MM captured to date 10-Year PV -10 % of Headline Purchase Price ~20% ~40% ~50% ✓ Operational Optimization • Workovers, field execution and D&C efficiencies Infrastructure Optimization • Facilities, compression and artificial lift Commercial Optimization • Marketing and supply chain ✓ ✓
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C R E S C E N T E N E R G Y Same Assets Performing Better Under CRGY Ownership LOE + Workover Optimization ($ MM) Prior Operator CRGY Permian Quarterly Highlights: Same Assets, Structurally Lower Operating Costs Improving Performance Demonstrates the Repeatability of the CRGY Operating Model Drivers of Improved Performance: 14 >10% lower LOE + workover vs. 2025 quarterly average$111 $99 2025 Quarterly Average 1H'26 Quarterly Average Field Optimization • Staffing, workflows and operating practices Production Enhancement • Workovers, artificial lift and proactive surveillance Commercial and Procurement • Vendor savings and standardized contracting ✓ ✓ ✓
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C R E S C E N T E N E R G Y Permian Quarterly Highlights: Positive Well Cost Trajectory is Improving Permian Positioning Improving Well Costs to Enhance Free Cash Flow and Reduce Breakevens 15 Delaware Well Costs(1) ($/ft) ~20% Savings (~$200/ft) vs. Prior Operator ~25% Savings (~$225/ft) vs. Prior Operator $723 $813 $815 $850 $862 $863 $879 $929 $972 $996 $1,050 PR EOG FANG CRGY APA OXY DVN COP SM MTDR Legacy VTLE $552 $596 $604 $614 $679 $692 $700 $739 $925 FANG OXY PR SM APA OVV CRGY COP Legacy VTLE Midland Well Costs(1) ($/ft) (1) Peer NTM-weighted well cost estimates based on Enverus 1Q26 Oil NAV Compass, published June 24, 2026. Legacy VTLE and CRGY DC&F well costs based on management’s internal data, with CRGY reflecting current AFE estimates.
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C R E S C E N T E N E R G Y Uinta Quarterly Highlights: HBP Asset Base with Substantial Stacked Resource Opportunity 16 ✓ Improving Base Production • Optimized workover and artificial lift programs Driving Down Well Costs; Improving Breakevens • ~20% YoY DC&F savings • Implementing simulfrac and remote frac operations Expanding the Economic Resource Base • Capitalizing on core Uteland Butte while actively delineating the stacked resource opportunity Q2 Operational Results Net Production Mboe/d 26 % Oil 54% Capital Spend – $ MM $28 D&C Activity (Gross / Net) Spuds 8 / 5 TILs 4 / 4 Uinta Acreage Best-in-Class Operational Execution Driving Increased Efficiencies hCRGY ✓ ✓
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C R E S C E N T E N E R G Y 17 Uinta Quarterly Highlights: Best-in-Class Execution Driving Lower Costs and Improved Returns Drilling Efficiencies (drilled ft/day) Simulfrac Utilization (% of gross TILs) Completion Efficiencies (lateral ft/day) Capital Savings (DC&F $/ft) ~1,300 ~1,600 2025 Program 2026 YTD 0% 100% 2025 Program 2026 YTD ~1,600 ~3,000 2025 Program 2026 YTD ~$950 <$800 2025 Program 2026 YTD Step-Change in Drilling, Completion and Capital Efficiency
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C R E S C E N T E N E R G Y EBITDA by Operator Production by Basin Eagle Ford ~60% DJ ~18% Appalachia ~13% Other ~10% COP ~31% CVX ~17%BP ~13% CRGY ~11% DVN ~11% Other ~17% Minerals Quarterly Highlights: High-Margin Cash Flow with Upside 18 Substantial Free Cash Flow with Exposure to Cost-Free Organic Growth Operational Results Q2 Net Production Mboe/d 13 % Oil 46% New Well Activity(2) Gross 182 Net - 100% NRI 4.2 Note: Based on current strip. Numbers may not sum due to rounding. (1) Run-rate amounts shown, assumes ownership of the acquired assets for FY 2026. (2) YTD estimate as of 6/30/26. Normalized to 10,000 ft laterals. ~13 Mboe/d(1) ~$200 MM(1) ✓ Strong, Stable Cash Flow • ~$200 MM of FY EBITDA(1) at current strip • No capital required to generate production Attractive Growth Profile • ~20% production CAGR since 2020 • ~45% EBITDA CAGR since 2020 Embedded Upside • World-class inventory concentrated under top-tier operators • Clear path to additional value ✓ ✓
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C R E S C E N T E N E R G Y (1) Liquidity based on 6/30/26 CEF RBL Elected Commitment of $2.0 BN less amount drawn less outstanding letters of credit plus cash outstanding as of 6/30/26. Liquidity does not give effect to borrowings drawn to fund the redemption of the 2029 notes in July 2026. (2) CRGY previous data represents weighted average interest expense as of 12/31/25. CRGY current data represents weighted average interest expense as of 6/30/26. Scale, Free Cash Flow and Deleveraging Support Upgrade Potential WA Interest Rate(2) Current vs. Previous 7.14% vs. 7.67% Total Liquidity(1) ~$2.2 BN Commitment to Balance Sheet Strength 19 ✓ Reducing Absolute Leverage • Redeemed remaining $259 MM of 2029 notes at par in July 2026 • Strong FCF supports continued deleveraging Maintaining Strong Liquidity & Flexibility • ~$2.2 BN of liquidity(1) • No near-term maturities Lowering Cost of Capital • Recent refinancings reduced weighted average interest expense by ~50 bps • Additional opportunity to further improve cost of capital ✓ ✓ WA Maturity ~6 years Strengthening Balance Sheet & Lowering Cost of Capital
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C R E S C E N T E N E R G Y 20 High-Quality Assets and Strong Free Cash Flow • Scaled positions in the Eagle Ford, Permian & Uinta • ~$1 BN of 2026E free cash flow(1) (25%+ yield(2)) ✓ ✓ ✓ Disciplined Capital Allocation • Focused on cash-on-cash returns • Clear priorities: balance sheet, dividend and opportunistic buybacks Repeatable Value Creation • Synergy and operational improvement • High-growth, high-margin minerals platform (1) Based on consensus estimates as of 7/24/26. 2026E Levered Free Cash Flow is a forward -looking, non-GAAP measure that cannot be quantitatively reconciled without unreasonable efforts on the Company. (2) Based on CRGY share price of $11.27 as of 7/24/26. Repeatable Operating and Investing Model Driving Outsized Value Creation Why CRGY: Execution, Free Cash Flow and Upside
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C R E S C E N T E N E R G Y Appendix
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C R E S C E N T E N E R G Y 22 Note: Based on current commodity environment as of 7/24/26. (1) Development Capital excludes leasing activity (acquisitions). (2) Non-GAAP measure. Adjusted operating expense excluding production and other taxes includes lease and asset operating expense, wo rkover expense, gathering, processing and transportation and midstream and other revenue net of expense. (3) Non-GAAP measure. G&A Expense, excluding non-cash equity-based compensation and transaction and nonrecurring expenses, and inclu ding cash distributions initiated by Manager Compensation. (4) Adjusted EBITDAX is a non-GAAP financial measure. For a reconciliation to the comparable GAAP measure, see Appendix. Enhanced 2026 Outlook Full Year 2026 Guidance February 2026 August 2026 Change in Midpoint Total Production (Mboe/d) 320 – 335 327 – 335 +1% % Oil (%) 40% – 42% 40% – 42% % Gas (%) 36% – 39% 36% – 38% (1%) Realized Prices (Oil % of WTI / Gas % of HHUB) Mid ~90% / 55% – 65% Mid/High ~90% / 40% – 50% Development Capital ($ MM)(1) $1,325 – $1,425 $1,325 – $1,425 Corporate Capital ($ MM) ~$30 ~$30 Adj. Opex Ex. Prod. & Other Taxes ($/Boe)(2) $11.50 – $12.50 $11.00 – $12.00 (4%) Production Taxes (% of Commodity Revenue) 6.0% – 7.0% 5.0% – 6.0% (15%) Adj. Recurring Cash G&A ($/boe)(3) $1.15 – $1.25 $1.15 – $1.25 Non-Recurring Transaction G&A ($ MM) ~$25 ~$25 Cash Taxes (% of Adj. EBITDAX)(4) -- -- Production Guidance Increased and Cost Guidance Improved with Development Capital Unchanged 2026 Outlook: Higher Production and Lower Cash Costs
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C R E S C E N T E N E R G Y 23 Note: Map and current ownership by operator based on Enverus operator shapefiles. Acreage shown excludes pro forma impact of announced transactions until such transactions have closed. Location counts as of year end 2025. (1) Low-risk locations include highest-confidence, line-of-sight development. Total represents 3P locations. (2) DC&F costs reflect leading edge expectations by area. Operated Central Southern Western Non-Op Net Acres ~240k ~100k ~165k ~25k Counties Live Oak, Atascosa, McMullen, La Salle, DeWitt, Lavaca, Frio Webb, La Salle, McMullen, Live Oak Dimmit, Webb, Maverick, La Salle Zavala, Frio, Atascosa, Avg. WI / NRI ~84% / ~65% ~86% / ~65% ~61% / ~45% ~22% / ~18% % Oil ~75% ~0% ~45% ~61% Gross Locations(1) Low-Risk ~420 ~120 ~250 ~40 Total ~505 ~200 ~405 ~90 DC&F $ / ft(2) ~$725 ~$850 ~$690 ~$800 ‘26 Avg. Lateral ~13,500’ ~13,500’ ~11,500’ ~11,000’ Takeaway Premium Gulf Coast pricing (MEH) Asset Detail Eagle Ford Asset Detail: Premier Position with Commodity Flexibility & Significant Growth Opportunity
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C R E S C E N T E N E R G Y 24 Note: Map and current ownership by operator based on Enverus operator shapefiles. Acreage shown excludes pro forma impact of announced transactions until such transactions have closed. Location counts as of year end 2025. (1) Based on internal management estimates. (2) Per Enverus as of year end 2025. Asset Detail Permian Asset Detail: Scaled Position with Significant Synergy and Growth Opportunity Delaware Midland Net Acres ~82k ~192k Counties Ward, Reeves, Winkler, Pecos Glasscock, Midland, Howard, Reagan, Upton, Crane, Borden, Sterling Avg. WI / NRI ~70% / ~55% ~85% / ~65% % Oil ~65% ~50% Gross Locations Low-Risk(1) ~160 ~230 Total(2) ~260 ~860 DC&F $ / ft ~$850 ~$700 ‘26 Avg. Lateral ~14,500’ ~14,500’ Takeaway Premium Gulf Coast pricing (MEH) Conventional Metrics do not include CRGY conventional assets
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C R E S C E N T E N E R G Y Uinta Asset Detail: HBP Asset Base with Substantial Stacked Resource Opportunity 25 Note: Map based on Enverus operator shapefiles. Location counts as of year end 2025. (1) Gross locations based on delineated formations only. Asset Detail Uinta Net Acres ~140k Counties Duchesne & Uintah Avg. WI / NRI ~85% / ~70% % Oil ~80% Gross Locations(1) ~650 DC&F $ / ft ~$800 ’26 Avg. Lateral ~10,000’ Takeaway High-value crude with secured capacity Inventory Upside Uinta Formations Peer Activity CRGY Garden Gulch ✓ Upper Douglas Creek ✓ Middle Douglas Creek ✓ Lower Douglas Creek ✓ Black Shale ✓ Castle Peak ✓ ✓ Castle Peak Lime ✓ Uteland Butte A ✓ ✓ Uteland Butte B ✓ ✓ Uteland Butte C ✓ ✓ Upper Wasatch 5 ✓ ✓ Lower Wasatch 5 ✓ ✓ Wasatch 4 ✓ Wasatch 3 ✓ Wasatch 2 - Wasatch 1 - Upper Flagstaff ✓ Middle Flagstaff - Lower Flagstaff - Current CRGY inventory estimates only include a portion of substantial resource opportunity
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C R E S C E N T E N E R G Y 26 Minerals Asset Detail: Scaled Footprint Under World-Class Operators with Consistent Development Activity Note: Combination of DSUs and tract level detail shown on maps. (1) Normalized to 1/8th. (2) Includes drilled uncompleted (“DUCs”), permitted and high-confidence undeveloped locations. Asset Detail Eagle Ford Rockies Appalachia Other Net Royalty Acres(1) ~46k ~13k ~38k 25k+ % Oil ~50% ~30% ~4% ~8% Key Operators CRGY / COP / DVN / BP CVX / SM EXE / REP / EOG Multiple Producing Wells Gross ~3,500 ~1,000 ~1,000 ~1,500 Net (100% NRI) ~60 ~20 ~6 ~25 High-Confidence Locations(2) Gross >1,800 ~200 ~600 ~600 Net (100% NRI) ~27 ~3 ~4 ~4 CRGY Minerals and Royalties Acreage CRGY Royalties O&G Basin Key Basin Eagle Ford Rockies Appalachia TX CO OH PA
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C R E S C E N T E N E R G Y Hedge Position: Liquids 27 Note: Hedge position as of 7/29/26. Includes hedge contracts beginning 7/1/26. (1) Extendible swaps and collars represent options that may be extended by the counterparty. Crescent Energy Finance Q3 2026 Q4 2026 FY 2027 NYMEX WTI (Bbls, $/Bbl) Swaps Total Daily Volumes 54,800 54,300 12,250 WA Swap Price $64.95 $64.91 $63.18 Collars Total Daily Volumes 22,500 21,500 11,000 WA Long Put Price $60.62 $60.47 $60.91 WA Short Call Price $73.72 $73.83 $75.20 Short Puts Total Daily Volumes 16,500 16,500 11,000 WA Short Put Price $48.00 $48.00 $47.66 Extendible Swaps(1) Total Daily Volumes -- -- 12,500 WA Swap Price -- -- $73.93 Extendible Collars(1) Total Daily Volumes -- -- 1,250 WA Short Put Price -- -- $45.00 WA Long Put Price -- -- $60.00 WA Short Call Price -- -- $70.00 ICE Brent Collars (Bbls, $/Bbl) Total Daily Volumes 500 500 -- WA Long Put Price $60.00 $60.00 -- WA Short Call Price $82.00 $82.00 -- MEH Basis Swaps (Bbls, $/Bbl) Total Daily Volumes 49,000 49,000 6,800 WA Swap Price $1.46 $1.46 $1.75 MidCush Basis Swaps (Bbls, $/Bbl) Total Daily Volumes 10,000 10,000 -- WA Swap Price $0.76 $0.76 -- CMA Roll Swaps (Bbls, $/Bbl) Total Daily Volumes 60,000 60,000 -- WA Swap Price $0.56 $0.56 -- Crescent Royalty Finance Q3 2026 Q4 2026 FY 2027 NYMEX WTI (Bbls, $/Bbl) Swaps Total Daily Volumes 2,800 2,800 2,800 WA Swap Price $59.02 $59.02 $59.02
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C R E S C E N T E N E R G Y Hedge Position: Gas 28 Note: Hedge position as of 7/29/26. Includes hedge contracts beginning 7/1/26. (1) Extendible swaps represent options that may be extended by the counterparty. Crescent Energy Finance Q3 2026 Q4 2026 FY 2027 NYMEX Henry Hub (MMBtu, $/MMBtu) Swaps Total Daily Volumes 230,000 225,000 -- WA Swap Price $3.90 $4.10 -- Collars Total Daily Volumes 110,000 110,000 -- WA Long Put Price $3.04 $3.04 -- WA Short Call Price $4.74 $4.74 -- Extendible Swaps(1) Total Daily Volumes -- -- 50,000 WA Swap Price -- -- $4.19 Waha Fixed Swaps (MMBtu, $/MMBtu) Total Daily Volumes 152,000 152,000 120,000 WA Swap Price $2.41 $2.41 $2.69 Waha Basis Swaps (MMBtu, $/MMBtu) Total Daily Volumes -- -- 40,000 WA Swap Price -- -- ($0.97) HSC Basis Swaps (MMBtu, $/MMBtu) Total Daily Volumes 270,000 270,000 210,000 WA Swap Price ($0.43) ($0.43) ($0.31) Crescent Royalty Finance Q3 2026 Q4 2026 FY 2027 NYMEX Henry Hub (MMBtu, $/MMBtu) Swaps Total Daily Volumes 20,000 20,000 20,000 WA Swap Price $4.21 $4.21 $4.21
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C R E S C E N T E N E R G Y Per Unit Performance – Total Consolidated 29 (1) The realized price presented above does not include $62.1 million, $17.0 million and $60.6 million received from the settleme nt of acquired oil, gas and NGL derivative contracts for the three months ended June 30, 2026, June 30, 2025 and March 31, 2026, respectively. Total average realized prices, after effects of derivatives settlements, would have been $40.56, $37.50 and $36.91/Boe for the three months ended June 30, 2026, June 30, 2025 and March 31, 2026, respectively. (2) Non-GAAP financial measure. Please see “Reconciliation of Non-GAAP Measures” on Slide 2 for discussion and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with GAAP. (3) Adjusted operating expense excluding production and other taxes includes lease and asset operating expense, workover expense, gatherin g, processing and transportation and midstream and other revenue net of expense. For the three months ended June 30, 2026 June 30, 2025 March 31, 2026 Total Consolidated Average daily net sales volumes: Oil (MBbls/d) 140 108 140 Natural gas (MMcf/d) 715 644 743 NGLs (MBbls/d) 76 48 77 Total (MBoe/d) 335 263 341 Average realized prices, before effects of derivative settlements: Oil ($/Bbl) $ 96.61 $ 61.47 $ 71.00 Natural gas ($/Mcf) 0.52 2.71 2.37 NGLs ($/Bbl) 18.67 22.59 18.05 Total ($/Boe) 45.63 35.96 38.39 Average realized prices, after effects of derivative settlements: Oil ($/Bbl) $ 73.33 $ 64.27 $ 63.75 Natural gas ($/Mcf) 1.74 2.60 2.23 NGLs ($/Bbl) 18.67 22.48 18.05 Total ($/Boe)(1) 38.52 36.79 34.93 Expense (per Boe) Operating expense $ 13.38 $ 16.31 $ 14.00 Depreciation, depletion and amortization 11.75 12.42 11.55 General and administrative expense 2.02 5.21 2.05 Non-GAAP and other expense (per Boe) Adjusted operating expense, excluding production and other taxes(2)(3) $ 10.95 $ 12.40 $ 11.98 Production and other taxes 2.27 2.30 1.82 Adjusted Recurring Cash G&A(2) 1.26 1.22 1.04
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C R E S C E N T E N E R G Y Per Unit Performance – Minerals and Royalties (CRF) 30 For the three months ended June 30, 2026 June 30, 2025 March 31, 2026 Minerals and royalties (CRF) Average daily net sales volumes: Oil (MBbls/d) 6 2 4 Natural gas (MMcf/d) 30 17 30 NGLs (MBbls/d) 2 1 2 Total (MBoe/d) 13 6 11 Average realized prices, before effects of derivative settlements: Oil ($/Bbl) $ 92.88 $ 66.51 $ 74.10 Natural gas ($/Mcf) 1.92 2.72 4.89 NGLs ($/Bbl) 27.13 23.25 22.95 Total ($/Boe) 51.45 34.95 44.57 Average realized prices, after effects of derivative settlements: Oil ($/Bbl) $ 77.45 $ 66.51 $ 65.02 Natural gas ($/Mcf) 2.80 2.72 4.40 NGLs ($/Bbl) 27.06 23.25 22.95 Total ($/Boe) 46.31 34.95 39.90 Expense (per Boe) Operating expense $ 4.26 $ 5.40 $ 4.23 Crescent presents certain operational results for CRF separately from the CEF operational results because we believe that it permits investors to better understand the performance of this aspect of our business.
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C R E S C E N T E N E R G Y Adjusted EBITDAX & Levered Free Cash Flow 31 Adjusted EBITDAX & Levered Free Cash Flow Crescent defines 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, Crescent further subtracts certain redeemable noncontrolling interest distributions made by OpCo and settlement of acquired derivative contracts. Crescent 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. Crescent believes Adjusted EBITDAX is a useful performance measure because it allows for an effective evaluation of its operating performance when compared against its peers, without regard to its financing methods, corporate form or capital structure. Crescent excludes the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially within its 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. Crescent’s presentation of Adjusted EBITDAX should not be construed as an inference that its results will be unaffected by unusual or nonrecurring items. Crescent’s 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. Crescent defines 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 Crescent’s management and external users of its financial statements, such as industry analysts, investors, lenders and rating agencies. Crescent believes Levered Free Cash Flow is a useful liquidity measure because it allows for an effective evaluation of its operating and financial performance and the ability of its 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. Crescent’s computations of Levered Free Cash Flow may not be comparable to other similarly titled measures of other companies. 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 measure, respectively, calculated in accordance with GAAP:
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C R E S C E N T E N E R G Y Adjusted EBITDAX & Levered Free Cash Flow (Cont’d) 32 (1) Transaction and nonrecurring expenses of $25.9 million for the three months ended June 30, 2026, were primarily related to ea rnout payments in connection with the Company's acquisition of certain Eagle Ford assets in January 2025 (the “January 2025 Eagle Ford Acquisition”), the Permian Acquisition transaction costs, divestiture and restructuring costs. Transaction and nonrecurring expense credits of $0.2 million for the three months ended June 30, 2025, were primarily related to uncapitalized transaction costs related to the January 2025 Eagle Ford Acquisition and transaction costs related to our divestitures and the July 2024 Eagle Ford Acquisition, parti ally offset by proceeds from a legal settlement. (2) Represents the settlement of certain oil, gas and NGL commodity derivative contracts acquired in connection with the Company' s acquisition of certain Eagle Ford assets in July 2024 and the Permian Acquisition. Three Months Ended June 30, 2026 2025 (in thousands) Net income (loss) $ 493,704 $ 162,498 Adjustments to reconcile to Adjusted EBITDAX: Interest expense 99,823 75,219 Loss from extinguishment of debt — — Income tax expense (benefit) 169,920 41,057 Depreciation, depletion and amortization 358,004 297,056 Exploration expense 366 5,574 Non-cash (gain) loss on derivatives (419,080) (178,592) Impairment expense — 2,985 Non-cash equity-based compensation expense 21,280 93,268 Gain on sale of assets (13,568) (1,910) Other (income) expense (471) (115) Certain RNCI Distributions made by OpCo — — Transaction and nonrecurring expenses(1) 25,893 (193) Settlement of acquired derivative contracts(2) 62,069 17,007 Adjusted EBITDAX (non-GAAP) $ 797,940 $ 513,854 Working interest and other Adjusted EBITDAX $ 748,524 $ 497,925 Minerals and royalties Adjusted EBITDAX $ 49,416 $ 15,929 Adjustments to reconcile to Levered Free Cash Flow: Interest expense, excluding non-cash amortization of deferred financing costs, discounts and premiums (95,576) (71,430) Loss from extinguishment of debt, excluding non-cash write-off of deferred financing costs, discounts and premiums — — Current income tax benefit (expense) (562) (6,673) Tax-related RNCI Distributions made by OpCo — (165) Development of oil and natural gas properties (284,124) (264,711) Levered Free Cash Flow (non-GAAP) $ 417,678 $ 170,875 Working interest and other Levered Free Cash Flow $ 373,536 $ 154,891 Minerals and royalties Levered Free Cash Flow $ 44,142 $ 15,984
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C R E S C E N T E N E R G Y Net Leverage & PV-10 Reconciliation 33 (1) Includes $60.3 million, $40.1 million and $1.6 million of unamortized discount, premium and issuance costs for total consolidated, CEF and CRF, respectively. (2) Total consolidated debt includes CEF, CRF and corporate-level items (including the 2.75% convertible notes due 2031) and does no t equal the sum of CEF and CRF. (3) During the initial covenant periods until December 31, 2026, Net Leverage for CRF Credit Facility is calculated on an annuali zed basis. Net Leverage Crescent defines Net Leverage as the ratio of consolidated total debt to consolidated Adjusted EBITDAX as calculated under the credit agreements (collectively, the "Credit Agreements") governing the Revolving Credit Facility and CRF Credit Facility, as applicable. Management believes Net Leverage is a useful measurement because it takes into account the impact of acquisitions. For purposes of the Credit Agreements, (i) consolidated total debt is calculated as total principal amount of Senior Notes, net of unamortized discount, premium and issuance costs, plus borrowings on our Revolving Credit Facility or CRF Credit Facility, as applicable, and unreimbursed drawings under letters of credit, less cash and cash equivalents and (ii) consolidated Adjusted EBITDAX includes certain adjustments to account for EBITDAX contributions associated with acquisitions the Company has closed within the last twelve months. Adjusted EBITDAX is a non-GAAP financial measure. Standardized Measure Reconciliation to PV-10 (in millions) For the year ended December 31, 2025 Standardized measure of discounted future net cash flows $7,756 Present value of future income taxes discounted at 10% 877 Total Proved PV-10 at SEC Pricing $8,633 June 30, 2026 Total consolidated Working interest (CEF) Minerals and royalties (CRF)(3) (in millions) Total debt(1)(2) $ 5,166 $ 4,221 $ 274 Less: cash and cash equivalents (265) (256) (8) Net Debt $ 4,901 $ 3,965 $ 266 Adjusted EBITDAX for Leverage Ratio $ 3,137 $ 2,939 $ 198 Net Leverage 1.6x 1.3x 1.3x
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C R E S C E N T E N E R G Y Adjusted Recurring Cash G&A 34 (1) Transaction and nonrecurring expenses (G&A) of $1.9 million for the three months ended June 30, 2026, were primarily related to the Permian Acquisition transaction costs, divestiture and restructuring costs. Transaction and nonrecurring expenses of $1.8 million for the three months ended June 30, 2025, were primarily related to uncapitalized transaction costs related to the January 2025 Eagle Ford Acquisition and transaction costs related to the July 2024 Eagle Ford Acquisition. Adjusted Recurring Cash G&A Crescent defines Adjusted Recurring Cash G&A as general and administrative expense, excluding equity- based compensation and transaction and nonrecurring expenses, and including cash distributions initiated by Manager Compensation. We include “Certain RNCI 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. Management believes Adjusted Recurring Cash G&A is a useful performance measure because it excludes transaction and nonrecurring expenses and equity-based compensation and includes Manager Compensation as if 100% of OpCo were owned and managed by the Company to reflect consistent measures not impacted by the amount of OpCo’s ownership under management, facilitating the ability for investors to compare Crescent's cash G&A expense against peer companies. As discussed elsewhere, these adjustments are made to Adjusted EBITDAX and Levered Free Cash Flow for historical periods and periods for which we present guidance. Three Months Ended June 30, 2026 2025 (in thousands) General and administrative expense $ 61,494 $ 124,612 Less: Non-cash equity-based compensation expense (21,280) (93,268) Less: Transaction and nonrecurring expenses(1) (1,867) (1,769) Plus: Certain RNCI Distributions made by OpCo — — Adjusted Recurring Cash G&A $ 38,347 $ 29,575
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Stay Connected. IR@crescentenergyco.com 600 Travis Street Suite 7200 Houston, Texas 77002 (713) 332-7001 www.crescentenergyco.com