Slides
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Operational Execution; Enhancing Returns 2Q25 Results August 2025
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Forward-Looking Statements and Disclosures 2 Forward-Looking Statements and Cautionary Statements Certain statements in this presentation concerning future opportunities for Civitas, future financial performance and condition, guidance, and any other statements regarding Civitas’ future expectations, beliefs, plans, objectives, financial conditions, returns to shareholders, assumptions, or future events or performance that are not historical facts are “forward-looking” statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “probable,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “potential,” “may,” “might,” “anticipate,” “likely,” “plan,” “positioned,” “strategy,” and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. Specific forward-looking statements included in this presentation include statements regarding the Company’s plans and expectations with respect to future production, sales volumes, capital expenditures, cash operating expenses, drilling and completion activity, and achievement of the Company’s net debt and divestiture targets and the effects of such on the Company’s results of operations, financial position, growth opportunities, reserve estimates and competitive position. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve significant risks and uncertainties that could cause actual results to differ materially from those anticipated, including, but not limited to: future financial condition, results of operations, strategy and plans; declines or volatility in the prices we receive for our crude oil, natural gas, and NGLs; general economic conditions, whether internationally, nationally, or in the regional and local market areas in which we do business, including any future economic downturn, the impact of continued or further inflation, disruption in the financial markets, the imposition of tariffs or trade or other economic sanctions, political instability, and the availability of credit on acceptable terms; our ability to identify, select, and consummate possible additional acquisition and disposition opportunities; the effects of disruption of our operations or excess supply of crude oil and natural gas and other effects of world events, and actions taken by OPEC+ as it pertains to global supply and demand of, and prices for, crude oil, natural gas, and NGLs; the ability of our customers to meet their obligations to us; our access to capital on acceptable terms; our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions and to meet our capital allocation initiatives; the presence or recoverability of estimated crude oil and natural gas reserves and the actual future sales volume rates and associated costs; uncertainties associated with estimates of proved crude oil and natural gas reserves; changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs); environmental, health, and safety risks; seasonal weather conditions as well as severe weather and other natural events caused by climate change; lease stipulations; drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques; our ability to acquire adequate supplies of water for drilling and completion operations; availability of oilfield equipment, services, and personnel; exploration and development risks; operational interruption of centralized crude oil and natural gas processing facilities; competition in the crude oil and natural gas industry; management’s ability to execute our plans to meet our goals; our ability to attract and retain key members of our senior management and key technical employees; our ability to maintain effective internal controls; access to adequate gathering systems and pipeline take-away capacity; our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for crude oil, natural gas, and NGL we produce, and to sell the crude oil, natural gas, and NGL at market prices; costs and other risks associated with perfecting title for mineral rights in some of our properties; pandemics and other public health epidemics; political conditions in or affecting other producing countries, including conflicts or hostilities in or relating to the Middle East, South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage and the effects therefrom; and other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing. Additional information concerning other factors that could cause results to differ materially from those described above can be found under Item 1A. “Risk Factors” and “Management’s Discussion and Analysis” sections in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, subsequently filed Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other filings made with the Securities and Exchange Commission. All forward-looking statements speak only as of the date they are made and are based on information available at the time they were made. The Company assumes no obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. Disclaimer The common stock repurchase authorization referenced in this presentation permits Civitas to make repurchases on a discretionary basis as determined by the board of directors of Civitas (the “Board”) and by management, subject to market conditions, applicable legal requirements, available liquidity, compliance with the company's debt agreements and other appropriate factors. Acquisitions under this repurchase authorization are to be made through open market or privately negotiated transactions and may be made pursuant to plans entered into in accordance with Rule 10b5-1 and/or Rule 10b-18 of the Exchange Act. This repurchase authorization does not have a termination date, does not obligate Civitas to acquire any particular amount of common stock, and may be modified, extended, suspended or discontinued at any time without prior notice. No assurance can be given that any particular amount of common stock will be repurchased. In addition, we may, at any time and from time to time, seek to repurchase and retire our outstanding senior notes through cash purchases and/or exchanges for debt in the open market, in privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, would be made upon the terms and at the prices as our Board and management may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The decision to pay any future dividends referenced in this presentation lies solely within the discretion of, and subject to approval by, the Board. The Board's determination with respect to any such dividends, including the record date, the payment date, and the actual amount of the dividend, will depend upon Civitas' profitability and financial condition, contractual restrictions, restrictions imposed by applicable law, and other factors that the Board deems relevant at the time of such determination. Additionally, covenants contained in Civitas' credit facility and the indentures governing its senior notes restrict the payment of cash dividends on shares of Civitas' common stock. No assurances can be given that any or any particular amount of dividends will be paid with respect to shares of Civitas' common stock. Non-GAAP Financial Measures To provide investors with additional information in connection with our results as determined in accordance with generally accepted accounting principles in the United States (“GAAP”), we disclose certain non-GAAP financial measures. The non-GAAP financial measures include Adjusted EBITDAX, Free Cash Flow (“FCF”), Cash G&A, Net Debt and related calculations. We believe the non-GAAP financial measures provide users of our financial information with additional meaningful comparisons between the current results and results of prior periods, as well as comparisons with peer companies. These non-GAAP financial measures are not measures of financial performance in accordance with GAAP and may exclude items that are significant in understanding and assessing our financial results. Therefore, these measures should not be considered in isolation or as an alternative or superior to GAAP measures. You should be aware that our presentation of these measures may not be comparable to similarly-titled measures used by other companies. Reconciliations of each non-GAAP financial measure to the applicable most comparable GAAP measure can be found in the Appendix section of this presentation.
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3 Key 2Q25 Messages Operating Results Outperformed Expectations in 2Q Beat on oil volumes, capital expenditures, and operating costs Cost Optimization and Capital Efficiency Initiative on Track 2025 savings impact of $40 MM; 2026 run-rate $100 MM Non-Core DJ Basin Asset Sales of $435 MM Exceeding YTD divestment goal at EBITDAX multiple >4x Reinstating Leading Capital Returns to Shareholders $750 MM buyback authorization; executing $250 MM ASR in 2025
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Decisive YTD Actions Strengthen Financial Position 4 Entered 2025 optimizing free cash flow with $150 MM reduction in capex Added 17 MMBbls of oil hedges YTD; currently hedged ~60% through end of 2025 with avg. floor of ~$67 per barrel WTI Extended debt maturities and reduced revolving credit facility borrowings with $750 MM unsecured bond Implemented $100 MM cost optimization and efficiency project, targeting sustainable improvements to capital and operating costs Signed $435 MM non-core asset divestments, accelerating value from DJ Basin 1 2 3 4 5 On track to achieve $4.5 Bn net debt target around YE25; reinstating buybacks
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5 Well Costs Reductions Delivered in All Basins Well costs (DC&E) $ per lateral foot Key Drivers: • Drilling, completion, facility design optimization • Delaware Basin efficiencies exceeding expectations due to BHA optimization, best practices from Midland ops • Midland and Delaware simulfrac throughput continues to increase • Local sand sourcing and real-time AI frac optimization in DJ Basin • Operational changes aimed toward minimizing time on pad (offline cementing, etc.) $1,000 $950 $880 $790 Delaware (7)% $850 $725 $685 $610 Midland (5)% $700 $670 $650 $585 DJ (3)% 2024 plan 2025 plan Current (DC&E) Current (D&C) Note: Well costs represent an average depth, two-mile lateral in each basin. Actual well costs can vary with multiple factors including specific development zone, lateral length, wells per pad, amongst other factors.
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Accelerating Value Through Non -core Asset Sales 6 Divested DJ Basin assets $435 MM non-core asset divestments, significantly exceeding $300 MM annual target Realizing 2026E EBITDAX multiple >4x 2026 production estimated 10 MBoe/d (~50% oil); 4Q25 impact of ~12 MBoe/d Streamlining DJ Basin operations; focus on core near- term development areas 100% of proceeds expected to go to debt reduction Anticipate closing transactions around the end of 3Q25 CIVI acreage Divested acreage(1) (1) Represents the pending non-core asset divestments which are expected to close around the end of the third quarter 2025.
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Free cash flow Accelerate deleveraging Base dividend Net debt reduction Buybacks 7 Reinstating 50/50 Allocation to Buybacks/Debt 50% to debt reduction 1 – Base dividend commitment • $0.50 per quarter; current annual yield ~7% 2 – Continuous focus on debt reduction • 2025 non-core asset divestments exceeding plan • Anticipating $4.5 Bn net debt around YE25; no RCF borrowings 3 – Value-focused share repurchases • Board increased authorization to $750 MM; ~28% of market cap • $250 MM accelerated share repurchase in 2025 • Total buybacks in 2025 estimated to be ~$375 MM • 50% to buybacks determined on an annual basis Illustrative 2025E FCF allocation FCF generated $435 MM to debt reduction Asset sale proceeds 50% to share buybacks $2.00 per share 2 3 1 CIVI Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 2025E total capital return yield(1) % of market capitalization Peer avg. 6% ~21% Note: Historical capital return based on period of cash settlement (i.e. when dividends paid). (1) Peers comprise CHRD, MGY, MTDR, MUR, PR, SM, VTLE. Data sources from Capital One July 30.
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2Q Results / 3Q Guidance
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Delivered $749 MM Adj. EBITDAX(1) & $123 MM Adj. FCF(2) Oil growth of 6% to 149 MBbl/d Cash Opex(3) per BOE down >10% to $10.19 Added ~9 MMBbls of new oil hedges 3Q25 – 3Q26 $750 MM unsecured bond, reducing RCF borrowings and increasing liquidity Cost optimization and efficiency delivering well cost improvements ↓7% in Delaware ↓5% in Midland ↓3% in DJ Strong productivity in Permian, including first operated Delaware pad Multi-well DJ Basin development >4 miles drilled; Avg. Spud to TD 4.4 days Strong 2Q25 Performance 9 (1) Adjusted EBITDAX is a non-GAAP financial measure. See slide 19 for a reconciliation to the most directly comparable GAAP financial measure. (2) Adjusted Free Cash Flow is a non-GAAP financial measure. See slide 20 for a reconciliation to the most directly comparable GAAP financial measure. (3) Includes LOE, GT&P Expense, Midstream Expense, and Cash G&A. Cash G&A is a non-GAAP financial measure. See slide 22 for a reconciliation to the most directly comparable GAAP financial measure. .
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1 Permian Basin Overview 3 1 2 3 2 Midland S Delaware CIVI acreage N Delaware 10 Key Stats Midland Delaware Net acreage ~109,000 ~32,000 YE24 proved reserves(1) 444 MMBoe Q2 2025 Total production 113 MBoe/d 57 MBoe/d Oil production 55 MBbl/d 28 MBbl/d Capex $271 MM Rigs / frac crews 5 / 2 Net TILs 42 2025E Net TILs 120 – 130 Avg. WI ~91% Avg. LL ~2.1 miles 2Q25 highlights • ~10% oil production growth quarter over quarter with LOE per BOE down 17% • Well costs decreased 7% in Delaware and 5% in Midland since beginning of 2025 Delaware Basin • 50% of wells drilled and 30% of wells completed were in the Delaware • First operated pad turned online in late June in Lea Co.; early-time production results in-line with expectation Midland Basin • First co-development in Martin County; strong results from Middle Spraberry to WCA • Wolfcamp D continues to outperform expectations (1) Excludes reserves associated with Midland bolt-on acquisition (transaction closed February 2025).
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Delaware Execution Exceeding Expectations 1,000 1,200 1,400 1,600 Plan Current Delaware drilling efficiency Feet drilled per day Delaware drilling and completions operations realizing significant efficiencies • Improved drilling performance driven by BHA optimization refined wellbore design, and utilization of managed pressure drilling ▪ Recent 4-well Wolfcamp A pad averaged 1,875 feet drilled per day • Completions throughput averaging >170,000 Bbl/day for Delaware simulfrac pads to-date ▪ Simulfrac ~90% of 2025 Permian program Production from first operated NM pad online late 2Q25; early results in-line with expectations • Multiple Delaware pads expected online in 3Q25 driving continued Permian production growth ~20% Delaware completions throughput Barrels pumped per day 0 45,000 90,000 135,000 180,000 2024 Zipper fracs Simulfrac ~50% 11
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Watkins West Wattenberg East Wattenberg CIVI acreage Divested acreage(2) DJ Basin Overview 12 Key Stats Net acreage(1) ~357,000 YE24 proved reserves 354 MMBoe Q2 2025 Total production 146 MBoe/d Oil production 66 MBbl/d Capex $226 MM Rigs / frac crews 2 / 2 Net TILs 46 2025E Net TILs 80 – 90 Avg. WI ~86% Avg. LL ~2.2 miles 2Q25 highlights • Sustained production quarter over quarter with significant growth anticipated in 3Q • Well costs decreased 3% per foot to $650 (D,C &E) • Sustained regulatory progress with two new Oil & Gas Development Plans (OGDPs) approved • Accelerating value with $435 MM in non-core asset divestments KS NE NMAZ UT KS (1) Net acreage does not reflect the impact of the pending non-core asset divestments which are expected to close around the end of the third quarter 2025. (2) Represents the pending non-core asset divestments which are expected to close around the end of the third quarter 2025.
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2.5 4.0 5.0 7.0 10.0 2.3 3.7 9.9 5.4 6.6 1 mile 2 mile 2.5 mile 3 mile 4 mile 2025 Plan Actual DJ Basin Efficiencies Ahead of Plan DJ drilling efficiency YTD Spud to spud (days) DJ completions throughput Barrels pumped per day 70,000 90,000 110,000 130,000 2025 plan 1Q Actual 2Q Outlook 2Q Actual Record-setting drilling performance • Drilled and completed largest step out in basin 9,150’ (Invicta) • 4-mile cycle times continue to trend down, most recent spud to spud in ~6 days • Utilizing RSS alternative allowing rotation while drilling directionally – lower cost and reduced failure rates Consistent improvement in completions • Real-time AI frac optimization increasing throughput by ~5% • Utilizing all electric-fleets to enhance emissions profile • Extended reach wells utilizing 6” casing to increase fluid throughput • Fiber test verified stage architecture, uniformity index, and plug providers 13
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0 1 2 0 30 Cum. oil prod. per well (MBbl/1,000 ft) Days on production Invicta pad 4-mile laterals 3-mile laterals Unlocking Value through Trades and Long Laterals 14 Invicta development – top-tier resource in Watkins • Ground game trade into Invicta driving value through expertise in drilling long laterals • Some of the longest wells in Colorado - 4.3 miles drilled; 3 miles frac’d ▪ ~5% lower cost/ft compared to 2024 4-mile laterals due to increased drilling and completions efficiencies ▪ Decreased frac time on pad by 11 days ▪ Utilizing existing CIVI surface location • Peak 30-day oil avg. 1,100 Bbl/d; highest well avg. >1,600 Bbl/d 1.3-mile reach over existing wells3-mile productive laterals Early-time production performance CIVI acreage Trade in (Invicta) Trade out Watkins
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Delivering Third Quarter Growth 350 450 550 2Q25 3Q25E Capital expenditures $ MM $9.00 $9.50 $10.00 $10.50 2Q25 3Q25E Cash operating costs(1) $ per Boe (~1.5)% (1) Includes LOE, GT&P Expense, Midstream Expense, and Cash G&A. Cash G&A is a non-GAAP financial measure. For 2Q25, see slide 22 for a reconciliation to the most directly comparable GAAP financial measure. For 3Q25E, due to the forward-looking nature of this projection and the unavailability of the specific quantifications of the amounts that would be required to reconcile such pro jection to the most directly comparable GAAP financial measure, Civitas believes it to be infeasible to provide accurate reconci liations. 200 250 300 350 2Q25 3Q25E 5.5% 100 120 140 160 2Q25 3Q25E Oil production MBbl per day 15 (~5)% Total volumes MBoe per day Divestment ImpactDivestment Impact 5.5%
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2025 Guidance Update 16 Current Status Quo FY Range Divestment Impact(1) Divestment – adjusted FY Range Oil production (MBbl/d) 150 – 155 (2) 148 – 153 Total production (MBoe/d) 325 – 335 (4) 321 – 331 Total cash opex(2) ($/Boe) $9.60 – $10.30 $9.60 – $10.30 Capital expenditures ($MM) $1,800 – $1,900 $1,800 – $1,900 (1) Represents the portion of production lost in 2025 from non-core divestments (transactions expected to close around the end of 3Q25) averaged for the full-year 2025. (2) Includes LOE, GT&P Expense, Midstream Expense, and Cash G&A. Cash G&A is a non-GAAP financial measure. Due to the forward-looking nature of this projection and the unavailability of the specific quantifications of the amounts that would be required to reconcile such projection to the most directly comparable GAAP finan cial measure, Civitas believes it to be infeasible to provide accurate reconciliations. 3Q Guidance Commentary Oil production (MBbl/d) 154 – 160 Divestment impact – 1 MBbl/d (3Q), 6 MBbl/d (4Q) Total production (MBoe/d) 327 – 338 Divestment impact – 2 MBoe/d (3Q), 12 MBoe/d (4Q) Total cash opex(2) ($/Boe) $9.80 – $10.30 Benefitting from volume growth and cost optimization project Capital expenditures ($MM) $460 – $500 Benefitting from well cost savings; activity accelerated from 4Q into 3Q Full-year Guidance Third Quarter Guidance
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Appendix
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Hedge Position Summary Note: Hedge positions as of August 1, 2025. 18 Contract period 3Q25 4Q25 1Q26 2Q26 3Q26 4Q26 Crude oil derivatives (volumes in Bbl/day and prices in $/Bbl) Swaps NYMEX WTI volumes 48,363 74,700 33,000 44,500 12,000 -- Weighted-average contract price $70.85 $66.41 $68.28 $61.20 $65.21 -- Two-way collars NYMEX WTI volumes 46,500 19,000 15,000 5,000 -- -- Weighted-average ceiling price $76.99 $75.11 $75.18 $71.28 -- -- Weighted-average floor price $66.31 $60.00 $60.00 $60.00 -- -- Contract period 3Q25 4Q25 1Q26 2Q26 3Q26 4Q26 Natural gas derivatives (volumes in MMBtu/day and prices in $/MMBtu) Swaps NYMEX HH volumes 240,000 240,000 60,000 60,000 60,000 60,000 Weighted-average contract price $3.83 $3.83 $4.42 $4.42 $4.42 $4.42 Two-Way Collars NYMEX HH volumes 50,000 50,000 200,000 200,000 200,000 200,000 Weighted-average ceiling price $4.30 $4.30 $4.35 $4.35 $4.35 $4.35 Weighted-average floor price $3.66 $3.66 $3.52 $3.52 $3.52 $3.52 Basis protection swaps Waha basis volumes 140,000 140,000 130,000 130,000 130,000 130,000 Weighted-average contract price ($1.32) ($1.32) ($1.31) ($1.31) ($1.31) ($1.31) CIG basis volumes 150,000 150,000 130,000 130,000 130,000 130,000 Weighted-average contract spread ($0.83) ($0.83) ($0.57) ($0.57) ($0.57) ($0.57)
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Adjusted EBITDAX is a supplemental non-GAAP financial measure that represents earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash and/or non-recurring charges. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature. We present Adjusted EBITDAX because we believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our revolving credit facility based on Adjusted EBITDAX ratios. In addition, Adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the crude oil and natural gas exploration and production industry. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because Adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the Adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDAX (in millions): Adjusted EBITDAX Reconciliation 19
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Adjusted Free Cash Flow Reconciliation 20 Adjusted Free Cash Flow is a supplemental non-GAAP financial measure that is calculated as net cash provided by operating activities before changes in operating assets and liabilities and less exploration and development of crude oil and natural gas properties, changes in working capital related to capital expenditures, and purchases of carbon credits. We believe that Adjusted Free Cash Flow provides additional information that may be useful to investors and analysts in evaluating our ability to generate cash from our existing crude oil and natural gas assets to fund future exploration and development activities and to return cash to stockholders. Adjusted Free Cash Flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. The following tables presents a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Adjusted Free Cash Flow (in millions):
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Net Debt is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines net debt as GAAP total debt, excluding any applicable unamortized deferred financing costs and discounts/premiums, less GAAP cash and cash equivalents. We believe Net Debt is an important element for assessing the Company’s liquidity. The following table presents a reconciliation of GAAP financial measure of total debt to the non-GAAP financial measure of Net Debt (in millions). Net Debt Reconciliation 21
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Cash General and Administrative Reconciliation 22 Cash general and administrative is a non-GAAP measure that excludes stock-based compensation, that we believe affects the comparability of operating results as it is non-cash. Cash general and administrative is a non-GAAP measure that we include in our total cash operating expense per BOE. We believe it provides useful additional information to investors and analysts, as a performance measure, for analysis of our operations. The following table presents a reconciliation of the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of cash general and administrative (in millions):