Civitas Resources Reports Second Quarter 2025 Results and
Reinstates Capital Return Program

DENVER — August 6, 2025 - Civitas Resources, Inc. (NYSE: CIVI) (the "Company" or "Civitas") today reported its second quarter 2025 financial and operating results, announced asset divestments exceeding its 2025 full-year target, and reinstated a peer-leading capital return program. A webcast and conference call to discuss these items is planned for 6:00 a.m. MT (8:00 a.m. ET) on Thursday, August 7, 2025. Participation details are available in this release, and supplemental materials can be accessed on the Company's website, www.civitasresources.com.

•Second quarter results exceeded expectations, with strong operating performance including higher than expected oil production and lower than expected capital and operating costs.

•On track with the Company's cost optimization and capital efficiency efforts, targeting $40 million in savings in 2025 and $100 million in 2026.

•Signed agreements to divest non-core DJ Basin assets for $435 million, significantly exceeding the Company’s full-year 2025 asset sales target, at a valuation of more than 4x estimated EBITDAX. Proceeds from the transactions, which are expected to close around the end of the third quarter 2025, are expected to be allocated to debt reduction.

•Reinstating a capital return strategy of allocating 50% of free cash flow, after the base dividend, to share buybacks and 50% to debt reduction on an annual basis. The Company's Board increased its share repurchase authorization to $750 million, and Civitas plans to enter into a $250 million accelerated share repurchase program.

Interim CEO Wouter van Kempen commented, “Our second quarter results demonstrate the decisive steps we have taken to strengthen Civitas’ operating performance and financial position. Year-to-date, we’ve improved field-level execution, captured sustainable cost savings, reduced risk through hedging, optimized our capital structure, and accelerated value through non-core divestments, resulting in a stronger and more durable Civitas. With high confidence in our operating plan, including reaching our $4.5 billion debt target around the end of the year, we are reinstating an aggressive capital return program to take advantage of the compelling value we see in our equity today.”

(1) Non-GAAP financial measure; see attached schedules at the end of this release for reconciliations to the most directly comparable GAAP financial measures.

•Average daily oil volumes increased six percent from the first quarter, almost entirely from the Permian Basin as a result of new wells commencing production in the first half of the year.

•Capital expenditures were at the low end of expectations, benefiting from well cost optimization, capital efficiencies, and activity timing adjustments.

◦The Company's current average drilling, completion and facilities cost per lateral foot in the Delaware, Midland, and DJ Basins are $880, $685, and $650 (down seven, five, and three percent, respectively, from the beginning of the year).

•Permian Basin activity included 27, 31, and 42 net operated wells drilled, completed, and turned to sales, respectively. The Company's average lateral length completed was approximately two miles.

◦Over 50% of the wells drilled and 30% of the wells completed were in the Delaware Basin.

◦Simul-frac operations in the Delaware Basin averaged more than 170,000 barrels of water pumped per day on its initial completions.

◦Included in the wells turned to sales was the Company's initial operated Delaware development in Lea County, New Mexico. The four wells commenced production in late June with initial production in line with expectations.

◦In the Midland Basin, the Company brought online 11 two-mile laterals in Martin County, Texas, that included co-development in the Middle and Lower Spraberry, Jo Mill, and Wolfcamp A reservoirs, with peak 30-day production averaging 823 barrels per day per well.

•DJ Basin activity for the quarter included 30, 31, and 46 net operated wells drilled, completed, and turned to sales, respectively. The Company's average lateral length completed was 2.3 miles.

◦During the second quarter, the Company drilled a multi-well pad of four-mile wells with an average spud-to-total depth of 4.4 days.

◦In the Watkins area, the Company commenced production on an eight-well development that averaged over four miles drilled and three miles completed, demonstrating Civitas' expertise in long-reach laterals. The wells represent some of the longest laterals in Colorado, and peak 30-day oil production averaged 1,100 barrels per day per well, with one of the wells averaging over 1,600 barrels per day.

•Crude oil, natural gas, and NGL revenues totaled nearly $1.1 billion, benefiting from strong crude oil volumes and realizations.

◦Realized oil prices for the quarter benefited from the Company's high-quality crude production in both basins and improved commercial terms for long-haul transportation from the DJ Basin.

◦Natural gas realizations reflected continued weak Waha pricing, and natural gas liquid realizations averaged 30% of the West Texas Intermediate ("WTI") oil price for the period.

•Realized hedging gains for the quarter totaled $69 million, with more than half coming from crude oil swaps and collars, and the remainder primarily from NYMEX and natural gas basis swaps.

•During the second quarter, the Company opportunistically added over nine million barrels of oil hedges through the third quarter of 2026. The Company has protected nearly 60% of second half 2025 production with a weighted-average floor of $67 per barrel WTI.

•Cash operating expenses, including lease operating expense ("LOE"), midstream operating expense, gathering, transportation, and processing, and cash G&A(2), totaled $10.19 per barrel of oil equivalent ("BOE"), a more than 10% reduction from the first quarter of the year.

◦Permian Basin LOE per BOE was lower than the first quarter by more than 15%, largely as a result of reduced maintenance and workover activity, lower water disposal, and fuel and power usage.

•Financial liquidity at the end of the second quarter 2025 totaled $2 billion, representing cash on hand and borrowings available under the Company's revolving credit facility. During the second quarter, the Company issued $750 million in unsecured Senior Notes due 2033, with the proceeds utilized to reduce credit facility borrowings.

(2) Cash operating expenses include LOE, midstream, gathering, transportation and processing, and cash G&A. Cash G&A is a non-GAAP financial measure. See attached schedules at the end of this release for reconciliations to the most directly comparable GAAP financial measures.

The Company’s Board of Directors approved a quarterly dividend of $0.50 per share, payable on September 25, 2025, to shareholders of record as of September 11, 2025.

The Company recently executed two agreements to divest non-core DJ Basin asset packages for a total value of $435 million, less customary post-closing adjustments, which represents an estimated EBITDAX multiple of over 4x based on 2026 estimated production and pricing. The assets are located in the northern portion of the Company's DJ Basin acreage position and are estimated to produce approximately 10 MBoe/d (approximately 50% oil) in 2026. Divesting these assets enables Civitas to further streamline its operations and operating cost structure in the basin.

The two transactions are expected to close around the end of the third quarter 2025, and all proceeds are expected to go to debt reduction. Production is anticipated to be lower by 2 MBoe/d in the third quarter of 2025 and 12 MBoe/d in the fourth quarter, approximately half of which is oil, as a result of the divestments.

Civitas remains on track with its cost optimization and efficiency initiative to deliver sustainable capital reductions and margin improvements. For 2025, the Company estimates the impact from this initiative to be $40 million, led by well cost and cycle time reductions in each basin, improved oil differentials from new transportation agreements, as well as lower LOE, GTP, and corporate costs.

For the third quarter, Civitas anticipates more than five percent oil volume growth, with both the Permian and DJ Basins showing meaningful increases. Permian Basin production is anticipated to maintain high levels in the fourth quarter while the DJ Basin is reduced primarily as a result of the non-core divestitures.

Third quarter capital expenditures are expected to be lower than the second quarter of the year, reflecting well cost improvements and slight adjustments in the timing of planned activities.

(3) Third quarter 2025 average sales volumes guidance reflects a 2 MBoe/d (1 MBbl/d) reduction as a result of the non-core asset divestments.

(4) Cash operating expenses include LOE, midstream, gathering, transportation and processing, 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 financial measure, we believe it to be infeasible to provide accurate reconciliations.

The Company plans to host a webcast and conference call at 6:00 a.m. MT (8:00 a.m. ET) on Thursday, August 7, 2025. The webcast will be available on the Investor Relations section of the Company’s website at www.civitasresources.com. The dial-in number for the call is 888-510-2535, with passcode 4872770.

Civitas Resources, Inc. is an independent exploration and production company focused on the acquisition, development and production of crude oil and liquids-rich natural gas from its premier assets in the Permian Basin in Texas and New Mexico and the DJ Basin in Colorado. Civitas’ proven business model to maximize shareholder returns is focused on four key strategic pillars: generating significant free cash flow, maintaining a premier balance sheet, returning capital to shareholders, and demonstrating ESG leadership. For more information about Civitas, please visit www.civitasresources.com.

Certain statements in this press release concerning 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. 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 press release include statements regarding the Company’s plans and expectations with respect to the Company’s capital return program and anticipated ASR program, the timing of the completion of and the allocation of proceeds from the Company’s two non-core DJ Basin asset divestitures, achievement of the Company’s net debt targets, future production, sales volumes, capital expenditures, cash operating expenses, and oil differentials, 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; 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; political conditions in or affecting other producing countries, including conflicts or hostilities in or relating to the Middle East (including the current events involving Israel and Iran), 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; the risk that we will not be able to complete one or both of our non-core DJ Basin divestitures on the anticipated timelines or at all; our ability to identify, select, and consummate possible additional acquisition and disposition opportunities; the ability of our customers and vendors 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; 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.

Investor Relations:

Brad Whitmarsh, 832.736.8909, bwhitmarsh@civiresources.com

Media:

Rich Coolidge, info@civiresources.com

Schedule 1: Condensed Consolidated Statements of Operations

Schedule 2: Condensed Consolidated Statements of Cash Flows

Schedule 3: Condensed Consolidated Balance Sheets

Schedule 4: Average Sales Volumes and Prices

The following table presents crude oil, natural gas, and NGL sales volumes by operating region as well as consolidated average sales prices before and after derivatives.

Average sales price, after derivatives is a non-GAAP financial measure that incorporates the net effect of derivative cash receipts from or payments on commodity derivatives that are presented in our accompanying statements of cash flows, netted into the average sales price, before derivatives, the most directly comparable GAAP financial measure. We believe that the presentation of average sales price, after derivatives is a useful means to reflect the actual cash performance of our commodity derivatives for the respective periods and is useful to management and our stockholders in determining the effectiveness of our price risk management program. The following table provides a reconciliation of the GAAP financial measure of average sales price, before derivatives to the non-GAAP financial measure of average sales prices, after derivatives for the periods presented:

____________________

(1) Items may not recalculate due to rounding.

(2) Derivatives economically hedge the price we receive for crude oil, natural gas, and NGL. For the three months ended June 30, 2025, the derivative cash settlement gain for crude oil and natural gas was $36 million and $33 million, respectively. For the three months ended March 31, 2025, the derivative cash settlement gain for crude oil and natural gas was $1 million and $3 million respectively. For the six months ended June 30, 2025, the derivative cash settlement gain for crude oil and natural gas was $37 million and $36 million, respectively. For the six months ended June 30, 2024, the derivative cash settlement loss for crude oil was $30 million, and the derivative cash settlement gain for natural gas was $6 million. We did not hedge the price we received for NGL during the periods presented.

Schedule 5: Adjusted Net Income

Adjusted Net Income is a supplemental non-GAAP financial measure that is used by management to present a more comparable, recurring profitability between periods. We believe that Adjusted Net Income provides external users of our consolidated financial statements with additional information to assist in their analysis of the Company. Adjusted Net Income represents net income after adjusting for (1) the impact of certain non-cash items and/or non-recurring charges and correspondingly (2) the related tax effect in each period. Adjusted Net Income is not a measure of net income as determined by GAAP and 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.

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted Net Income.

Schedule 6: Adjusted EBITDAX

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:

Schedule 7: Adjusted Free Cash Flow

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 table 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:

Schedule 8: Cash General and Administrative

Cash general and administrative is a supplemental non-GAAP financial 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 financial 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:

						Three Months Ended												Six Months Ended
						June 30, 2025						March 31, 2025						June 30, 2025						June 30, 2024
General and administrative expense						$	53					$	57					$	110					$	117
Stock-based compensation						(13)						(13)						(26)						(23)
Cash general and administrative						$	40					$	44					$	84					$	94