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W&T Offshore Announces Timing of Third Quarter 2025 Earnings Release and Conference Call
W&T Offshore Announces Timing of Third Quarter 2025 Earnings Release and Conference Call HOUSTON, Oct. 23, 2025 (GLOBE NEWSWIRE) -- W&T Offshore, Inc. (NYSE: WTI) (the "Company") today announced the timing of its third quarter 2025 earnings release and conference call. The Company said it will issue its third quarter 2025 earnings release on Wednesday, November 5, 2025, after the close of trading on the NYSE and host a conference call to discuss financial and operational results on Thursday, November 6, 2025, at 9:00 a.m. Central Time (10:00 a.m. Eastern Time). Interested parties may participate by dialing (844) 739-3797. International parties may dial (412) 317-5713. Participants should request to be joined to the "W&T Offshore, Inc. Conference Call." This call will also be webcast and available on W&T Offshore's website at www.wtoffshore.com under "Investors." An audio replay will be available on the Company's website following the call. About W&T Offshore W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of America and has grown through acquisitions, exploration and development. As of June 30, 2025, the Company had working interests in 50 fields in federal and state waters (which include 43 fields in federal waters and seven in state waters). The Company has under lease approximately 629,700 gross acres (491,900 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 482,200 gross acres on the conventional shelf, approximately 141,900 gross acres in the deepwater and 5,600 gross acres in Alabama state waters. A majority of the Company's daily production is derived from wells it operates. For more information on W&T, please visit the Company's website at www.wtoffshore.com.
Comstock to Host Third Quarter 2025 Earnings and Business Update Webinar
Comstock to Host Third Quarter 2025 Earnings and Business Update Webinar VIRGINIA CITY, Nev., Oct. 23, 2025 (GLOBE NEWSWIRE) -- Comstock Inc. (NYSE: LODE) ("Comstock" and the "Company") is pleased to announce that the Company's Executive Chairman & CEO, Corrado De Gasperis, and CFO, Judd Merrill will be providing an overview of recent financial results and current business updates on Thursday, October 30, 2025, at 11:30am ET. We invite all investors and other interested parties to register for the webinar at the link below. Date: Thursday, October 30, 2025Time: 11:30am ETRegister: Webinar Registration There will be an allotted time following the live presentation for a Q&A session. Unaddressed questions will be reviewed by management and responded to accordingly. You may submit your question(s) beforehand in the registration form (linked above) or by email at: ir@comstockinc.com. About Comstock Inc. Comstock Inc. (NYSE: LODE) innovates and commercializes technologies, systems and supply chains that enable, support and sustain clean energy systems by efficiently, effectively, and expediently extracting and converting under-utilized natural resources into reusable metals, like silver, aluminum, gold, and other critical minerals, primarily from end-of-life photovoltaics. To learn more, please visit www.comstock.inc. Comstock Social Media Policy Comstock Inc. has used, and intends to continue using, its investor relations link and main website at www.comstock.inc in addition to its X.com, LinkedIn and YouTube accounts, as means of disclosing material non-public information and for complying with its disclosure obligations under Regulation FD. Contacts For investor inquiries:Judd B. Merrill, Chief Financial OfficerTel (775) 413-6222ir@comstockinc.com For media inquiries:Zach Spencer, Director of External RelationsTel (775) 847-7573media@comstockinc.com Forward-Looking Statements This press release and any related calls or discussions may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, are forward-looking statements. The words "believe," "expect," "anticipate," "estimate," "project," "plan," "should," "intend," "may," "will," "would," "potential" and similar expressions identify forward-looking statements but are not the exclusive means of doing so. Forward-looking statements include statements about matters such as: future market conditions; future explorations or acquisitions; divestitures, spin-offs or similar distribution transactions, future changes in our research, development and exploration activities; future financial, natural, and social gains; future prices and sales of, and demand for, our products and services; land entitlements and uses; permits; production capacity and operations; operating and overhead costs; future capital expenditures and their impact on us; operational and management changes (including changes in the Board of Directors); changes in business strategies, planning and tactics; future employment and contributions of personnel, including consultants; future land and asset sales; investments, acquisitions, divestitures, spin-offs or similar distribution transactions, joint ventures, strategic alliances, business combinations, operational, tax, financial and restructuring initiatives, including the nature, timing and accounting for restructuring charges, derivative assets and liabilities and the impact thereof; contingencies; litigation, administrative or arbitration proceedings; environmental compliance and changes in the regulatory environment; offerings, limitations on sales or offering of equity or debt securities, including asset sales and associated costs; business opportunities, growth rates, future working capital, needs, revenues, variable costs, throughput rates, operating expenses, debt levels, cash flows, margins, taxes and earnings. These statements are based on assumptions and assessments made by our management in light of their experience and their perception of historical and current trends, current conditions, possible future developments and other factors they believe to be appropriate. Forward-looking statements are not guarantees, representations or warranties and are subject to risks and uncertainties, many of which are unforeseeable and beyond our control and could cause actual results, developments, and business decisions to differ materially from those contemplated by such forward-looking statements. Some of those risks and uncertainties include the risk factors set forth in our filings with the SEC and the following: adverse effects of climate changes or natural disasters; adverse effects of global or regional pandemic disease spread or other crises; global economic and capital market uncertainties; the speculative nature of gold or mineral exploration, and lithium, nickel and cobalt recycling, including risks of diminishing quantities or grades of qualified resources; operational or technical difficulties in connection with exploration, metal recycling, processing or mining activities; costs, hazards and uncertainties associated with precious and other metal based activities, including environmentally friendly and economically enhancing clean mining and processing technologies, precious metal exploration, resource development, economic feasibility assessment and cash generating mineral production; costs, hazards and uncertainties associated with metal recycling, processing or mining activities; contests over our title to properties; potential dilution to our stockholders from our stock issuances, recapitalization and balance sheet restructuring activities; potential inability to comply with applicable government regulations or law; adoption of or changes in legislation or regulations adversely affecting our businesses; permitting constraints or delays; challenges to, or potential inability to, achieve the benefits of business opportunities that may be presented to, or pursued by, us, including those involving battery technology and efficacy, quantum computing and generative artificial intelligence supported advanced materials development, development of cellulosic technology in bio-fuels and related material production; commercialization of cellulosic technology in bio-fuels and generative artificial intelligence development services; ability to successfully identify, finance, complete and integrate acquisitions, spin-offs or similar distribution transactions, joint ventures, strategic alliances, business combinations, asset sales, and investments that we may be party to in the future; changes in the United States or other monetary or fiscal policies or regulations; interruptions in our production capabilities due to capital constraints; equipment failures; fluctuation of prices for gold or certain other commodities (such as silver, zinc, lithium, nickel, cobalt, cyanide, water, diesel, gasoline and alternative fuels and electricity); changes in generally accepted accounting principles; adverse effects of war, mass shooting, terrorism and geopolitical events; potential inability to implement our business strategies; potential inability to grow revenues; potential inability to attract and retain key personnel; interruptions in delivery of critical supplies, equipment and raw materials due to credit or other limitations imposed by vendors; assertion of claims, lawsuits and proceedings against us; potential inability to satisfy debt and lease obligations; potential inability to maintain an effective system of internal controls over financial reporting; potential inability or failure to timely file periodic reports with the Securities and Exchange Commission; potential inability to list our securities on any securities exchange or market or maintain the listing of our securities; and work stoppages or other labor difficulties. Occurrence of such events or circumstances could have a material adverse effect on our business, financial condition, results of operations or cash flows, or the market price of our securities. All subsequent written and oral forward-looking statements by or attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Except as may be required by securities or other law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Neither this press release nor any related calls or discussions constitutes an offer to sell, the solicitation of an offer to buy or a recommendation with respect to any securities of the Company, the fund, or any other issuer.
Satisfaction of Conditions Precedent for 20-year charter of MK II FLNG to Southern Energy in Argentina, confirming $8 billion EBITDA backlog before commodity exposure and inflationary adjustments
Satisfaction of Conditions Precedent for 20-year charter of MK II FLNG to Southern Energy in Argentina, confirming $8 billion EBITDA backlog before commodity exposure and inflationary adjustments Hamilton, Bermuda October 23, 2025- Golar LNG Limited (Nasdaq: "GLNG" or "Golar") is pleased to announce today that all conditions precedent and customary closing conditions in connection with the 20-year charter of Golar's 3.5MTPA MKII FLNG to Southern Energy S.A. ("SESA") in Argentina have been satisfied. This milestone follows the execution of definitive agreements announced on May 2nd, 2025, and the Final Investment Decision announced on August 6th, 2025. The 20-year charter of the MKII FLNG solidifies $8 billion of net earnings backlog over 20 years, equivalent to $400 million in annual EBITDA to Golar, before commodity exposure and inflationary adjustments. In addition, the charter agreement includes attractive commodity exposure both in the FLNG commodity tariff component and through Golar's 10% shareholding in SESA. The MKII FLNG will be deployed in the Gulf of San MatÃas, offshore Argentina, where it will operate in proximity to the FLNG Hilli. The MKII FLNG, with a nameplate capacity of 3.5 MTPA, is currently undergoing conversion at CIMC Raffles Shipyard in Yantai, China. The unit is on schedule for delivery by year end 2027, with operations expected to commence in 2028. The total conversion budget is approximately $2.2 billion of which $1.0 billion has been spent to date, all capital expenditures funded through equity. The project has received all key governmental approvals, including an unrestricted 30-year LNG export authorization in Argentina, and qualification as Strategic Investment under the Large Investments Incentive Regime ("RIGI"). Golar's CEO, Karl Fredrik Staubo commented: "Following today's confirmation of the 20-year charter for the MKII FLNG in Argentina, each of Golar's three existing FLNGs now holds 20 years of earnings visibility, representing a combined EBITDA backlog of $17 billion before attractive commodity exposure. We look forward to starting operations in Argentina and to continue the strong partnership with SESA and its shareholders. Now that our existing fleet is fully contracted for the next 20+ years, we will increase our focus on new FLNG growth opportunities. Golar's position as the only proven provider of FLNG as a service enables us to drive value for all stakeholders through attractive gas monetization solutions." FORWARD LOOKING STATEMENTSThis press release contains forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934, as amended) which reflect management's current expectations, estimates and projections about its operations. All statements, other than statements of historical facts, that address activities and events that will, should, could or may occur in the future are forward-looking statements. Words such as "may," "could," "should," "would," "expect," "plan," "anticipate," "intend," "forecast," "believe," "estimate," "predict," "propose," "potential," "continue," "subject to" or the negative of these terms and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Golar LNG Limited undertakes no obligation to update publicly any forward-looking statements whether as a result of new information, future events or otherwise, unless required by applicable law. Investor Questions: +44 207 063 7900Karl Fredrik Staubo - CEOEduardo Maranhão - CFO This information is subject to the disclosure requirements pursuant to Section 5-12 the Norwegian Securities Trading Act
Woodside Announces Louisiana LNG Partnership With Williams
Woodside Announces Louisiana LNG Partnership With Williams HOUSTON, Oct. 22 /BusinessWire/ -- Woodside has simultaneously signed and closed a transaction with Williams, a world-class leader in US natural gas infrastructure, for an integrated investment in Louisiana LNG. The strategic partnership involves the sale by Woodside of a 10% interest in Louisiana LNG LLC (HoldCo) and an 80% interest and operatorship of Driftwood Pipeline LLC (PipelineCo) to Williams for a purchase price of US$250 million at the effective date of 1 January 2025. The total proceeds received are $378 million including proportionate capital reimbursement since the effective date. The transaction represents the next key stage towards realising Woodside's strategy for Louisiana LNG. It not only secures capital and offtake commitments but also brings a strong strategic partner with complementary capabilities in US natural gas infrastructure and an existing gas sourcing platform, Sequent Energy Management (Sequent). Williams will contribute its share of the capital expenditure for the LNG facility and pipeline, of approximately $1.9 billion. As part of the investment in Louisiana LNG, Williams assumes LNG offtake obligations for 10% of produced volumes. Williams currently operates more than 33,000 miles of pipeline across 24 states in the US and its Sequent platform has a marketing and optimisation footprint of more than 7 Bcf/d. It will utilise its extensive pipeline experience to construct and operate the Line 200 pipeline to the Louisiana LNG Terminal. Leveraging the established Sequent platform and capabilities, a gas supply team will operationalise and optimise daily gas sourcing and balancing in accordance with Louisiana LNG's gas procurement strategy. Sequent's proven gas marketing and asset optimisation expertise will support reliable feedgas supply for the benefit of all Louisiana LNG participants. Woodside CEO Meg O'Neill welcomed Williams to the Louisiana LNG Project. "We are excited to have Williams join us as a strategic partner in Louisiana LNG given its leadership in US natural gas infrastructure and ability to add value and deliver operational benefits to enhance the project. "This is Williams' first investment in LNG and its participation in Louisiana LNG is a testament to the quality of the project. "The bringing together of Woodside's proven track record in developing and operating LNG facilities and global marketing, and Williams' expertise in pipelines and gas sourcing, creates an energy partnership that has the combined capability to realise opportunities for long-term global energy demand. "With strong LNG contracting momentum from Louisiana LNG and our portfolio, our existing infrastructure partner New York-based Stonepeak, and our key contracting partners including Bechtel, Baker Hughes and Chart, we are on track to deliver first LNG in 2029 and create long-term value for our shareholders." President and CEO of Williams Chad Zamarin expressed enthusiasm for the partnership. "This transaction marks an important step forward in Williams' wellhead to water strategy - integrating upstream, midstream, marketing and LNG capabilities to deliver the cleanest, most reliable energy to global markets. We look forward to partnering with Woodside, and together, reinforcing and strengthening our collective roles as trusted providers of sustainable energy solutions that meet growing global demand." Transaction details Williams will hold 10% equity in Louisiana LNG LLC (HoldCo), with the remaining 90% of HoldCo currently owned by Woodside. HoldCo owns 60% equity in Louisiana LNG Infrastructure LLC (InfraCo), with the remainder being owned by Stonepeak. Williams will hold 80% equity in Driftwood Pipeline LLC (PipelineCo) and manage construction and operations of the Line 200 pipeline. Woodside will own the remaining 20%. HoldCo will continue to lead the gas procurement strategy and execute agreements greater than 12 months. Leveraging the established Sequent platform and capabilities, a gas supply team will operationalise and optimise daily gas sourcing and balancing in accordance with HoldCo's gas procurement strategy. Optimisation value created is distributed to HoldCo. The team will be Williams-led and include secondees and oversight from Woodside. Williams' total share of LNG production from Louisiana LNG will be 1.6 million tonnes per annum (Mtpa). This LNG production will be supplied to Williams under an LNG SPA for approximately 1.5 Mtpa and Williams will also receive the proportionate benefit (10%) of the Louisiana LNG 1.0 Mtpa SPA previously signed with Uniper.1 The effective date of the transaction is 1 January 2025 with completion having occurred simultaneously with execution. The consideration includes a payment of $250 million representing Williams' contribution to acquisition and project development costs until the effective date. Williams will also reimburse its proportionate share of development costs from 1 January 2025. The total payment received from Williams is $378 million. Woodside's total capital expenditure for the Louisiana LNG Project is now expected to be $9.9 billion reduced from $11.8 billion at final investment decision (FID). HoldCo will remain consolidated in Woodside's year end accounts. PipelineCo will be deconsolidated and recorded as an equity investment on a go-forward basis. Woodside's financial advisers are RBC Capital Markets and Evercore, and its legal adviser is Norton Rose Fullbright. About Williams Williams (NYSE:WMB) owns and operates energy infrastructure that safely and reliably delivers the natural gas that is used every day to affordably heat homes, cook food and generate electricity. As the world moves to a lower-carbon future, Williams is well-positioned to leverage its natural gas-focused strategy while continuing to deliver consistently stable returns for its shareholders. Williams is a FORTUNE 500 investment grade corporation headquartered in Tulsa, Oklahoma, with operations across the natural gas value chain spanning the United States. Williams handles one third of natural gas volumes across the United States. Sequent Energy Management, a Williams Company, moves natural gas to markets through transportation and storage agreements on strategically positioned assets. Sequent currently has a marketing and optimisation footprint of 7 Bcf/d. About Louisiana LNG Louisiana LNG is a fully permitted LNG project located near Lake Charles, Louisiana, with total permitted capacity of 27.6 Mtpa across five trains. The approved foundation project includes three trains with a combined capacity of 16.5 Mtpa. The project is targeting first LNG in 2029. Bechtel is the engineering, procurement and construction contractor, under a lump sum, turnkey agreement. The facility utilises the Chart IPSMR® liquefaction technology and Baker Hughes LM6000PF+ gas turbines. This announcement was approved and authorised for release by Woodside's Disclosure Committee. Forward-looking statements This announcement contains forward-looking statements with respect to Woodside's business and operations, market conditions, results of operations and financial condition, including, for example, but not limited to, statements regarding the transaction (including statements concerning the expected benefits of the transaction and other future arrangements between the parties), expectations regarding future expenditures (including the development costs for the Louisiana LNG Project and related pipelines), completion dates and future results of projects. All forward-looking statements contained in this announcement reflect Woodside's views held as at the date of this announcement. All statements, other than statements of historical or present facts, are forward-looking statements and generally may be identified by the use of forward-looking words such as 'guidance', 'foresee', 'likely', 'potential', 'anticipate', 'believe', 'aim', 'estimate', 'expect', 'intend', 'may', 'target', 'plan', 'forecast', 'project', 'schedule', 'will', 'should', 'seek' and other similar words or expressions. Forward-looking statements in this announcement are not guidance, forecasts, guarantees or predictions of future events or performance, but are in the nature of aspirational targets that Woodside has set for itself and its management of the business. Those statements and any assumptions on which they are based are only opinions, are subject to change without notice and are subject to inherent known and unknown risks, uncertainties, assumptions and other factors, many of which are beyond the control of Woodside, its related bodies corporate and their respective officers, directors, employees, advisers or representatives. Details of the key risks relating to Woodside and its business can be found in the "Risk" section of Woodside's most recent Annual Report released to the Australian Securities Exchange and Woodside's most recent Annual Report on Form 20-F filed with the United States Securities and Exchange Commission and available on the Woodside website at https://www.woodside.com/investors/reports-investor-briefings. You should review and have regard to these risks when considering the information contained in this announcement. Investors are strongly cautioned not to place undue reliance on any forward-looking statements. Actual results or performance may vary materially from those expressed in, or implied by, any forward-looking statements. All information included in this announcement, including any forward-looking statements, speak only as of the date of this announcement and, except as required by law or regulation, Woodside does not undertake to update or revise any information or forward-looking statements contained in this announcement, whether as a result of new information, future events, or otherwise. 1 See "Woodside signs LNG supply agreements with Uniper" released 17 April 2025. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022810869/en/ back
Patterson-UTI Energy Reports Financial Results for the Quarter Ended September 30, 2025
Patterson-UTI Energy Reports Financial Results for the Quarter Ended September 30, 2025 HOUSTON, TEXAS / ACCESS Newswire / October 22, 2025 / PATTERSON-UTI ENERGY, INC. (NASDAQ:PTEN) today reported financial results for the quarter ended September 30, 2025.Third Quarter 2025 Financial Results and Other Key ItemsTotal revenue of $1.2 billionNet loss attributable to common stockholders of $36 millionAdjusted net loss attributable to common stockholders of $21 millionAdjusted EBITDA of $219 millionReturned $64 million to shareholders in the third quarter through an $0.08 per share dividend and $34 million in share repurchasesDeclared a quarterly dividend of $0.08 per share, payable on December 15, 2025 to holders of record as of December 1, 2025Management Commentary"In the third quarter, our teams successfully navigated a challenging environment, and we are executing our plan that concentrates on optimizing our business in the areas that we can control," said Andy Hendricks, Chief Executive Officer. "Operationally, our teams are performing well, and we continue to enhance our commercial strategy through additional integration and performance-based agreements, while at the same time we are lowering our cost structure. Margin performance across Patterson-UTI is outpacing what we have historically seen in periods of activity moderation. We think this outperformance is a function of the focus and execution of the teams in each of our segments and the technology edge that we are using to deliver better drilling and completion results for our customers. We expect this relative margin resiliency to continue.""U.S. activity levels stabilized towards the end of the third quarter, and while we do expect normal seasonality in completion activity during the fourth quarter, we think our activity should remain relatively steady into 2026," continued Mr. Hendricks. "We believe the full impact of the moderation of activity over the past six months is yet to be fully reflected in U.S. oil production, and we believe current industry activity is already below levels needed to hold U.S. oil production steady. Any further rig count declines would likely result in additional pressure on U.S. oil production volumes for an extended period, which could negatively impact global oil supply in 2026. On natural gas, we continue to see a strengthening outlook as physical LNG takeaway begins to come into focus, which we expect to result in higher natural gas drilling and completion activity in 2026.""We continue to deliver on the cash generation potential of our company, and we expect the fourth quarter will be our strongest free cash flow generating quarter of the year," said Andy Smith, Chief Financial Officer. "Our low leverage and strong liquidity give us significant flexibility in capital allocation going forward, and we will continue to deploy capital only towards opportunities we believe will deliver high long-term returns for our shareholders, including the option to further accelerate our share repurchase program."Drilling ServicesDuring the third quarter, our Drilling Services segment revenue totaled $380 million. Drilling Services adjusted gross profit was $134 million during the quarter. Our U.S. Contract Drilling operating days totaled 8,737, with an average of 95 rigs working in the third quarter.Activity in our U.S. Contract Drilling business was steady outside the Permian Basin compared to the second quarter, with the sequential change in activity a function of moderating industry demand in the Permian Basin. Additionally, our Directional Drilling business performance was strong, benefitting from high service quality and additional integrated offerings with both our drilling rigs and drill bits.Completion ServicesThird quarter Completion Services revenue totaled $705 million, with adjusted gross profit of $111 million. Our commercial team effectively managed our frac schedule during the quarter, with steady overall activity compared to the second quarter. Additionally, our operational execution was very strong, with our teams making great strides in efficiency and benefiting from some cost reduction activities in the segment during the first half of the year. Pricing per horsepower hour was steady compared to the second quarter, with lower revenue from low margin sand and chemical product sales.Our fleet of Emerald 100% natural gas-powered assets remains in high demand with strong operational and financial performance. Towards the end of the third quarter, we accepted delivery of our first commercial direct-drive hydraulic fracturing fleet, which is scheduled to begin long-term dedicated work in the fourth quarter.After successful introduction in the third quarter, we continue to deploy our Vertex Automated Controls across all pumping fleets, with projection for full deployment by year-end. This will allow us to implement closed loop automation for all pump types to improve our operating efficiency and asset management, while delivering optimized completion designs for our customers based on real-time surface measurements.Drilling ProductsThird quarter Drilling Products revenue totaled $86 million, with adjusted gross profit of $36 million.Performance was strong in the United States and Canada, where our sequential change in revenue again outperformed the change in industry activity. We reached another company record for U.S. revenue per U.S. industry rig, with the segment improving on this metric by approximately 40% since we acquired Ulterra in 2023. International revenue was down slightly, the result of lower drilling activity in Saudi Arabia, which is our largest international market.Segment margins were impacted by higher than normal bit repair expense early in the quarter, although the segment did see margins return closer to historical levels by the end of the quarter.OtherDuring the third quarter, Other revenue totaled $5 million, with adjusted gross profit totaling $2 million.Other Operating ExpensesOther Operating Expenses for the quarter totaled $23 million, of which $20 million was associated with the accrual of expenses associated with personal injury-related claims for incidents that occurred several years ago, partially offset by a favorable contract dispute resolution.OutlookWithin the Drilling Services segment for the fourth quarter, we expect our average rig count will be similar to the third quarter, which reflects activity remaining relatively steady, compared to our current rig count, through the end of the year. We expect adjusted gross profit within the Drilling Services segment to be down approximately 5% from the third quarter.In our Completion Services segment for the fourth quarter, we expect adjusted gross profit to be approximately $85 million. From an activity perspective, we expect less seasonality compared to the fourth quarter last year.In our Drilling Products segment for the fourth quarter, we expect adjusted gross profit will improve slightly compared to the third quarter. We expect relatively steady results in the U.S. and Canada, with higher revenue and adjusted gross profit from our International business.We expect Other adjusted gross profit in the fourth quarter to be roughly flat compared to the third quarter.For the fourth quarter, we expect selling, general and administrative expense to be relatively steady compared to the third quarter, and we expect depreciation, depletion, amortization, and impairment expense of approximately $225 million.We expect capital expenditures to approximate $140 million during the fourth quarter. For full-year 2025, we now expect capital expenditures to be below $600 million, before considering the benefit of $33 million in asset sales we have realized through the third quarter. For full-year 2025, our updated capital expenditure budget is lower than previously expected.All references to "per share" in this press release are diluted earnings per common share as defined within Accounting Standards Codification Topic 260.Third Quarter Earnings Conference CallThe Company's quarterly conference call to discuss the operating results for the quarter ended September 30, 2025, is scheduled for October 23, 2025, at 9:00 a.m. Central Time. The dial-in information for participants is (800) 715-9871 (Domestic) and (646) 307-1963 (International). The conference ID for both numbers is 5526772. The call is also being webcast and can be accessed through the Investor Relations section of the Company's website at investor.patenergy.com. A replay of the conference call will be on the Company's website for two weeks.About Patterson-UTIPatterson-UTI is a leading provider of drilling and completion services to oil and natural gas exploration and production companies in the United States and other select countries, including contract drilling services, integrated well completion services and directional drilling services in the United States, and specialized bit solutions in the United States, Middle East and many other regions around the world. For more information, visit www.patenergy.com.Cautionary Statement Regarding Forward-Looking StatementsThis press release contains forward-looking statements which are protected as forward-looking statements under the Private Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Patterson-UTI's current beliefs, expectations or intentions regarding future events. Words such as "anticipate," "believe," "budgeted," "continue," "could," "estimate," "expect," "intend," "may," "plan," "potential," "predict," "project," "pursue," "see," "should," "strategy" "target," or "will," and similar expressions are intended to identify such forward-looking statements. The statements in this press release that are not historical statements, including statements regarding Patterson-UTI's future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance that are not historical facts, are forward-looking statements within the meaning of the federal securities laws. These statements are subject to numerous risks and uncertainties, many of which are beyond Patterson-UTI's control, which could cause actual results to differ materially from the results expressed or implied by the statements. These risks and uncertainties include, but are not limited to: adverse oil and natural gas industry conditions, including the impact of commodity price volatility on industry outlook; global economic conditions, including inflationary pressures and risks of economic downturns or recessions in the United States and elsewhere; volatility in customer spending and in oil and natural gas prices that could adversely affect demand for Patterson-UTI's services and their associated effect on rates; excess supply of drilling and completions equipment, including as a result of reactivation, improvement or construction; competition and demand for Patterson-UTI's services; the impact of the ongoing Ukraine/Russia and Middle East conflicts and instability in other international regions; strength and financial resources of competitors; utilization, margins and planned capital expenditures; ability to obtain insurance coverage on commercially reasonable terms and liabilities from operational risks for which Patterson-UTI does not have and receive full indemnification or insurance; operating hazards attendant to the oil and natural gas business; failure by customers to pay or satisfy their contractual obligations (particularly with respect to fixed-term contracts); the ability to realize backlog; specialization of methods, equipment and services and new technologies, including the ability to develop and obtain satisfactory returns from new technology and the risk of obsolescence of existing technologies; the ability to attract and retain management and field personnel; loss of key customers; shortages, delays in delivery, and interruptions in supply, of equipment and materials; cybersecurity events; difficulty in building and deploying new equipment; complications with the design or implementation of Patterson-UTI's new enterprise resource planning system; governmental regulation, including climate legislation, regulation and other related risks; environmental, social and governance practices, including the perception thereof; environmental risks and ability to satisfy future environmental costs; technology-related disputes; legal proceedings and actions by governmental or other regulatory agencies; changes to tax, tariff and import/export regulations and sanctions by the United States or other countries, including the impacts of any sustained escalation or changes in tariff levels or trade-related disputes; the ability to effectively identify and enter new markets or pursue strategic acquisitions; public health crises, pandemics and epidemics; weather; operating costs; expansion and development trends of the oil and natural gas industry; financial flexibility, including availability of capital and the ability to repay indebtedness when due; adverse credit and equity market conditions; our return of capital to stockholders, including timing and amounts (including any plans or commitments in respect thereof) of any dividends and share repurchases; stock price volatility; and compliance with covenants under Patterson-UTI's debt agreements.Additional information concerning factors that could cause actual results to differ materially from those in the forward-looking statements is contained from time to time in Patterson-UTI's SEC filings. Patterson-UTI's filings may be obtained by contacting Patterson-UTI or the SEC or through Patterson-UTI's website at http://www.patenergy.com or through the SEC's Electronic Data Gathering and Analysis Retrieval System (EDGAR) at http://www.sec.gov. Patterson-UTI undertakes no obligation to publicly update or revise any forward-looking statement.PATTERSON-UTI ENERGY, INC.Condensed Consolidated Balance Sheets(unaudited, in thousands) September 30, 2025 December 31, 2024 ASSETS Current assets: Cash, cash equivalents and restricted cash $186,913 $241,293 Accounts receivable, net 800,448 763,806 Inventory 155,933 167,023 Other current assets 134,207 123,193 Total current assets 1,277,501 1,295,315 Property and equipment, net 2,785,428 3,010,342 Goodwill 487,388 487,388 Intangible assets, net 842,972 929,610 Other assets 139,821 110,811 Total assets $5,533,110 $5,833,466 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $461,265 $421,318 Accrued liabilities 283,880 385,751 Other current liabilities 32,628 34,924 Total current liabilities 777,773 841,993 Long-term debt, net 1,220,716 1,219,770 Deferred tax liabilities, net 232,803 238,097 Other liabilities 46,733 57,762 Total liabilities 2,278,025 2,357,622 Stockholders' equity: Stockholders' equity attributable to controlling interests 3,248,805 3,465,823 Noncontrolling interest 6,280 10,021 Total equity 3,255,085 3,475,844 Total liabilities and stockholders' equity $5,533,110 $5,833,466 PATTERSON-UTI ENERGY, INC.Condensed Consolidated Statements of Operations(unaudited, in thousands, except per share data) Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, 2025 2025 2024 2025 2024 REVENUES $1,175,954 $1,219,320 $1,357,222 $3,675,811 $4,215,776 COSTS AND EXPENSES: Direct operating costs 893,833 929,363 1,011,907 2,784,610 3,060,210 Depreciation, depletion, amortization and impairment 225,598 261,858 374,680 719,322 917,274 Impairment of goodwill - - 885,240 - 885,240 Selling, general and administrative 61,976 64,108 65,696 193,014 195,258 Merger and integration expense 90 488 6,699 1,010 29,577 Other operating expense (income), net 22,511 (7,011) 3,629 18,450 (13,381) Total operating costs and expenses 1,204,008 1,248,806 2,347,851 3,716,406 5,074,178 OPERATING INCOME (LOSS) (28,054) (29,486) (990,629) (40,595) (858,402) OTHER INCOME (EXPENSE): Interest income 1,480 1,272 745 4,216 4,801 Interest expense, net of amount capitalized (17,488) (17,645) (17,990) (52,830) (54,238)Other income (expense) 1,020 (1,644) (716) 1,344 358 Total other income (expense) (14,988) (18,017) (17,961) (47,270) (49,079) INCOME (LOSS) BEFORE INCOME TAXES (43,042) (47,503) (1,008,590) (87,865) (907,481) INCOME TAX EXPENSE (BENEFIT) (6,592) 1,194 (30,256) (4,008) 7,526 NET INCOME (LOSS) (36,450) (48,697) (978,334) (83,857) (915,007) NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST (48) 447 427 684 1,442 NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS $(36,402) $(49,144) $(978,761) $(84,541) $(916,449) NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS PER COMMON SHARE: Basic $(0.10) $(0.13) $(2.50) $(0.22) $(2.29)Diluted $(0.10) $(0.13) $(2.50) $(0.22) $(2.29)WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING: Basic 382,819 385,365 391,732 384,888 399,795 Diluted 382,819 385,365 391,732 384,888 399,795 CASH DIVIDENDS PER COMMON SHARE $0.08 $0.08 $0.08 $0.24 $0.24 PATTERSON-UTI ENERGY, INC.Condensed Consolidated Statements of Cash Flows(unaudited, in thousands) Nine Months Ended September 30, 2025 2024 Cash flows from operating activities: Net income (loss) $(83,857) $(915,007)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and impairment 719,322 917,274 Impairment of goodwill - 885,240 Deferred income tax expense (benefit) (5,599) 5,824 Stock-based compensation 30,527 35,790 Net (gain) loss on asset disposals (1,739) (5,956)Other 27 7,347 Changes in operating assets and liabilities (94,988) (70,810)Net cash provided by operating activities 563,693 859,702 Cash flows from investing activities: Purchases of property and equipment (450,516) (538,036)Investment in unconsolidated affiliate (10,500) - Proceeds from disposal of assets, including insurance recoveries 33,155 14,685 Other (8,980) (1,464)Net cash used in investing activities (436,841) (524,815) Cash flows from financing activities: Purchases of treasury stock (69,424) (269,948)Dividends paid (92,114) (95,593)Proceeds from revolving credit facility - 50,000 Repayments of revolving credit facility - (50,000)Payments of finance leases (6,216) (36,635)Other (10,820) (9,156)Net cash used in financing activities (178,574) (411,332)Effect of foreign exchange rate changes on cash, cash equivalents and restricted cash (2,658) (753)Net change in cash, cash equivalents and restricted cash (54,380) (77,198)Cash, cash equivalents and restricted cash at beginning of period 241,293 192,680 Cash, cash equivalents and restricted cash at end of period $186,913 $115,482 PATTERSON-UTI ENERGY, INC.Additional Financial and Operating Data(unaudited, dollars in thousands) Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, 2025 2025 2024 2025 2024 Drilling Services Revenues $380,200 $403,805 $421,563 $1,196,865 $1,319,425 Direct operating costs $246,407 $254,772 $250,877 $748,808 $784,111 Adjusted gross profit (1) $133,793 $149,033 $170,686 $448,057 $535,314 Depreciation, amortization and impairment $84,100 $112,647 $201,272 $281,719 $392,224 Selling, general and administrative $3,969 $4,152 $3,809 $12,066 $11,761 Other operating expense (income), net $8,600 $(8,368) $- $232 $- Operating income (loss) $37,124 $40,602 $(34,395) $154,040 $131,329 Operating days - U.S. (2) 8,737 9,465 9,870 27,775 31,282 Capital expenditures $46,691 $55,174 $69,127 $175,323 $210,346 Completion Services Revenues $705,275 $719,332 $831,567 $2,190,687 $2,581,937 Direct operating costs $594,118 $619,083 $703,809 $1,870,882 $2,102,643 Adjusted gross profit (1) $111,157 $100,249 $127,758 $319,805 $479,294 Depreciation, amortization and impairment $117,058 $119,774 $140,930 $352,658 $428,303 Impairment of goodwill $- $- $885,240 $- $885,240 Selling, general and administrative $8,821 $9,723 $10,253 $29,953 $31,854 Other operating expense (income), net $13,000 $- $- $13,000 $(17,792)Operating income (loss) $(27,722) $(29,248) $(908,665) $(75,806) $(848,311)Capital expenditures $81,301 $68,985 $86,755 $212,459 $258,860 Drilling Products Revenues $85,880 $88,390 $89,102 $259,933 $265,129 Direct operating costs $50,265 $49,335 $47,144 $146,540 $141,921 Adjusted gross profit (1) $35,615 $39,055 $41,958 $113,393 $123,208 Depreciation, amortization and impairment $21,326 $23,584 $22,924 $67,786 $73,282 Selling, general and administrative $8,486 $8,651 $9,898 $26,256 $25,651 Operating income (loss) $5,803 $6,820 $9,136 $19,351 $24,275 Capital expenditures $13,331 $15,252 $16,309 $46,805 $45,853 Other (3) Revenues $4,599 $7,793 $14,990 $28,326 $49,285 Direct operating costs $3,043 $6,173 $10,077 $18,380 $31,535 Adjusted gross profit (1) $1,556 $1,620 $4,913 $9,946 $17,750 Depreciation, depletion, amortization and impairment $923 $3,538 $8,330 $10,797 $19,253 Selling, general and administrative $(177) $82 $156 $109 $649 Operating income (loss) $810 $(2,000) $(3,573) $(960) $(2,152)Capital expenditures $2,145 $1,802 $5,909 $7,543 $18,919 Corporate Depreciation $2,191 $2,315 $1,224 $6,362 $4,212 Selling, general and administrative $40,877 $41,500 $41,580 $124,630 $125,343 Merger and integration expense $90 $488 $6,699 $1,010 $29,577 Other operating expense (income), net $911 $1,357 $3,629 $5,218 $4,411 Capital expenditures $1,011 $2,993 $2,487 $8,386 $4,058 Total Capital Expenditures $144,479 $144,206 $180,587 $450,516 $538,036 Adjusted gross profit is defined as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense, which does not include impairment of goodwill). See Non-GAAP Financial Measures below for a reconciliation of GAAP gross profit to adjusted gross profit by segment.Operational data relates to our contract drilling business. A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day.Other includes our oilfield rentals business, prior to its divestiture in April 2025, and oil and natural gas working interests.PATTERSON-UTI ENERGY, INC.Non-GAAP Financial MeasuresAdjusted EBITDA(unaudited, dollars in thousands) Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, 2025 2025 2024 2025 2024 Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (Adjusted EBITDA) (1): Net income (loss) $(36,450) $(48,697) $(978,334) $(83,857) $(915,007)Income tax expense (benefit) (6,592) 1,194 (30,256) (4,008) 7,526 Net interest expense 16,008 16,373 17,245 48,614 49,437 Depreciation, depletion, amortization and impairment 225,598 261,858 374,680 719,322 917,274 Legal accruals and settlements 20,000 (4,585) - 15,415 (17,792)Impairment of goodwill - - 885,240 - 885,240 Merger and integration expense 90 488 6,699 1,010 29,577 Adjusted EBITDA $218,654 $226,631 $275,274 $696,496 $956,255 Total revenues $1,175,954 $1,219,320 $1,357,222 $3,675,811 $4,215,776 Adjusted EBITDA by Operating Segment: Drilling Services $128,224 $148,664 $166,877 $438,174 $523,553 Completion Services 102,336 90,526 117,505 289,852 447,440 Drilling Products 27,129 30,404 32,060 87,137 97,557 Other 1,733 1,538 4,757 9,837 17,101 Corporate (40,768) (44,501) (45,925) (128,504) (129,396)Adjusted EBITDA $218,654 $226,631 $275,274 $696,496 $956,255 Adjusted earnings before interest, taxes, depreciation and amortization ("Adjusted EBITDA") is not defined by accounting principles generally accepted in the United States of America ("GAAP"). We define Adjusted EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization and impairment expense, legal accruals and settlements, impairment of goodwill, and merger and integration expense. We present Adjusted EBITDA as a supplemental disclosure because we believe it provides to both management and investors additional information with respect to the performance of our fundamental business activities and a comparison of the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be construed as an alternative to the GAAP measure of net income (loss). Our computations of Adjusted EBITDA may not be the same as similarly titled measures of other companies.PATTERSON-UTI ENERGY, INC.Non-GAAP Financial MeasuresAdjusted Free Cash Flow(unaudited, dollars in thousands) Nine Months Ended September 30, 2025 2024 Adjusted Free Cash Flow (1): Net cash provided by operating activities $563,693 $859,702 Less capital expenditures (450,516) (538,036)Plus proceeds from disposal of assets, including insurance recoveries 33,155 14,685 Adjusted free cash flow $146,332 $336,351 We define adjusted free cash flow as net cash provided by operating activities less capital expenditures, plus proceeds from disposal of assets, including insurance recoveries. We present adjusted free cash flow as a supplemental disclosure because we believe that it is an important liquidity measure and that it is useful to investors and management as a measure of the company's ability to generate cash flow, after reinvesting in the company, that could be available for financing cash flows, such as dividend payments, share repurchases and/or repurchases of long-term indebtedness. Our computations of adjusted free cash flow may not be the same as similarly titled measures of other companies. Adjusted free cash flow is not intended to represent our residual cash flow available for discretionary expenditures. Adjusted free cash flow is a non-GAAP financial measure that should be considered in addition to, not as a substitute for or superior to, cash flows from operations reported in accordance with GAAP.PATTERSON-UTI ENERGY, INC.Non-GAAP Financial MeasuresAdjusted Gross Profit(unaudited, dollars in thousands) Three Months Ended Nine Months Ended September 30, June 30, September 30, September 30, 2025 2025 2024 2025 2024 Drilling Services Revenues $380,200 $403,805 $421,563 $1,196,865 $1,319,425 Less direct operating costs (246,407) (254,772) (250,877) (748,808) (784,111)Less depreciation, amortization and impairment (84,100) (112,647) (201,272) (281,719) (392,224)GAAP gross profit (loss) 49,693 36,386 (30,586) 166,338 143,090 Depreciation, amortization and impairment 84,100 112,647 201,272 281,719 392,224 Adjusted gross profit (1) $133,793 $149,033 $170,686 $448,057 $535,314 Completion Services Revenues $705,275 $719,332 $831,567 $2,190,687 $2,581,937 Less direct operating costs (594,118) (619,083) (703,809) (1,870,882) (2,102,643)Less depreciation, amortization and impairment (117,058) (119,774) (140,930) (352,658) (428,303)GAAP gross profit (loss) (5,901) (19,525) (13,172) (32,853) 50,991 Depreciation, amortization and impairment 117,058 119,774 140,930 352,658 428,303 Adjusted gross profit (1) $111,157 $100,249 $127,758 $319,805 $479,294 Drilling Products Revenues $85,880 $88,390 $89,102 $259,933 $265,129 Less direct operating costs (50,265) (49,335) (47,144) (146,540) (141,921)Less depreciation, amortization and impairment (21,326) (23,584) (22,924) (67,786) (73,282)GAAP gross profit (loss) 14,289 15,471 19,034 45,607 49,926 Depreciation, amortization and impairment 21,326 23,584 22,924 67,786 73,282 Adjusted gross profit (1) $35,615 $39,055 $41,958 $113,393 $123,208 Other Revenues $4,599 $7,793 $14,990 $28,326 $49,285 Less direct operating costs (3,043) (6,173) (10,077) (18,380) (31,535)Less depreciation, depletion, amortization and impairment (923) (3,538) (8,330) (10,797) (19,253)GAAP gross profit (loss) 633 (1,918) (3,417) (851) (1,503)Depreciation, depletion, amortization and impairment 923 3,538 8,330 10,797 19,253 Adjusted gross profit (1) $1,556 $1,620 $4,913 $9,946 $17,750 We define "Adjusted gross profit" as revenues less direct operating costs (excluding depreciation, depletion, amortization and impairment expense, which does not include impairment of goodwill). Adjusted gross profit is included as a supplemental disclosure because it is a useful indicator of our operating performance.PATTERSON-UTI ENERGY, INC.Non-GAAP Financial MeasuresAdjusted Net Income (Loss)(unaudited, in thousands) Three Months Ended September 30, 2025 As Reported Adjusted Total Total Net income (loss) attributable to common stockholders as reported $(36,402) $(36,402) Reverse certain items: Merger and integration expense 90 Legal accruals and settlements 20,000 Income tax expense (benefit) (4,219) Adjusted net income (loss) (1) $(36,402) $(20,531) Federal statutory tax rate 21.0%We define adjusted net income (loss) as net loss attributable to common stockholders as reported, excluding merger and integration expense and legal accruals and settlements. We present adjusted net income (loss) in order to convey to investors our performance on a basis that, by excluding the items listed above, is more comparable to our net income (loss) reported in previous periods. Adjusted net income (loss) should not be construed as an alternative to GAAP net income (loss).Contact: Michael SabellaVice President, Investor Relations(281) 885-7589SOURCE: Patterson-UTI EnergyView the original press release on ACCESS Newswire
Crescent Energy Announces Updates to Revolving Credit Facility: Increased Borrowing Base, Extended Tenor and Early Synergy Capture
Crescent Energy Announces Updates to Revolving Credit Facility: Increased Borrowing Base, Extended Tenor and Early Synergy Capture HOUSTON, Oct. 22 /BusinessWire/ -- Crescent Energy Company (NYSE:CRGY) ("Crescent" or the "Company") today announced the successful completion of its fall borrowing base redetermination under its reserve-based revolving credit facility (the "Credit Facility"). The borrowing base increase and extended tenor reflect strong support from Crescent's bank syndicate and ongoing financial discipline. Credit Facility Highlights Elected Commitment Amount reaffirmed at $2.0 billion Borrowing Base increased by 50%, from $2.6 billion to $3.9 billion(1) Maturity extended to five years, resulting in no near-term debt maturities and a weighted average maturity of 6.4 years Pricing grid reduced by 25 basis points, from 200-300 bps to 175-275 bps Total synergy capture of approximately $12 million, or roughly 13% of the midpoint of Crescent's $90-$100 million synergy range associated with the Vital Energy transaction, primarily driven by lower interest expense, unused commitment fees and reduced administrative costs "We are pleased with the outcome of our fall redetermination process and the continued support of our lender group," said Crescent Energy CEO David Rockecharlie. "The increase in our borrowing base, combined with extended maturities and lower spreads, further enhances our financial flexibility and delivers meaningful cost-of-capital synergies. We have already realized approximately 13% of our targeted synergies ahead of closing the Vital Energy transaction, demonstrating early progress toward capturing our full synergy potential." About Crescent Energy Crescent is a differentiated U.S. energy company committed to delivering value for shareholders through a disciplined growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines stable cash flows from low-decline production with deep, high-quality development inventory. The Company's investing and operating activities are focused in Texas and the Rocky Mountain region. For additional information, please visit www.crescentenergyco.com. No Offer or Solicitation This communication relates to a proposed business combination transaction (the "Transaction") between Crescent and Vital Energy, Inc. ("Vital"). This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the Transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended (the "Securities Act"). Important Additional Information About the Transaction In connection with the Transaction, Crescent filed a registration statement on Form S-4 with the U.S. Securities and Exchange Commission (the "SEC") (File No. 333-290422) that includes a preliminary joint proxy statement of Crescent and Vital and a prospectus of Crescent. The registration statement has not been declared effective by the SEC nor has it become effective pursuant to the Securities Act, and the information contained in the preliminary joint proxy statement/prospectus is not complete and may be changed. The Transaction will be submitted to Crescent's stockholders and Vital's stockholders for their consideration. Crescent and Vital may also file other documents with the SEC regarding the Transaction. The definitive joint proxy statement/prospectus will be sent to the stockholders of Crescent and Vital. This document is not a substitute for the registration statement that has been, and joint proxy statement/prospectus that will be, filed with the SEC or any other documents that Crescent or Vital may file with the SEC or send to stockholders of Crescent or Vital in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF CRESCENT AND VITAL ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders can obtain free copies of the registration statement and will be able to obtain free copies of the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by Crescent or Vital through the website maintained by the SEC at https://www.sec.gov. Copies of documents filed with the SEC by Crescent are made available free of charge on Crescent's website at https://crescentenergyco.com/investors, or by directing a request to Investor Relations, Crescent Energy Company, 600 Travis Street, Suite 7200, Houston, TX 77002, Tel. No. (713) 332-7001. Copies of documents filed with the SEC by Vital are made available free of charge on Vital's website at https://vitalenergy.com under the Investors tab or by directing a request to Investor Relations, Vital Energy, Inc., 521 E. Second Street, Suite 1000, Tulsa, OK 74120, Tel. No. (918) 513-4570. Participants in the Solicitation Regarding the Mergers Crescent and Vital and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies in respect to the Transaction. Information regarding Crescent's executive officers and directors, including a description of their direct or indirect interests, by security holdings or otherwise, (i) is set forth in Crescent's Annual Report on Form 10-K for the year ended December 31, 2024, including under Part III, Item 10. Directors, Executive Officers and Corporate Governance, Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, and Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence, which was filed with the SEC on February 26, 2025, and available at https://www.sec.gov/Archives/edgar/data/1866175/000186617525000024/crgy-20241231.htm and (ii) to the extent holdings of Crescent's securities by its directors or executive officers have changed since the amounts set forth in Crescent's Annual Report on Form 10-K for the year ended December 31, 2024, such changes have been or will be reflected on Initial Statement of Beneficial Ownership of Securities on Form 3, Statement of Changes in Beneficial Ownership on Form 4, or Annual Statement of Changes in Beneficial Ownership on Form 5 filed with the SEC, which are available at https://www.sec.gov/cgi-bin/own-disp?action=getissuer&CIK=0001866175. You can obtain a free copy of these documents at the SEC's website at www.sec.gov or by accessing Crescent's website at crescentenergyco.com. Information regarding Vital's directors and executive officers, including a description of their direct or indirect interests, by security holdings or otherwise, (i) is set forth in Vital's definitive proxy statement for its 2025 Annual Meeting of Stockholders, including under the headings "Proposal One - Election of Three Class III Directors at the 2025 Annual Meeting", "Proposal Three - Advisory Vote Approving the Compensation of Our Named Executive Officers", "Stock Ownership Information", and "Related Party Transactions", which was filed with the SEC on April 10, 2025 and available at https://www.sec.gov/Archives/edgar/data/1528129/000152812925000071/vtle-20250409.htm and (ii) to the extent holdings of Vital's securities by the directors or executive officers have changed since the amounts set forth in Vital's definitive proxy statement for its 2025 Annual Meeting of Stockholders, such changes have been or will be reflected on Initial Statement of Beneficial Ownership of Securities on Form 3, Statement of Changes in Beneficial Ownership on Form 4, or Annual Statement of Changes in Beneficial Ownership on Form 5 filed with the SEC, which are available at https://www.sec.gov/cgi-bin/own-disp?action=getissuer&CIK=0001528129. You can obtain a free copy of these documents at the SEC's website at https://www.sec.gov or by accessing Vital's website at vitalenergy.com. Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the joint proxy statement/prospectus regarding the Transaction when it becomes available. You may obtain free copies of this document as described above. Forward-Looking Statements and Cautionary Statements The foregoing contains "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this communication that address activities, events or developments that Crescent or Vital expects, believes or anticipates will or may occur in the future are forward-looking statements. Words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "create," "intend," "could," "may," "foresee," "plan," "will," "guidance," "look," "outlook," "goal," "future," "assume," "forecast," "build," "focus," "work," "continue" or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, statements regarding the Transaction, the expected timing of completion of the Transaction, pro forma descriptions of the combined company and its operations, integration and transition plans, synergies, opportunities and anticipated future performance. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication. These include the expected timing and likelihood of completion of the Transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Transaction that could reduce anticipated benefits or cause the parties to abandon the Transaction, the ability to successfully integrate the businesses, the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement, the possibility that stockholders of Crescent may not approve the issuance of new shares of common stock in the Transaction or that stockholders of Vital may not approve the merger agreement, the risk that the parties may not be able to satisfy the conditions to the Transaction in a timely manner or at all, risks related to disruption of management time from ongoing business operations due to the Transaction, the risk that any announcements relating to the Transaction could have adverse effects on the market price of Crescent's common stock or Vital's common stock, the risk that the Transaction and its announcement could have an adverse effect on the ability of Crescent and Vital to retain customers and retain and hire key personnel and maintain relationships with their suppliers and customers and on their operating results and businesses generally, the risk the pending Transaction could distract management of both entities and they will incur substantial costs, the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve synergies or it may take longer than expected to achieve those synergies and other important factors that could cause actual results to differ materially from those projected. All such factors are difficult to predict and are beyond Crescent's or Vital's control, including those detailed in Crescent's annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on its website at www.crescentenergyco.com and on the SEC's website at https://www.sec.gov, and those detailed in Vital's annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on Vital's website at www.vitalenergy.com and on the SEC's website at https://www.sec.gov. The Company does not give any assurance (1) that it will achieve its expectations or (2) to any business strategies, earnings or revenue trends or future financial results. All forward-looking statements are based on assumptions that Crescent or Vital believe to be reasonable but that may not prove to be accurate. Any forward-looking statement speaks only as of the date on which such statement is made, and Crescent and Vital undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022826069/en/ back
Energy Transfer LP Announces Cash Distribution on Series I Preferred Units
Energy Transfer LP Announces Cash Distribution on Series I Preferred Units DALLAS, Oct. 22 /BusinessWire/ -- Energy Transfer LP ("ET") today announced the quarterly cash distribution of $0.2111 per Series I Preferred Unit (NYSE:ETprI). The cash distribution for the Series I unitholders will be paid on November 14, 2025 to Series I unitholders of record as of the close of business on November 4, 2025. Energy Transfer LP (NYSE:ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with approximately 140,000 miles of pipeline and associated energy infrastructure. Energy Transfer's strategic network spans 44 states with assets in all of the major U.S. production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids ("NGL") and refined product transportation and terminalling assets; and NGL fractionation. Energy Transfer also owns Lake Charles LNG Company, as well as the general partner interests, the incentive distribution rights and approximately 21% of the outstanding common units of Sunoco LP (NYSE:SUN), and the general partner interests and approximately 38% of the outstanding common units of USA Compression Partners, LP (NYSE:USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com. Forward Looking Statements This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management's control. An extensive list of factors that can affect future results, including future distribution levels and leverage ratio, are discussed in the Partnership's Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events. Qualified Notice This release serves as qualified notice to nominees as provided for under Treasury Regulation Section 1.1446-4(b)(4) and (d). Please note that one hundred percent (100%) of Energy Transfer LP's distributions to foreign investors are attributable to income that is effectively connected with a United States trade or business. Accordingly, all of Energy Transfer LP's distributions to foreign investors are subject to federal tax withholding at the highest applicable effective tax rate. Nominees, and not Energy Transfer LP, are treated as withholding agents responsible for withholding distributions received by them on behalf of foreign investors. For purposes of Treasury Regulation section 1.1446(f)-4(c)(2)(iii), brokers and nominees should treat one hundred percent (100%) of the distributions as being in excess of cumulative net income for purposes of determining the amount to withhold. The information contained in this press release is available on our website at www.energytransfer.com. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022854241/en/ back
World Kinect Corporation Names Andrea Smith to the Board of Directors
World Kinect Corporation Names Andrea Smith to the Board of Directors MIAMI, Oct. 22 /BusinessWire/ -- World Kinect Corporation (NYSE:WKC) today announced the appointment of Andrea B. Smith to the Board of Directors of the company, effective October 24, 2025. "We are delighted to have Andrea join our Board of Directors," said Michael J. Kasbar, Chairman and Chief Executive Officer. "She is an accomplished financial services executive who brings a wealth of financial, operational and HR expertise." Ms. Smith retired from Bank of America in 2021 after nearly 34 years of service. Ms. Smith most recently served as Bank of America's Chief Administrative Officer, and was a member of Bank of America's executive management team, reporting to its Chief Executive Officer, for more than a decade. Previously, she led Bank of America's Global Human Resources function, managing a global workforce of more than 285,000 employees. Ms. Smith holds a degree in economics from Southern Methodist University. About World Kinect Corporation Headquartered in Miami, Florida, World Kinect Corporation (NYSE: WKC) is a global energy management company offering fulfillment and related services to customers across the aviation, marine, and land-based transportation sectors. The company also supplies natural gas and power in the United States and Europe along with a broad suite of sustainability-related products and services. For more information, visit www.world-kinect.com. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022967462/en/ back
NCS Multistage Holdings, Inc. Schedules Third Quarter 2025 Earnings Release and Conference Call
NCS Multistage Holdings, Inc. Schedules Third Quarter 2025 Earnings Release and Conference Call HOUSTON, Oct. 22, 2025 (GLOBE NEWSWIRE) -- NCS Multistage Holdings, Inc. ("NCS" or the "Company") (NASDAQ:NCSM) will host a conference call to discuss its third quarter 2025 results on Thursday, October 30, 2025 at 7:30 a.m. Central Time (8:30 a.m. Eastern Time). NCS will issue its third quarter 2025 earnings release the evening prior to the conference call. The conference call will be available via a live audio webcast. Participants who wish to ask questions may register for the call here to receive the dial-in numbers and unique PIN. If you wish to join the conference call but do not plan to ask questions, you may join the listen-only webcast here. It is recommended that participants join at least 10 minutes prior to the event start. The replay will be available in the Investors section of the Company's website shortly after the conclusion of the call and will remain available for approximately seven days. NCS Multistage Holdings, Inc. is a leading provider of highly engineered products and support services that facilitate the optimization of oil and natural gas well construction, well completions and field development strategies. NCS provides products and services primarily to exploration and production companies for use in onshore and offshore wells, predominantly wells that have been drilled with horizontal laterals in both unconventional and conventional oil and natural gas formations. NCS's products and services are utilized in oil and natural gas basins throughout North America and in selected international markets, including the North Sea, the Middle East, Argentina and China. NCS's common stock is traded on the Nasdaq Capital Market under the symbol "NCSM." Additional information is available on the website, www.ncsmultistage.com. Contact:Mike MorrisonChief Financial Officer and Treasurer+1 281-453-2222IR@ncsmultistage.com
Kinder Morgan Reports Third Quarter 2025 Financial Results
Kinder Morgan Reports Third Quarter 2025 Financial Results Earnings per Share (EPS) Flat to the Third Quarter of 2024 Adjusted EPS Up 16% HOUSTON, Oct. 22 /BusinessWire/ -- Kinder Morgan, Inc.'s (NYSE:KMI) board of directors today approved a cash dividend of $0.2925 per share for the third quarter ($1.17 annualized), payable on November 17, 2025, to stockholders of record as of the close of business on November 3, 2025. This dividend is a 2% increase over the third quarter of 2024. KMI is reporting: Third quarter net income attributable to KMI was $628 million versus $625 million in the third quarter of 2024; excluding Certain Items, which had a negative impact on net income attributable to KMI in 2025 and a positive impact in 2024, Adjusted Net Income Attributable to KMI was $648 million, 16% higher than the third quarter of 2024. Adjusted EBITDA of $1,991 million, up 6% versus the third quarter of 2024. Earnings per share (EPS) of $0.28, flat to the third quarter of 2024; and Adjusted EPS of $0.29, up 16% versus the third quarter of 2024. "We are firmly in an era of American global energy leadership," said Executive Chairman Richard D. Kinder. "The United States continues to lead the world in natural gas production and in exports of liquefied natural gas (LNG), providing enhanced energy security to allies around the world. "With historic growth in global natural gas demand, a favorable federal regulatory landscape, and strong support from permitting agencies, the outlook for our company is exceptionally promising," Kinder continued. "Our long-standing business model-owning midstream energy assets anchored by long-term, take-or-pay, fee-based contracts with creditworthy customers-positions us to continue delivering reliable performance and sustained value." "The company generated strong third quarter net income attributable to KMI and Adjusted EBITDA, with increased financial contributions from our Natural Gas Pipelines, Products Pipelines, and Terminals business segments versus the third quarter of 2024, along with very strong operational performance and project execution," said Chief Executive Officer Kim Dang. "We continued to internally fund high-quality capital projects while generating cash flow from operations of $1.4 billion and free cash flow (FCF) after capital expenditures of $0.6 billion, up 13% and 5%, respectively, from the prior year period. Our balance sheet remains healthy, as we ended the quarter with a Net Debt-to-Adjusted EBITDA ratio of 3.9 times," continued Dang. "KMI is seeing an opportunity set more robust than at any time in the company's history. U.S. LNG nameplate capacity is expected to more than double by 2030. We currently have long-term contracts to move almost 8 billion cubic feet per day (Bcf/d) of natural gas to LNG facilities and, upon completion of projects under construction, that amount is expected to grow to almost 12 Bcf/d by the end of 2028. We are also pursuing a substantial number of additional LNG feedgas opportunities," said Dang. "Overall, total demand for natural gas is expected to grow by 20% through 2030, led by LNG exports. We are also actively exploring more than 10 Bcf/d of opportunities to serve the natural gas power generation sector. Approximately 50% of our backlog is associated with projects supporting power generation. In the markets we serve, we expect robust growth in power demand in the coming years. With 66,000 miles of natural gas pipelines connected to all major basins and demand centers, along with more than 700 Bcf of working gas storage capacity, we are confident that we will secure our share of additional natural gas infrastructure projects supporting demand growth," said Dang. "Reflecting this strong demand, natural gas projects account for approximately 90% of our project backlog. At the end of the third quarter of 2025, the backlog stood at $9.3 billion, with approximately $500 million of projects placed in service during the quarter offset by a roughly equivalent amount of projects added. "In calculating backlog Project EBITDA multiples, we exclude both the capital and EBITDA from our CO2 enhanced oil recovery projects and our gathering and processing projects, where first-full-year multiples are more favorable but the earnings are more uneven than with our other business segments. We expect the remaining $7.9 billion of projects in the backlog, when realized, to generate an aggregate first-full-year Project EBITDA multiple of approximately 5.7 times," continued Dang. "Looking ahead, we anticipate meaningful tax advantages that will further strengthen our cash flow profile. The permanent reinstatement of bonus depreciation and the potential for expanded interest expense deductibility are expected to reduce our cash tax liability starting in 2025, with even greater benefits as new projects come online in 2026 and 2027. Additionally, recent regulatory adjustments to the corporate alternative minimum tax will unlock further savings beginning in 2026," Dang concluded. 2025 Outlook We currently expect to exceed budget primarily due to contributions from the Outrigger Energy II acquisition that closed in the first quarter of 2025. This outperformance would have been greater if not for lower than budgeted D3 RIN prices and volumes. For 2025, KMI budgeted net income attributable to KMI of $2.8 billion, up 8% versus 2024, and Adjusted EPS of $1.27, up 10% from 2024. KMI expects to declare dividends of $1.17 per share for 2025, a 2% increase from the dividends declared for 2024. The company also budgeted 2025 Adjusted EBITDA of $8.3 billion, up 4% versus 2024, and to end 2025 with a Net Debt-to-Adjusted EBITDA ratio of 3.8 times. These amounts do not include contributions from the Outrigger acquisition. This press release includes Adjusted Net Income Attributable to KMI, Adjusted EPS, Adjusted Segment EBDA, Adjusted EBITDA, Net Debt, FCF, and Project EBITDA, all of which are non-GAAP financial measures. For descriptions of these non-GAAP financial measures and reconciliations to the most comparable measures prepared in accordance with generally accepted accounting principles, please see "Non-GAAP Financial Measures" and the tables accompanying our preliminary financial statements. Overview of Business Segments "The Natural Gas Pipelines business segment's improved financial performance in the third quarter of 2025 relative to the third quarter of 2024 was due primarily to continued higher contributions from both our Texas Intrastate system and Tennessee Gas Pipeline (TGP) as well as contributions from the Outrigger Energy assets," said KMI President Tom Martin. "Natural gas transport volumes were up 6% compared to the third quarter of 2024 primarily due to LNG deliveries on TGP, new contracts from expansion projects placed in service on our Texas Intrastate system, and increased Permian deliveries to Waha and Mexico on El Paso Natural Gas. Natural gas gathering volumes were up 9% from the third quarter of 2024 across all assets, driven primarily by our Haynesville and Eagle Ford systems. "Contributions from the Products Pipelines business segment were up compared to the third quarter of 2024 due to higher transport rates in 2025 and unfavorable commodity price impact in our transmix business during the third quarter of 2024. Total refined products volumes were down 1% compared to the third quarter of 2024. Crude and condensate volumes were down 3% due to the expiration of legacy contracts in advance of our Double H pipeline conversion to natural gas liquids service. This was partially offset by higher volumes across all other crude and condensate pipelines," Martin said. "Terminals business segment earnings were up compared to the third quarter of 2024. The increase was led by our Jones Act tanker fleet, which benefited from higher rates and remains fully contracted under term charter agreements. Earnings from our liquids terminals business were up versus the prior year period, partially offset by lower earnings from our bulk terminals," continued Martin. "CO2 business segment earnings, which include Energy Transition Ventures (ETV), were down compared to the third quarter of 2024 due to lower crude and CO2 volumes, as well as lower CO2 and D3 RIN prices," said Martin. Other News Corporate On August 11, 2025, Fitch upgraded its senior unsecured rating of KMI from BBB to BBB+ largely based on KMI's ability to fund growth capital mainly with internally generated cash flow and favorable leverage levels. Moody's and S&P have KMI's senior unsecured rating at Baa2 and BBB, respectively, and both have the rating on positive outlook. Natural Gas Pipelines TGP has entered into binding firm transportation agreements with an anchor shipper to support its approximately $93 million South Texas Enhancement Project (STEP). The project is designed to provide additional firm transportation from receipt points near Agua Dulce, Texas, to the U.S.-Mexico border. With the receipt of all permits and approvals, STEP is expected to enter service in the second quarter of 2028. Right-of-way acquisition and permitting are progressing on KMI's approximately $1.8 billion Trident Intrastate Pipeline. The roughly 216-mile, 2.0 Bcf/d project is designed to provide high-demand natural gas transportation service from Katy, Texas, to the industrial corridor near Port Arthur, Texas. With the receipt of all permits and approvals, KMI expects the project to be in service in the first quarter of 2027. TGP continues to develop its $1.7 billion Mississippi Crossing (MSX) project with stakeholder outreach and right-of-way acquisition activities underway after filing its certificate application with FERC earlier this year. The project is designed to transport up to 2.1 Bcf/d of natural gas to Southeast markets through the construction of approximately 208 miles of 42-inch and 36-inch pipeline and three new compressor stations. MSX will originate near Greenville, Mississippi, and connect to the existing TGP system and multiple third-party pipelines to provide critical access to natural gas sourced from multiple supply basins for delivery to Southern Natural Gas (SNG) and Transco near Butler, Alabama. With the receipt of all permits and approvals, the project is expected to be in service in the fourth quarter of 2028. The company continues its stakeholder outreach activities for its SNG and Elba Express Company's (EEC) South System Expansion 4 (SSE4) project after filing for its FERC certificate earlier this year. The approximately $3.5 billion project (KM-share, including EEC, approximately $1.8 billion) is designed to increase SNG's South Main Line capacity by approximately 1.3 Bcf/d. SSE4 will be completed in two phases and is almost entirely comprised of brownfield looping and horsepower compression additions on the SNG and EEC pipeline systems. With the receipt of all permits and approvals, KMI expects to place the first phase of the project in service in the fourth quarter of 2028 and the second phase in the fourth quarter of 2029. The company's development of the Hiland Express project remains on track with the conversion of its Double H Pipeline system from crude oil to natural gas liquids (NGL) service, providing Williston Basin producers and midstream companies with pipeline capacity to key market hubs. The approximately $150 million project is anticipated to be in service near the end of the first quarter of 2026. Future phases could provide incremental pipeline capacity, including out of the Powder River Basin. The approximately $263 million Altamont Green River Pipeline project was placed in service in September 2025. The project provides additional natural gas egress to relieve existing production constraints in the Uinta Basin, resulting in the delivery of approximately 150 million cubic feet per day (MMcf/d) of capacity from the basin to the Western Chipeta processing plant. Products Pipelines On October 20, 2025, Phillips 66 and KMI launched a binding open season for transportation service on the Western Gateway Pipeline, a newly proposed refined products pipeline system. The Western Gateway Pipeline will facilitate the transportation of refined products from origin points in Texas to key downstream markets in Arizona and California, with connectivity to Las Vegas, Nevada. Interested customers will be able to make take-or-pay volume commitments for domestic grade gasoline, diesel, and jet products. The open season is scheduled to run through December 19, 2025. Following the successful open season, the Western Gateway Pipeline and KMI's SFPP's East Line will be jointly owned by Phillips 66 and KMI. On September 26, 2025, KMI successfully completed its most recent open season for SFPP's East Line expansion capacity to Tucson, Arizona. The project will create an additional 2,500 barrels per day of diesel capacity to Tucson and is fully supported by long-term, take-or-pay customer commitments. With the receipt of all permits and approvals, the expansion is expected to be in-service no later than April 1, 2026. Kinder Morgan, Inc. (NYSE: KMI) is one of the largest energy infrastructure companies in North America. Access to reliable, affordable energy is a critical component for improving lives around the world. We are committed to providing energy transportation and storage services in a safe, efficient, and environmentally responsible manner for the benefit of the people, communities and businesses we serve. We own an interest in or operate approximately 79,000 miles of pipelines, 139 terminals, more than 700 Bcf of working natural gas storage capacity and have renewable natural gas generation capacity of approximately 6.9 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks. Learn more about our work advancing energy solutions on the lower carbon initiatives page at www.kindermorgan.com. Please join Kinder Morgan, Inc. at 4:30 p.m. ET on Wednesday, October 22, at www.kindermorgan.com for a LIVE webcast conference call on the company's third quarter earnings. Non-GAAP Financial Measures As described in further detail below, our management evaluates our performance primarily using Net income attributable to Kinder Morgan, Inc. and Segment earnings before DD&A expenses (EBDA), along with the non-GAAP financial measures of Adjusted Net income attributable to Common Stock, in the aggregate and per share, Adjusted Segment EBDA, Adjusted Net income attributable to Kinder Morgan, Inc., Adjusted earnings before interest, income taxes, DD&A expenses and amortization of basis differences related to our joint ventures (previously known as amortization of excess cost of equity investments) (EBITDA), and Net Debt. Our non-GAAP financial measures described below should not be considered alternatives to GAAP net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its decision-making processes. Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in net income attributable to Kinder Morgan, Inc., but typically either (1) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (2) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the accompanying Tables 2, 3, 5, and 6.) We also include adjustments related to joint ventures (see "Amounts associated with Joint Ventures" below). The following table summarizes our Certain Items for the three and nine months ended September 30, 2025 and 2024. Adjusted Net Income Attributable to Kinder Morgan, Inc. (KMI) is calculated by adjusting net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. is used by us, investors, and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is net income attributable to Kinder Morgan, Inc. (See the accompanying Tables 1 and 2.) Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities. We believe Adjusted Net Income Attributable to Common Stock allows for calculation of adjusted earnings per share (Adjusted EPS) on the most comparable basis with earnings per share, the most comparable GAAP measure to Adjusted EPS. Adjusted EPS is calculated as Adjusted Net Income Attributable to Common Stock divided by our weighted average shares outstanding. Adjusted EPS applies the same two-class method used in arriving at basic earnings per share. Adjusted EPS is used by us, investors, and other external users of our financial statements as a per-share supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. (See the accompanying Table 2.) Adjusted Segment EBDA is calculated by adjusting segment earnings before DD&A, general and administrative expenses and corporate charges, interest expense, and income taxes (Segment EBDA) for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors, and other external users of our financial statements additional insight into performance trends across our business segments, our segments' relative contributions to our consolidated performance, and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment's performance. (See the accompanying Table 3.) Adjusted EBITDA is calculated by adjusting net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A, amortization of basis differences related to our joint ventures, income tax expense, and interest. We also include amounts from joint ventures for income taxes and DD&A (see "Amounts associated with Joint Ventures" below). Adjusted EBITDA (on a rolling 12-months basis) is used by management, investors, and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net income attributable to Kinder Morgan, Inc. (See the accompanying Tables 2 and 5.) Amounts associated with Joint Ventures - Certain Items and Adjusted EBITDA reflect amounts from unconsolidated joint ventures (JVs) and consolidated JVs utilizing the same recognition and measurement methods used to record "Earnings from equity investments" and "Noncontrolling interests (NCI)," respectively. The calculation of Adjusted EBITDA related to our unconsolidated and consolidated JVs include the same adjustments (DD&A, amortization of basis differences, and income tax expense) with respect to the JVs as those included in the calculation of Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. (See Tables 2, 5 and 6.) Although these amounts related to our unconsolidated JVs are included in the calculation of Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated JVs. Net Debt is calculated by subtracting from debt (1) cash and cash equivalents, (2) debt fair value adjustments, and (3) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA (on a rolling 12-months basis) as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors, and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt as reconciled in the notes to the accompanying Preliminary Consolidated Balance Sheets in Table 5. Project EBITDA is calculated for an individual capital project as earnings before interest expense, taxes, DD&A, and general and administrative expenses attributable to such project, or for JV projects, consistent with the methods described above under "Amounts associated with Joint Ventures," and in conjunction with capital expenditures for the project, is the basis for our Project EBITDA multiple. Management, investors, and others use Project EBITDA to evaluate our return on investment for capital projects before expenses that are generally not controllable by operating managers in our business segments. We believe the GAAP measure most directly comparable to Project EBITDA is the portion of net income attributable to a capital project. We do not provide the portion of budgeted net income attributable to individual capital projects (the GAAP financial measure most directly comparable to Project EBITDA) due to the impracticality of predicting, on a project-by-project basis through the second full year of operations, certain amounts required by GAAP, such as projected commodity prices, unrealized gains and losses on derivatives marked to market, and potential estimates for certain contingent liabilities associated with the project completion. FCF is calculated by reducing cash flow from operations for capital expenditures (sustaining and expansion), and FCF after dividends is calculated by further reducing FCF for dividends paid during the period. FCF is used by management, investors, and other external users as an additional leverage metric, and FCF after dividends provides additional insight into cash flow generation. Therefore, we believe FCF is useful to our investors. We believe the GAAP measure most directly comparable to FCF is cash flow from operations. (See the accompanying Table 6.) Important Information Relating to Forward-Looking Statements This news release includes forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934. Generally the words "expects," "believes," "anticipates," "plans," "will," "shall," "estimates," "projects," and similar expressions identify forward-looking statements, which are generally not historical in nature. Forward-looking statements in this news release include, among others, express or implied statements pertaining to: the long-term demand for KMI's assets and services; KMI's 2025 expectations; anticipated dividends; KMI's capital projects, including the regulatory environment for projects and expected costs, completion timing and benefits of those projects; and proposed joint ventures. Forward-looking statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management, based on information currently available to them. Although KMI believes that these forward-looking statements are based on reasonable assumptions, it can give no assurance as to when or if any such forward-looking statements will materialize nor their ultimate impact on our operations or financial condition. Important factors that could cause actual results to differ materially from those expressed in or implied by these forward-looking statements include: the timing and extent of changes in the supply of and demand for the products we transport and handle; trends expected to drive new natural gas demand for electricity generation; commodity prices; counterparty financial risk; changes in tariffs and trade restrictions, including potential adverse effects on financial and economic conditions; the results of the Western Gateway Pipeline open season and KMI's ability to negotiate terms of the proposed joint venture with Phillips 66; and the other risks and uncertainties described in KMI's reports filed with the Securities and Exchange Commission (SEC), including its Annual Report on Form 10-K for the year-ended December 31, 2024 (under the headings "Risk Factors" and "Information Regarding Forward-Looking Statements" and elsewhere), and its subsequent reports, which are available through the SEC's EDGAR system at www.sec.gov and on our website at ir.kindermorgan.com. Forward-looking statements speak only as of the date they were made, and except to the extent required by law, KMI undertakes no obligation to update any forward-looking statement because of new information, future events or other factors. Because of these risks and uncertainties, readers should not place undue reliance on these forward-looking statements. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022461205/en/ back
Clean Energy to Launch New Freightliner X15N Demo Truck Program at ATA's MCE in San Diego
Clean Energy to Launch New Freightliner X15N Demo Truck Program at ATA's MCE in San Diego NEWPORT BEACH, Calif., Oct. 22 /BusinessWire/ -- Clean Energy Fuels Corp. (NASDAQ: CLNE), the largest provider of renewable natural gas (RNG) for the transportation industry, has announced the launch of its second heavy-duty truck demo program, featuring the 2026 Freightliner Cascadia Gen 5 day cab equipped with the Cummins X15N natural gas engine. This press release features multimedia. View the full release here: https://www.businesswire.com/news/home/20251022704849/en/Clean Energy's Freightliner Cascadia Gen 5 demo truck with Cummins X15N natural gas engine. The new truck will be showcased at the American Trucking Associations' Management Conference & Exhibition (ATA MCE) in San Diego from October 25-28, offering attendees an exclusive preview before the program launches with its debut fleet partner. This new program builds on the success of Clean Energy's first Peterbilt X15N demo truck program which was launched last year. The first demo truck has been praised by fleets who have operated it for the engine's smooth handling through different terrains, impressive torque, per gallon savings running on RNG, and fuel efficiency, reinforcing the X15N's potential to reshape the future of low-carbon heavy-duty trucking. "Through one of the most tumultuous times in the history of the freight industry with evolving regulatory changes, impacts of tariffs, and overall economic uncertainty, the X15N/RNG solution has come out a clear winner for both carriers and shippers," said Chad Lindholm, senior vice president at Clean Energy. "The Cummins X15N truly is a game-changer, providing equivalent power and torque as its diesel equivalent, yet allowing fleets to claim significant carbon and NOx emission reductions with a fuel that is priced at a big discount to diesel. The reason we have a waiting list to test our demo trucks is because despite regulatory easing, operators of fleets and their customers continue to want to have the cleanest trucks. Viable electric and fuel cell options are years and years from becoming an affordable reality. RNG is the only solution that is here today, affordable, and clean." Clean Energy's demo truck program will give fleets across the country the opportunity to experience first-hand the capabilities of the Freightliner Cascadia Gen 5 equipped with the X15N. Participating carriers will be able to fuel at Clean Energy's network of RNG stations nationwide, showcasing the ease of integrating low-carbon fueling into their own fleet operations. The Cummins X15N engine is designed to run on RNG - a biogenic fuel derived from organic waste such as dairy manure. It offers a powerful, reliable, cleaner alternative to diesel, and fleets fueling with RNG can reduce emissions by more than 300 percent, achieving negative carbon-intensity results, while spending less per gallon of fuel. The X15N is quickly earning a reputation for performance and sustainability with major carriers including Walmart, Amazon, UPS, FedEx, Werner, Knight Swift, Food Express, Cemex and Mullen Group having placed orders for the new engine. The demo truck will travel through key freight corridors in California, Texas, Arizona, Illinois, Ohio, Michigan, Pennsylvania, Florida, and other states, allowing large and mid-sized fleets to try and test the engine's capabilities in real-world conditions. The program is expected to run through 2028 or longer, as demand and interest continue to grow. For more information about Clean Energy's demo truck program, please visit: www.cleanenergyfuels.com/x15n About Clean Energy Clean Energy Fuels Corp. is the country's largest provider of the cleanest fuel for the transportation market. Our mission is to decarbonize transportation through the development and delivery of renewable natural gas (RNG), a sustainable fuel derived by capturing methane from organic waste. Clean Energy allows thousands of vehicles, from airport shuttles to city buses to waste and heavy-duty trucks, to reduce their amount of climate-harming greenhouse gas. We operate a vast network of fueling stations across the U.S. and Canada as well as RNG production facilities at dairy farms. Visit www.cleanenergyfuels.com and follow @ce_renewables on X and LinkedIn. Forward-Looking Statements This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 that involve risks, uncertainties and assumptions, including without limitation statements about: the scope and timeframe of the demo truck program; the characteristics and performance of natural gas engines and trucks; the potential development of the market for RNG; the availability of environmental, tax and other government regulations, programs and incentives; the impacts of legislative and regulatory developments; and the environmental and other benefits of Clean Energy's fuels. Actual results and the timing of events could differ materially from those anticipated in these forward-looking statements. The forward-looking statements made herein speak only as of the date of this press release and, unless otherwise required by law, Clean Energy undertakes no obligation to publicly update such forward-looking statements to reflect subsequent events or circumstances. Additionally, the reports and other documents Clean Energy files with the SEC (available at www.sec.gov) contain risk factors, which may cause actual results to differ materially from the forward-looking statements contained in this news release. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022704849/en/ back
Venture Global Statement on CP2 Final Approval
Venture Global Statement on CP2 Final Approval ARLINGTON, Va., Oct. 22 /BusinessWire/ -- The U.S. Department of Energy issued the final non-FTA export authorization for Venture Global's CP2 facility in Cameron Parish, Louisiana. Venture Global CEO Mike Sabel issued the following statement: "Venture Global is grateful for the Trump Administration's final approval of CP2, a critical project that will supply American allies with low-cost LNG for decades, support thousands of jobs and greatly benefit the U.S. balance of trade. The CP2 project construction is well underway and we look forward to continue advancing the project safely and quickly to bring new LNG to the global market at a record pace beginning in 2027." About Venture Global Venture Global is an American producer and exporter of low-cost U.S. liquefied natural gas (LNG) with over 100 MTPA of capacity in production, construction, or development. Venture Global began producing LNG from its first facility in 2022 and is now one of the largest LNG exporters in the United States. The company's vertically integrated business includes assets across the LNG supply chain including LNG production, natural gas transport, shipping and regasification. The company's first three projects, Calcasieu Pass, Plaquemines LNG, and CP2 LNG, are located in Louisiana along the Gulf of America. Venture Global is developing Carbon Capture and Sequestration projects at each of its LNG facilities. Forward-looking Statements This press release contains certain statements that may include "forward-looking statements." All statements, other than statements of historical or present facts or conditions, included herein are "forward-looking statements." Included among "forward-looking statements" are, among other things, statements regarding Venture Global's business strategy, plans and objectives. Venture Global believes that the expectations reflected in these "forward-looking statements" are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond Venture Global's control. In addition, assumptions may prove to be inaccurate. Actual results may differ materially from those anticipated or implied in "forward-looking statements" as a result of a variety of factors. These "forward-looking statements" speak only as of the date made, and other than as required by law, Venture Global undertakes no obligation to update or revise any "forward-looking statement" or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise. View source version on businesswire.com: https://www.businesswire.com/news/home/20251022894186/en/ back
Sky Quarry and Continuum Move Closer to Launching Real-World Asset Tokens and Exchange Platform
Sky Quarry and Continuum Move Closer to Launching Real-World Asset Tokens and Exchange Platform Partnership advances framework to simplify how investors access commodity-linked assets while expanding Sky Quarry's capital optionsWOODS CROSS, Utah, Oct. 22, 2025 (GLOBE NEWSWIRE) -- Sky Quarry Inc. (NASDAQ:SKYQ) ("Sky Quarry" or the "Company"), an integrated energy solutions company committed to transforming the waste asphalt shingle recycling industry, today announced significant progress in its partnership with Continuum Network, accelerating work that began with the signing of a Memorandum of Understanding (MOU) in August 2025. Under the collaboration, Sky Quarry and Continuum are working to establish a clear framework for tokenizing energy-linked commodities and developing the digital infrastructure needed to support a modernized treasury model. Since signing the MOU, the parties have advanced both technical and operational workstreams and are preparing to launch the token creation process and functional exchange interface. A New Model for Unlocking Energy Asset Value Real-World Asset (RWA) tokenization is the process of converting rights in tangible assets into secure digital tokens on a blockchain. For Sky Quarry, this means creating tokens that give investors clear claims tied directly to the underlying asset, rather than company stock. "In the past, companies often sat on valuable assets and could only access them through traditional financing channels," said Marcus Laun, President and Interim Chief Executive Officer of Sky Quarry. "What we're doing with Continuum flips that model. Tokenization connects assets directly with investors in a way that's transparent and efficient. These tokens aren't company stock - they're designed to be simple, easy to understand, and always backed by something real and verifiable. For Sky Quarry, we believe that it will open new and more flexible ways to raise capital and strengthen our balance sheet. We believe this approach puts us ahead of the curve in showing how traditional industries can use digital tools to unlock new opportunities." How It Works: Tokens vs. Equity To ensure regulatory clarity, Sky Quarry will keep equity and token purchases entirely distinct. Investors can continue to purchase shares in Sky Quarry through standard equity transactions, giving them ownership rights in the company. Separately, the Company intends to create tokens tied to its oil assets. We intend to sell these tokens in separate transactions, and they will be priced based on the current market price of oil. Sky Quarry also plans to use its own token treasury to create working capital by pledging these oil tokens to suppliers as collateral for crude oil purchases at its refinery. We believe that this strategy will allow the Company to leverage assets already on its balance sheet, creating liquidity without diluting our equity holders or incurring additional debt. Market Context: A Global Opportunity Energy reserves represent one of the largest pools of untapped asset value in the world. According to OPEC, global proven crude reserves totaled approximately 1.567 trillion barrels in 2024.¹ Independent and mid-cap oil producers - critical contributors to regional supply - often face tight liquidity constraints, particularly during commodity price volatility. Many of these companies are forced to keep reserves off balance sheet because traditional financing channels offer limited marketability. We believe that tokenization addresses this challenge by converting these reserves into blockchain-based instruments. It allows fractional ownership, improves transparency, and introduces new forms of liquidity that were previously inaccessible. Market Opportunity and Liquidity Potential Applying even modest adoption rates to this model demonstrates the scale of the opportunity: If just 10-15% of producing reserves and 5% of undeveloped reserves were tokenized, it could unlock an estimated $750 billion to $1 trillion in global liquidity.Tokenized reserves can be structured to function similarly to other commodity-linked instruments, while enabling efficient fractionalization and direct investor access. These estimates are derived from upstream asset valuations and current RWA tokenization comparables, underscoring the significant capital formation potential. Use Case: Enhancing Working Capital Traditional reserve-based lending (RBL) typically caps loan-to-value ratios at 30-40% of proved producing reserves.² This structure limits liquidity for producers. By tokenizing a portion of PDP reserves, producers can: Issue asset-backed tokens and broaden investor participationPotentially reduce financing costsAccess instant secondary market liquidityPledge tokens as collateral to support operations For Sky Quarry, this means the potential to transform warehoused energy assets into a digital treasury - increasing financial flexibility without diluting shareholders or taking on conventional debt. Key Market Drivers Tightening credit markets: In Q3 2025, 9.5% of U.S. banks reported tightening standards for commercial and industrial loans.³Mature infrastructure: Tokenization platforms now offer qualified custody, KYC/AML compliance, and smart contract auditing at institutional-grade levels.ESG alignment: Pairing reserve-backed tokens with verified carbon credits can attract sustainability-focused investors, opening new pools of capital. U.S. Impact and Illustrative Scenario If 1% of total U.S. proved reserves (approximately $400 billion) were tokenized, roughly $4 billion in new liquidity could be generated annually. At 10% adoption, this expands to $40-50 billion. Based on internal modeling, integrating verified carbon credit streams could raise combined digital asset capitalization to $60-70 billion over the next decade. Implementation Considerations Tokenization requires rigorous execution to ensure credibility and compliance: Accurate and transparent reserve auditingRobust legal structuringClear regulatory frameworksSecure custody and investor protections These factors are critical to mitigating valuation, governance, and compliance risks as the market scales. References¹ OPEC Annual Statistical Bulletin 2025 - World Proven Crude Oil Reserves.² Norton Rose Fulbright (2024). Reserve-Based Lending: Market Overview and Trends.³ U.S. Federal Reserve (2025). Senior Loan Officer Opinion Survey on Bank Lending Practices (SLOOS). Continuum Network: Bringing Real Assets On-Chain Continuum Network brings deep expertise in secure blockchain infrastructure, investor verification, and automated digital contracting to support transparent and compliant token issuance. "The pace of progress demonstrates the strength of this collaboration," said Mehdi Mehrtash, Founder of Continuum Network. "Our platform is purpose-built to securely support real-world assets with full transparency and auditability, without the complexity often associated with blockchain. For investors, that means no need to manage crypto wallets or pay transaction fees. Tokens can be held and traded simply, with full transparency. By removing that friction, we make it easier for institutions and individuals to participate with confidence." Strategic Vision for Sky Quarry "The reason this is so compelling is that there are thousands of smaller companies operating across the energy industry," said Marcus Laun. "Tokenization can unlock billions in additional working capital, making the industry more efficient and more profitable. We intend to market our tokenization products to the sector while using our own assets and operations as a real-world demonstration platform. We've already begun discussions with counterparties and are evaluating additional assets for tokenization. It's a very exciting time." He continued, "We believe that the advantage of this strategy is that it isn't dilutive to the share structure and will complement our broader digital asset treasury initiative and directly strengthen our balance sheet." About Continuum Network Continuum Network is redefining enterprise blockchain with a gasless, public-permissioned EVM platform that removes the cost, complexity, and barriers to adoption of Decentralized Ledger Technology (DLT). By combining zero-trust architecture, decentralized identity (DID) standards, and asset-based encryption, Continuum enables organizations to verify identity, compliance, and data ownership without exposing sensitive information. Built for universal integration and global regulatory alignment, the platform empowers industries worldwide, from finance and energy to healthcare, manufacturing, logistics, and government, to operate with transparency, accountability, and trust. Continuum Network delivers the secure and scalable foundation needed for a more connected and resilient digital economy. About Sky Quarry Inc. Sky Quarry Inc. (NASDAQ:SKYQ) and its subsidiaries are, collectively, an oil production, refining, and a development-stage environmental remediation company formed to deploy technologies to facilitate the recycling of waste asphalt shingles and remediation of oil-saturated sands and soils. Our waste-to-energy mission is to repurpose and upcycle millions of tons of asphalt shingle waste, diverting them from landfills. By doing so, we can contribute to improved waste management, promote resource efficiency, conserve natural resources, and reduce environmental impact. For more information, please visit skyquarry.com. Forward-Looking Statements This press release may include ''forward-looking statements.'' All statements pertaining to our future financial and/or operating results, future events, or future developments may constitute forward-looking statements. The statements may be identified by words such as "expect," "look forward to," "anticipate," "intend," "plan," "believe," "seek," "estimate," "will," "project," or words of similar meaning. Such statements are based on the current expectations and certain assumptions of our management, of which many are beyond our control. These are subject to a number of risks, uncertainties, and factors, including but not limited to those described in our disclosures. Should one or more of these risks or uncertainties materialize or should underlying expectations not occur or assumptions prove incorrect, actual results, performance, or our achievements may (negatively or positively) vary materially from those described explicitly or implicitly in the relevant forward-looking statement. We neither intend, nor assume any obligation, to update or revise these forward-looking statements in light of developments which differ from those anticipated. You are urged to carefully review and consider any cautionary statements and the Company's other disclosures, including the statements made under the heading "Risk Factors" and elsewhere in the Company's Form 10-K as filed with the SEC on March 31, 2025, and all amendments thereto, as well as the Company's Form 10-Q as filed with the SEC on August 14, 2025. Forward-looking statements speak only as of the date of the document in which they are contained. Investor Relations Jennifer Standley Director of Investor RelationsIr@skyquarry.com Company Website www.skyquarry.com
Gulfport Energy Schedules Third Quarter 2025 Earnings Release and Conference Call
Gulfport Energy Schedules Third Quarter 2025 Earnings Release and Conference Call OKLAHOMA CITY, Oct. 21 /BusinessWire/ -- Gulfport Energy Corporation (NYSE:GPOR) announced today that it will host a teleconference and webcast to discuss its third quarter 2025 financial and operating results beginning at 9:00 a.m. ET (8:00 a.m. CT) on Wednesday, November 5, 2025. Gulfport plans to announce third quarter 2025 results on Tuesday, November 4, 2025, after market close. The conference call can be heard live through a link on the Gulfport website, www.gulfportenergy.com. In addition, you may participate in the conference call by dialing 866-373-3408 domestically or 412-902-1039 internationally. A replay of the conference call will be available on the Gulfport website and a telephone audio replay will be available from November 5, 2025 to November 19, 2025, by calling 877-660-6853 domestically or 201-612-7415 internationally and then entering the replay passcode 13756501. About Gulfport Gulfport is an independent, natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and NGL in the United States with primary focus in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus formations and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. View source version on businesswire.com: https://www.businesswire.com/news/home/20251021671632/en/ back
EQT Reports Third Quarter 2025 Results
EQT Reports Third Quarter 2025 Results PITTSBURGH, Oct. 21, 2025 /PRNewswire/ -- EQT Corporation (NYSE: EQT) today announced financial and operational results for the third quarter of 2025. Third Quarter 2025 Results: Production: Sales volume of 634 Bcfe, toward the high-end of guidance driven by strong well performance and compression project outperformance Capital Expenditures: $618 million, 10% below the mid-point of guidance due to continued efficiency gains and midstream cost optimization Realized Pricing: Differential $0.12 tighter than the mid-point of guidance due to strong gas marketing optimization results and tactical curtailment strategy Operating Costs: Record low per unit operating costs of $1.00 per Mcfe, 7% below the mid-point of guidance driven by lower-than-expected gathering, LOE and SG&A expense Cash Flow: Net cash provided by operating activities of $1,018 million; generated $484 million of free cash flow attributable to EQT(1) Balance Sheet: Exited the quarter with $8.2 billion total debt and just under $8.0 billion net debt(1) Recent Highlights: Olympus Integration: Achieved operational integration of all upstream and midstream assets acquired from Olympus Energy 34 days after closing, the fastest operational transition in EQT's acquisition history; drilled two deep Utica wells ~30% faster than Olympus' historic performance, saving $2 million per well Operational Efficiencies: Set multiple EQT records, including highest pumping hours in a month, fastest quarterly completion pace and the most lateral footage drilled and completed in a 24-hour period MVP Boost: Exceptionally strong and oversubscribed open season with capacity upsized by 20% to 600 MDth/d due to strong utility demand; projected build multiple of approximately 3.0x adjusted EBITDA(1) LNG Offtake: Signed LNG offtake agreements for 4.5 million tonnes per annum in aggregate with Sempra, NextDecade and Commonwealth LNG beginning in 2030-2031; represents patient and successful execution of LNG strategy underpinned by direct connectivity to end users globally Dividend Increased: Increased dividend by 5% to $0.66 per share, annualized; compounded annual dividend growth rate of ~8% since 2022 with durability underpinned by material cost structure improvements and synergy capture over this period President and CEO Toby Z. Rice stated, "Third quarter results built upon EQT's extensive track record of delivering operational and financial outperformance. Production, operating expenses, capital spending and price realizations were all at the favorable end of guidance, highlighting the efficiency gains and tangible synergy capture of our vertically integrated platform. We rapidly integrated the Olympus assets and are already seeing material operational outperformance with EQT at the helm. Simply put, our execution machine is firing on all cylinders, and the benefits are accruing to shareholders via significant free cash flow outperformance relative to both internal and consensus expectations." Rice continued, "We also completed the highly successful MVP Boost open season and elected to upsize capacity to 600 MDth/d due to strong demand from leading utilities. This project will provide gas supply from Appalachia into Northern Virginia and the Southeast regions, unleashing affordable, reliable, low emissions natural gas into areas that are seeing significant demand growth. MVP Boost represents just one of several strategic growth initiatives in our project pipeline, which offer highly attractive, full cycle returns and create the option to sustainably grow our upstream business in the years ahead." (1) A non-GAAP financial measure. See the Non-GAAP Disclosures section of this news release for the definition of, and other important information regarding, this non-GAAP financial measure. Third Quarter 2025 Financial and Operational Performance Three Months Ended September 30, ($ millions, except average realized price and EPS) 2025 2024 Change Total sales volume (Bcfe) 634 581 53 Average realized price ($/Mcfe) $ 2.76 $ 2.38 $ 0.38 Net income (loss) attributable to EQT $ 336 $ (301) $ 637 Adjusted net income attributable to EQT (a) $ 329 $ 91 $ 238 Diluted income (loss) per share (EPS) $ 0.53 $ (0.54) $ 1.07 Adjusted EPS (a) $ 0.52 $ 0.16 $ 0.36 Net income (loss) $ 407 $ (297) $ 704 Adjusted EBITDA (a) $ 1,328 $ 832 $ 496 Adjusted EBITDA attributable to EQT (a) $ 1,200 $ 824 $ 376 Net cash provided by operating activities $ 1,018 $ 593 $ 425 Adjusted operating cash flow (a) $ 1,221 $ 522 $ 699 Adjusted operating cash flow attributable to EQT (a) $ 1,094 $ 517 $ 577 Capital expenditures $ 618 $ 558 $ 60 Capital contributions to equity method investments $ 2 $ 85 $ (83) Free cash flow (a) $ 601 $ (121) $ 722 Free cash flow attributable to EQT (a) $ 484 $ (125) $ 609 (a) A non-GAAP financial measure. See the Non-GAAP Disclosures section of this news release for the definition of, and other important information regarding, this non-GAAP financial measure. Per Unit Operating CostsThe following table presents certain of the Company's consolidated operating costs on a per unit basis.(a) Three Months Ended September 30, Nine Months Ended September 30, Per Unit ($/Mcfe) 2025 2024 2025 2024 Gathering $ 0.06 $ 0.20 $ 0.07 $ 0.44 Transmission 0.40 0.43 0.43 0.37 Processing 0.13 0.13 0.14 0.13 Lease operating expense (LOE) 0.09 0.09 0.09 0.09 Production taxes 0.06 0.07 0.07 0.08 Operating and maintenance (O&M) 0.10 0.07 0.09 0.04 Selling, general and administrative (SG&A) 0.16 0.15 0.15 0.14 Operating costs $ 1.00 $ 1.14 $ 1.04 $ 1.29 Production depletion $ 0.95 $ 0.91 $ 0.95 $ 0.90 (a) References in this release to the "Company" refer to EQT Corporation together with its consolidated subsidiaries. As used throughout this release, per unit operating costs reflect, for each period presented, the consolidated amount of such operating cost for the Company (aggregated irrespective of business segment) divided by total sales volume (Mcfe). Gathering expense per Mcfe decreased for the three months ended September 30, 2025 compared to the same period in 2024 due primarily to the Company's ownership of the gathering, transmission and storage assets acquired in the Company's acquisition of Equitrans Midstream Corporation (the Equitrans Midstream Merger) completed in the third quarter of 2024. In addition, gathering expense per unit decreased due to the Company's divestiture of assets in Northeast Pennsylvania completed in December 2024 and increased sales volume. Transmission expense per Mcfe decreased for the three months ended September 30, 2025 compared to the same period in 2024 due primarily to increased sales volume. O&M expense per Mcfe increased for the three months ended September 30, 2025 compared to the same period in 2024 as a result of the Company's operation of the gathering, transmission and storage assets acquired in the Equitrans Midstream Merger. Production depletion expense per Mcfe increased for the three months ended September 30, 2025 compared to the same period in 2024 due to increased sales volume and higher annual depletion rate. LiquidityAs of September 30, 2025, the Company had no borrowings outstanding under EQT Corporation's $3.5 billion revolving credit facility. Total liquidity, excluding available capacity under Eureka Midstream, LLC's (Eureka Midstream) revolving credit facility, as of September 30, 2025 was $3.7 billion. As of September 30, 2025, total debt and net debt(1) were $8.2 billion and $8.0 billion, respectively, compared to $9.3 billion and $9.1 billion, respectively, as of December 31, 2024. (1) A non-GAAP financial measure. See the Non-GAAP Disclosures section of this news release for the definition of, and other important information regarding, this non-GAAP financial measure. Fourth Quarter 2025 OutlookThe Company expects total sales volume of 550 - 600 Bcfe in the fourth quarter of 2025, which includes the impact of 15 - 20 Bcfe of strategic curtailments. Total capital expenditures in the fourth quarter of 2025 are expected to be $635 - $735 million, including $555 - $635 million of maintenance capital expenditures. The Company plans to turn-in-line (TIL) 18 - 28 net wells in the fourth quarter of 2025. 2025 Guidance Production Q4 2025 Full Year 2025 Total sales volume (Bcfe) 550 - 600 2,325 - 2,375 Liquids sales volume, excluding ethane (Mbbl) 4,100 - 4,400 16,400 - 16,700 Ethane sales volume (Mbbl) 1,700 - 1,850 7,150 - 7,300 Total liquids sales volume (Mbbl) 5,800 - 6,250 23,550 - 24,000 Btu uplift (MMBtu/Mcf) 1.055 - 1.065 1.055 - 1.065 Average differential ($/Mcf) ($0.60) - ($0.50) ($0.60) - ($0.50) Resource Counts Top-hole rigs 2 - 3 2 - 3 Horizontal rigs 3 - 4 3 - 4 Frac crews 2 - 3 2 - 3 Third-party Midstream Revenue ($ Millions) $135 - $160 $590 - $615 Per Unit Operating Costs ($/Mcfe) Gathering $0.07 - $0.09 $0.07 - $0.09 Transmission $0.42 - $0.44 $0.42 - $0.44 Processing $0.13 - $0.15 $0.13 - $0.15 LOE $0.10 - $0.12 $0.09 - $0.11 Production taxes $0.06 - $0.08 $0.07 - $0.09 O&M $0.09 - $0.11 $0.09 - $0.11 SG&A $0.19 - $0.21 $0.16 - $0.18 Operating costs $1.06 - $1.20 $1.03 - $1.17 Equity Method Investments and Midstream JV Noncontrolling Interest ($ Millions) Distributions from Mountain Valley Pipeline, LLC (the MVP Joint Venture) and Laurel Mountain Midstream, LLC (LMM) $45 - $55 $250 - $260 Distributions to Pipebox LLC (the Midstream JV) Noncontrolling Interest (a) $90 - $105 $350 - $365 Capital Expenditures and Capital Contributions ($ Millions) Upstream maintenance $420 - $480 $1,540 - $1,600 Midstream maintenance $90 - $100 $280 - $290 Corporate & capitalized costs $45 - $55 $190 - $200 Total maintenance capital expenditures $555 - $635 $2,010 - $2,090 Strategic growth capital expenditures $80 - $100 $290 - $310 Total capital expenditures $635 - $735 $2,300 - $2,400 Capital contributions to equity method investments (b) $35 - $45 $80 - $90 (a) Assumes Midstream JV cash distributions of 60% to third-party noncontrolling interest. (b) Includes capital contributions to the MVP Joint Venture (including the MVP mainline, MVP Southgate and MVP Boost) and LMM. Third Quarter 2025 Earnings Webcast InformationThe Company's conference call with securities analysts begins at 10:00 a.m. ET on Wednesday October 22, 2025 and will be broadcast live via webcast. An accompanying presentation is available on the Company's investor relations website, www.ir.eqt.com under "Events & Presentations." To access the live audio webcast, visit the Company's investor relations website at ir.eqt.com. A replay will be archived and available for one year in the same location after the conclusion of the live event. Hedging (as of October 15, 2025)The following table summarizes the approximate volume and prices of the Company's NYMEX hedge positions. The difference between the fixed price and NYMEX price is included in average differential presented in the Company's price reconciliation. Q4 2025 (a) Q1 2026 Q2 2026 Q3 2026 Q4 2026 Q1 2027 Hedged Volume (MMDth) 332 80 31 29 27 9 Hedged Volume (MMDth/d) 3.6 0.9 0.3 0.3 0.3 0.1 Swaps - Short Volume (MMDth) 95 - - - - - Avg. Price ($/Dth) $ 3.28 $ - $ - $ - $ - $ - Calls - Short Volume (MMDth) 189 80 31 29 27 9 Avg. Strike ($/Dth) $ 5.34 $ 5.77 $ 4.22 $ 4.17 $ 4.35 $ 4.25 Puts - Long Volume (MMDth) 237 80 31 29 27 9 Avg. Strike ($/Dth) $ 3.35 $ 3.79 $ 3.31 $ 3.29 $ 3.40 $ 3.30 Option Premiums Cash Settlement of Deferred Premiums (millions) $ (45) $ - $ - $ - $ - $ - (a) October 1 through December 31. The Company has also entered into transactions to hedge basis. The Company may use other contractual agreements from time to time to implement its commodity hedging strategy. Non-GAAP DisclosuresThis news release includes the non-GAAP financial measures described below. These non-GAAP measures are intended to provide additional information only and should not be considered as alternatives to, or more meaningful than, net income attributable to EQT Corporation, diluted EPS, net income, net cash provided by operating activities, total Production operating revenues, total debt, or any other measure calculated in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, tax structure, and historic costs of depreciable assets. Adjusted Net Income Attributable to EQT and Adjusted EPSAdjusted net income attributable to EQT is defined as net income (loss) attributable to EQT Corporation, excluding (gain) loss on sale/exchange of long-lived assets, impairments, the revenue impact of changes in the fair value of derivative instruments prior to settlement and certain other items that the Company's management believes do not reflect the Company's core operating performance. Adjusted EPS is defined as adjusted net income attributable to EQT divided by diluted weighted average common shares outstanding. As a result of the Class B Unitholder's noncontrolling equity interest ownership in the Midstream JV that commenced on December 30, 2024, the Company has adjusted its non-GAAP measure of adjusted net income attributable to EQT. Beginning in the first quarter of 2025, adjusted net income attributable to EQT and the related non-GAAP financial measure of adjusted EPS are no longer adjusted for income from investments, distributions received from equity method investments or non-cash interest expense (amortization). Adjusted net income attributable to EQT and adjusted EPS presented in this news release for the comparative period have also been calculated based on the updated definition. The Company's management believes adjusted net income attributable to EQT and adjusted EPS provide useful information to investors regarding the Company's financial condition and results of operations because it helps facilitate comparisons of operating performance and earnings trends across periods by excluding the impact of items that, in their opinion, do not reflect the Company's core operating performance. For example, adjusted net income attributable to EQT and adjusted EPS reflect only the impact of settled derivative contracts; thus, the measures exclude the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. The table below reconciles adjusted net income attributable to EQT and adjusted EPS with net income (loss) attributable to EQT Corporation and diluted EPS, respectively, the most comparable financial measures calculated in accordance with GAAP, each as derived from the Statements of Condensed Consolidated Operations to be included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2025. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands, except per share amounts) Net income (loss) attributable to EQT Corporation $ 335,862 $ (300,823) $ 1,362,148 $ (187,818) (Deduct) add: (Gain) loss on sale/exchange of long-lived assets (5,623) 10,117 (2,402) (309,865) Impairment and expiration of leases 3,476 12,095 9,391 58,963 Gain on derivatives (135,784) (66,816) (176,829) (234,660) Net cash settlements received (paid) on derivatives 74,960 288,136 (118,390) 1,037,321 Premiums paid for derivatives that settled during the period - (4,971) - (44,565) Other expenses (a) 28,962 279,751 182,693 328,913 Loss on debt extinguishment 1,909 365 19,478 5,651 Tax impact of non-GAAP items (b) 24,818 (126,420) 38,774 (235,254) Adjusted net income attributable to EQT $ 328,580 $ 91,434 $ 1,314,863 $ 418,686 Diluted weighted average common shares outstanding 628,324 563,956 611,427 484,526 Diluted EPS $ 0.53 $ (0.54) $ 2.23 $ (0.39) Adjusted EPS $ 0.52 $ 0.16 $ 2.15 $ 0.86 (a) Other expenses consist primarily of transaction costs associated with acquisitions and other strategic transactions and costs related to exploring new venture opportunities. Other expenses for the three and nine months ended September 30, 2025 included the impact of $21.0 million and $24.5 million, respectively, of cash transaction costs related to the Company's acquisition of Olympus Energy (the Olympus Energy Acquisition). In addition, other expenses for the nine months ended September 30, 2025 and 2024 included the impact of $133.7 million and $17.5 million, respectively, of net expense related to a securities class action settlement. (b) The tax impact of non-GAAP items represents the incremental tax expense/benefit that would have been incurred by the Company had these items been excluded from net income (loss) attributable to EQT Corporation, which resulted in a blended tax rate of 24.7% and 24.4% for the three months ended September 30, 2025 and 2024, respectively, and 25.1% and 27.9% for the nine months ended September 30, 2025 and 2024, respectively. The blended tax rates differ from the Company's statutory tax rate due primarily to state taxes, including valuation allowances limiting certain state tax benefits. Adjusted EBITDA, Adjusted EBITDA Attributable to Noncontrolling Interests and Adjusted EBITDA Attributable to EQTAdjusted EBITDA is defined as net income excluding net interest expense, income tax expense (benefit), depreciation, depletion and amortization, (gain) loss on sale/exchange of long-lived assets, impairments, the revenue impact of changes in the fair value of derivative instruments prior to settlement and certain other items that the Company's management believes do not reflect the Company's core operating performance. Adjusted EBITDA attributable to EQT is defined as adjusted EBITDA less adjusted EBITDA attributable to noncontrolling interests. Adjusted EBITDA attributable to noncontrolling interests is defined as the proportionate share of adjusted EBITDA attributable to the third-party ownership interests in the Non-Wholly-Owned Consolidated Subsidiaries (defined below). As a result of the Company's completion of the Equitrans Midstream Merger in July 2024, which meaningfully increased the Company's equity method investments, the Company adjusted its non-GAAP measure of adjusted EBITDA. Beginning in the third quarter of 2024, adjusted EBITDA was changed to include distributions received from equity method investments. In addition, as a result of the Class B Unitholder's noncontrolling equity interest ownership in the Midstream JV that commenced on December 30, 2024, beginning in the first quarter of 2025, the amounts attributable to noncontrolling interests meaningfully impacted the Company's consolidated results, and, therefore, the Company began presenting adjusted EBITDA attributable to noncontrolling interests. Adjusted EBITDA attributable to noncontrolling interests presented in this news release for the prior comparative period has also been calculated based on the updated definition, and, certain prior period amounts have been recast for comparability. The Company's management believes that these measures provide useful information to investors regarding the Company's financial condition and results of operations because they help facilitate comparisons of operating performance and earnings trends across periods by excluding the impact of items that, in their opinion, do not reflect the Company's core operating performance. For example, adjusted EBITDA reflects only the impact of settled derivative instruments and excludes the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. In addition, adjusted EBITDA includes the impact of distributions received from equity method investments, which excludes the impact of depreciation included within equity earnings from equity method investments and helps facilitate comparisons of the core operating performance of the Company's equity method investments. The table below reconciles adjusted EBITDA and adjusted EBITDA attributable to EQT with net income, the most comparable financial measure as calculated in accordance with GAAP, as reported in the Statements of Condensed Consolidated Operations to be included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2025. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands) Net income (loss) $ 407,216 $ (297,432) $ 1,579,290 $ (185,130) Add (deduct): Interest expense, net 109,929 158,299 333,166 268,390 Income tax expense (benefit) 129,266 (104,870) 443,549 (124,790) Depreciation, depletion and amortization 688,382 589,299 1,932,628 1,542,031 (Gain) loss on sale/exchange of long-lived assets (5,623) 10,117 (2,402) (309,865) Impairment and expiration of leases 3,476 12,095 9,391 58,963 Gain on derivatives (135,784) (66,816) (176,829) (234,660) Net cash settlements received (paid) on derivatives 74,960 288,136 (118,390) 1,037,321 Premiums paid for derivatives that settled during the period - (4,971) - (44,565) Other expenses (a) 28,962 279,751 182,693 328,913 Income from investments (44,638) (34,242) (138,274) (36,674) Distributions from equity method investments 69,679 2,212 202,560 11,187 Loss on debt extinguishment 1,909 365 19,478 5,651 Adjusted EBITDA 1,327,734 831,943 4,266,860 2,316,772 Deduct: Adjusted EBITDA attributable to noncontrolling interests (b) (128,230) (7,783) (390,194) (7,339) Adjusted EBITDA attributable to EQT $ 1,199,504 $ 824,160 $ 3,876,666 $ 2,309,433 (a) Other expenses consist primarily of transaction costs associated with acquisitions and other strategic transactions and costs related to exploring new venture opportunities. Other expenses for the three and nine months ended September 30, 2025 included the impact of $21.0 million and $24.5 million, respectively, of cash transaction costs related to the Olympus Energy Acquisition. In addition, other expenses for the nine months ended September 30, 2025 and 2024 included the impact of $133.7 million and $17.5 million, respectively, of net expense related to a securities class action settlement. (b) A non-GAAP financial measure. See below for a reconciliation of this non-GAAP financial measure to the most comparable financial measure as calculated in accordance with GAAP. The Company consolidates its controlling equity interests in the Midstream JV, Eureka Midstream Holdings, LLC (Eureka Midstream Holdings) and Teralytic Holdings Inc. (Teralytic, and, together with the Midstream JV and Eureka Midstream Holdings, the Non-Wholly-Owned Consolidated Subsidiaries). The table below reconciles adjusted EBITDA of the Non-Wholly-Owned Consolidated Subsidiaries and adjusted EBITDA attributable to noncontrolling interests with net income of the Non-Wholly-Owned Consolidated Subsidiaries, the most comparable financial measure as calculated in accordance with GAAP. The Company's management believes adjusted EBITDA attributable to noncontrolling interests provides useful information to investors regarding the impact of the third-party ownership interest in the Non-Wholly-Owned Consolidated Subsidiaries on the Company's financial condition and results of operations. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands) Non-Wholly-Owned Consolidated Subsidiaries: Net income $ 158,088 $ 8,320 $ 500,966 $ 6,366 Add (deduct): Interest expense, net 3,742 5,087 11,014 5,087 Depreciation and amortization 34,879 5,989 96,723 6,707 Loss on sale/exchange of long-lived assets - - 349 - Income from investments (42,078) - (125,652) - Distributions from equity method investments 66,579 - 191,090 - Adjusted EBITDA 221,210 19,396 674,490 18,160 Deduct: Adjusted EBITDA of the Non-Wholly-Owned Consolidated Subsidiaries attributable to EQT (a) (92,980) (11,613) (284,296) (10,821) Adjusted EBITDA attributable to noncontrolling interests $ 128,230 $ 7,783 $ 390,194 $ 7,339 (a) Adjusted EBITDA of the Non-Wholly-Owned Consolidated Subsidiaries attributable to EQT is calculated based on EQT Corporation's current 40% Class A Unitholder share of available cash flow distributions from the Midstream JV, 60% ownership interest in Eureka Midstream Holdings and approximate 34% ownership interest in Teralytic. The Company believes that using its distribution share from the Midstream JV in the calculation of adjusted EBITDA of the Non-Wholly-Owned Consolidated Subsidiaries attributable to EQT best reflects the economic impact of the Company's investment in the Midstream JV on adjusted EBITDA and earnings trends. The Company has not provided projected net income or a reconciliation of projected adjusted EBITDA to projected net income, the most comparable financial measure calculated in accordance with GAAP. Net income includes the impact of depreciation, depletion and amortization expense, income tax expense (benefit), the revenue impact of changes in the projected fair value of derivative instruments prior to settlement and certain other items that impact comparability between periods and the tax effect of such items, which may be significant and difficult to project with a reasonable degree of accuracy. Therefore, projected net income, and a reconciliation of projected adjusted EBITDA to projected net income, are not available without unreasonable effort. Adjusted Operating Cash Flow, Adjusted Operating Cash Flow Attributable to EQT, Free Cash Flow and Free Cash Flow Attributable to EQTAdjusted operating cash flow is defined as net cash provided by operating activities less changes in other assets and liabilities. Adjusted operating cash flow attributable to EQT is defined as adjusted operating cash flow less adjusted EBITDA attributable to noncontrolling interests excluding net interest expense attributable to noncontrolling interests. Free cash flow is defined as adjusted operating cash flow less accrual-based capital expenditures and capital contributions to equity method investments. Free cash flow attributable to EQT is defined as adjusted operating cash flow attributable to EQT less accrual-based capital expenditures and capital contributions to equity method investments excluding the proportionate share of accrual-based capital expenditures and capital contributions to equity method investments attributable to the third-party ownership interests in the Non-Wholly-Owned Consolidated Subsidiaries. As a result of the Company's completion of the Equitrans Midstream Merger in July 2024, which meaningfully increased the Company's equity method investments, the Company adjusted its non-GAAP measure of free cash flow. Beginning in the third quarter of 2024, free cash flow was changed to exclude capital contributions to equity method investments. In addition, as a result of the Class B Unitholder's noncontrolling equity interest ownership in the Midstream JV that commenced on December 30, 2024, the amounts attributable to noncontrolling interests meaningfully impacted the Company's consolidated cash flows, and, therefore, the Company began presenting free cash flow attributable to EQT. Free cash flow attributable to EQT presented in this news release for the prior comparative period has also been calculated based on the updated definition, and, certain prior period amounts have been recast for comparability. The Company's management believes these measures provide useful information to investors regarding the Company's liquidity, including the Company's ability to generate cash flow in excess of its capital requirements and return cash to shareholders. The tables below reconcile adjusted operating cash flow, adjusted operating cash flow attributable to EQT, free cash flow and free cash flow attributable to EQT with net cash provided by operating activities, the most comparable financial measure calculated in accordance with GAAP, as derived from the Statements of Condensed Consolidated Cash Flows to be included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2025. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands) Net cash provided by operating activities $ 1,017,699 $ 592,989 $ 4,000,565 $ 2,070,697 Decrease (increase) in changes in other assets and liabilities 203,441 (70,703) (194,779) (192,830) Adjusted operating cash flow (a) 1,221,140 522,286 3,805,786 1,877,867 Deduct: Capital expenditures (617,893) (557,889) (1,668,896) (1,683,011) Capital contributions to equity method investments (2,359) (85,196) (44,406) (87,804) Free cash flow (a) $ 600,888 $ (120,799) $ 2,092,484 $ 107,052 (a) Adjusted operating cash flow and free cash flow for the three and nine months ended September 30, 2025 included the impact of $21.0 million and $24.5 million, respectively, of cash transaction costs related to the Olympus Energy Acquisition. In addition, these measures for the nine months ended September 30, 2025 and 2024 included the impact of $133.7 million and $17.5 million, respectively, of net expense related to a securities class action settlement. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands) Net cash provided by operating activities $ 1,017,699 $ 592,989 $ 4,000,565 $ 2,070,697 Decrease (increase) in changes in other assets and liabilities 203,441 (70,703) (194,779) (192,830) Adjusted operating cash flow (a) 1,221,140 522,286 3,805,786 1,877,867 (Deduct) add: Adjusted EBITDA attributable to noncontrolling interests (b) (128,230) (7,783) (390,194) (7,339) Net interest expense attributable to noncontrolling interests 1,190 2,035 3,470 2,035 Adjusted operating cash flow attributable to EQT (a) (c) 1,094,100 516,538 3,419,062 1,872,563 (Deduct) add: Capital expenditures (617,893) (557,889) (1,668,896) (1,683,011) Capital contributions to equity method investments (2,359) (85,196) (44,406) (87,804) Capital expenditures attributable to noncontrolling interests 9,962 1,664 30,051 1,664 Capital contributions to equity method investments attributable to noncontrolling interests - - 23,123 - Free cash flow attributable to EQT (a) (c) $ 483,810 $ (124,883) $ 1,758,934 $ 103,412 (a) Adjusted operating cash flow, adjusted operating cash flow attributable to EQT and free cash flow attributable to EQT for the three and nine months ended September 30, 2025 included the impact of $21.0 million and $24.5 million, respectively, of cash transaction costs related to the Olympus Energy Acquisition. In addition, these measures for the nine months ended September 30, 2025 and 2024 included the impact of $133.7 million and $17.5 million, respectively, of net expense related to a securities class action settlement. (b) A non-GAAP financial measure. See above for a reconciliation of this non-GAAP financial measure to the most comparable financial measure as calculated in accordance with GAAP. (c) Adjusted operating cash flow attributable to EQT and free cash flow attributable to EQT are calculated based on EQT Corporation's current 40% Class A Unitholder share of available cash flow distributions from the Midstream JV, 60% ownership interest in Eureka Midstream Holdings and approximate 34% ownership interest in Teralytic. The Company believes that using its distribution share from the Midstream JV in the calculation of these measures best reflect the economic impact of the Company's investment in the Midstream JV on adjusted operating cash flow, free cash flow and earnings trends. The tables below present adjusted operating cash flow, free cash flow, adjusted operating cash flow attributable to EQT and free cash flow attributable to EQT for the quarters ended September 30, 2025, June 30, 2025, March 31, 2025 and December 31, 2024 as derived from (i) the Statements of Condensed Consolidated Cash Flows to be included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2025, (ii) the Statements of Condensed Consolidated Cash Flows included in EQT Corporation's Quarterly Reports on Form 10-Q for the quarters ended June 30, 2025 and March 31, 2025 and (iii) the Statements of Consolidated Cash Flows included in EQT Corporation's Annual Report on Form 10-K for the year ended December 31, 2024. Three Months Ended September 30, 2025 June 30, 2025 March 31, 2025 December 31, 2024 (Thousands) Net cash provided by operating activities $ 1,017,699 $ 1,241,699 $ 1,741,167 $ 756,276 Decrease (increase) in changes in other assets and liabilities 203,441 (323,821) (74,399) 474,635 Adjusted operating cash flow (a) 1,221,140 917,878 1,666,768 1,230,911 Deduct: Capital expenditures (617,893) (553,559) (497,444) (582,937) Capital contributions to equity method investments (2,359) (24,101) (17,946) (60,245) Free cash flow (a) $ 600,888 $ 340,218 $ 1,151,378 $ 587,729 (a) Adjusted operating cash flow and free cash flow for the three months ended September 30, 2025 included the impact of $21.0 million of cash transaction costs related to the Olympus Energy Acquisition. In addition, adjusted operating cash flow and free cash flow for the three months ended June 30, 2025 included the impact of $133.7 million of net expense related to a securities class action settlement. Three Months Ended September 30, 2025 June 30, 2025 March 31, 2025 December 31, 2024 (Thousands) Net cash provided by operating activities $ 1,017,699 $ 1,241,699 $ 1,741,167 $ 756,276 Decrease (increase) in changes in other assets and liabilities 203,441 (323,821) (74,399) 474,635 Adjusted operating cash flow (a) 1,221,140 917,878 1,666,768 1,230,911 (Deduct) add: Adjusted EBITDA attributable to noncontrolling interests (b) (128,230) (125,164) (136,800) (12,286) Net interest expense attributable to noncontrolling interests 1,190 1,028 1,252 2,472 Adjusted operating cash flow attributable to EQT (a) (c) 1,094,100 793,742 1,531,220 1,221,097 (Deduct) add: Capital expenditures (617,893) (553,559) (497,444) (582,937) Capital contributions to equity method investments (2,359) (24,101) (17,946) (60,245) Capital expenditures attributable to noncontrolling interests 9,962 9,907 10,182 2,308 Capital contributions to equity method investments attributable to noncontrolling interests - 13,587 9,536 - Free cash flow attributable to EQT (a) (c) $ 483,810 $ 239,576 $ 1,035,548 $ 580,223 (a) Adjusted operating cash flow, adjusted operating cash flow attributable to EQT and free cash flow attributable to EQT for the three months ended September 30, 2025 included the impact of $21.0 million of cash transaction costs related to the Olympus Energy Acquisition. In addition, adjusted operating cash flow, adjusted operating cash flow attributable to EQT and free cash flow attributable to EQT for the three months ended June 30, 2025 included the impact of $133.7 million of net expense related to a securities class action settlement. (b) A non-GAAP financial measure. See above for a reconciliation of this non-GAAP financial measure to the most comparable financial measure as calculated in accordance with GAAP. (c) Adjusted operating cash flow attributable to EQT and free cash flow attributable to EQT are calculated based on EQT Corporation's current 40% Class A Unitholder share of available cash flow distributions from the Midstream JV, 60% ownership interest in Eureka Midstream Holdings and approximate 34% ownership interest in Teralytic. The Company believes that using its distribution share from the Midstream JV in the calculation of these measures best reflect the economic impact of the Company's investment in the Midstream JV on adjusted operating cash flow, free cash flow and earnings trends. Production Adjusted Operating RevenuesProduction adjusted operating revenues (also referred to as total natural gas and liquids sales, including cash settled derivatives) is defined as total Production operating revenues, less the revenue impact of changes in the fair value of derivative instruments prior to settlement and Production other revenues. The Company's management believes that this measure provides useful information to investors regarding the Company's financial condition and results of operations because it helps facilitate comparisons of operating performance and earnings trends across periods. Production adjusted operating revenues reflects only the impact of settled derivative contracts; thus, the measure excludes the often-volatile revenue impact of changes in the fair value of derivative instruments prior to settlement. The measure also excludes Production other revenues because it is unrelated to the revenue from the Company's natural gas and liquids production. The table below reconciles Production adjusted operating revenues with total Production operating revenues, the most comparable financial measure calculated in accordance with GAAP, as reported in the Statements of Condensed Consolidated Operations to be included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2025. Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands, unless otherwise noted) Total Production operating revenues $ 1,815,766 $ 1,178,067 $ 5,805,591 $ 3,536,264 (Deduct) add: Production gain on derivatives (135,784) (72,489) (176,829) (240,333) Net cash settlements received (paid) on derivatives 74,960 288,136 (118,390) 1,037,321 Premiums paid for derivatives that settled during the period - (4,971) - (44,565) Production other revenues (2,365) (5,826) (5,919) (2,757) Production adjusted operating revenues $ 1,752,577 $ 1,382,917 $ 5,504,453 $ 4,285,930 Total sales volume (MMcfe) 634,395 581,414 1,773,373 1,622,976 Average sales price ($/Mcfe) $ 2.64 $ 1.89 $ 3.17 $ 2.03 Average realized price ($/Mcfe) $ 2.76 $ 2.38 $ 3.10 $ 2.64 Net DebtNet debt is defined as total debt less cash and cash equivalents. Total debt includes the Company's current portion of debt, revolving credit facility borrowings, term loan facility borrowings and senior notes. The Company's management believes net debt provides useful information to investors regarding the Company's financial condition and assists them in evaluating the Company's leverage since the Company could choose to use its cash and cash equivalents to retire debt. The table below reconciles net debt with total debt, the most comparable financial measure calculated in accordance with GAAP, as derived from the Condensed Consolidated Balance Sheets to be included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2025 and the Condensed Consolidated Balance Sheets included in EQT Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2024. September 30, 2025 December 31, 2024 September 30, 2024 (Thousands) Current portion of debt (a) $ 506,690 $ 320,800 $ 400,150 Revolving credit facility borrowings (b) 278,000 150,000 2,297,000 Term loan facility borrowings - - 497,970 Senior notes 7,433,132 8,853,377 10,598,428 Total debt 8,217,822 9,324,177 13,793,548 Less: Cash and cash equivalents 235,736 202,093 88,980 Net debt $ 7,982,086 $ 9,122,084 $ 13,704,568 (a) As of September 30, 2025, the current portion of debt included EQT Corporation's 3.125% senior notes and 7.75% debentures. As of December 31, 2024, the current portion of debt included borrowings outstanding under Eureka Midstream's revolving credit facility. Eureka Midstream is a wholly-owned subsidiary of Eureka Midstream Holdings. As of September 30, 2024, the current portion of debt included EQM Midstream Partners, LP's 6.000% senior notes. (b) As of September 30, 2025, revolving credit facility borrowings included borrowings outstanding under Eureka Midstream's revolving credit facility. As of December 31, 2024, revolving credit facility borrowings included borrowings outstanding under EQT Corporation's revolving credit facility. As of September 30, 2024, revolving credit facility borrowings included borrowings outstanding under EQT Corporation's and Eureka Midstream's revolving credit facilities. Investor ContactCameron HorwitzManaging Director, Investor Relations & Strategy412.445.8454Cameron.Horwitz@eqt.com About EQT CorporationEQT Corporation is a premier, vertically integrated American natural gas company with production and midstream operations focused in the Appalachian Basin. We are dedicated to responsibly developing our world-class asset base and being the operator of choice for our stakeholders. By leveraging a culture that prioritizes operational efficiency, technology and sustainability, we seek to continuously improve the way we produce environmentally responsible, reliable and low-cost energy. We have a longstanding commitment to the safety of our employees, contractors, and communities, and to the reduction of our overall environmental footprint. Our values are evident in the way we operate and in how we interact each day - trust, teamwork, heart, and evolution are at the center of all we do. EQT management speaks to investors from time to time and the analyst presentation for these discussions, which is updated periodically, is available via EQT's investor relations website at https://ir.eqt.com. Cautionary Statements Regarding Forward-Looking StatementsThis news release contains, and certain statements made during the above referenced conference call will be, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this news release or made during the above referenced conference call specifically include the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of EQT Corporation (EQT) and its consolidated subsidiaries (collectively, the Company), including guidance regarding the Company's strategy to develop its reserves; drilling plans and programs (including the number and type of drilling rigs and the number of frac crews to be utilized by the Company, the projected amount of wells to be turned-in-line and the timing thereof); projected natural gas prices, basis and average differential; the impact of commodity prices on the Company's business; total resource potential; projected production and sales volumes; projected capital expenditures and per unit operating costs; the Company's ability to successfully implement and execute its operational, organizational, technological and environmental, social and governance (ESG) initiatives, the timing thereof and the Company's ability to achieve the anticipated results of such initiatives; the Company's plans, objectives, expectations, goals and projections relating to the Company's in-basin growth projects; the projected volumes, incremental capacity, geographic scope, timing of in-service and projected cost and investment returns of MVP Boost; the Company's ability to achieve the intended operational, financial and strategic benefits from any proposed and recently completed strategic transactions, including the Olympus Energy Acquisition, and the anticipated synergies therefrom; the amount and timing of any redemptions, repayments or repurchases of EQT's common stock, the Company's outstanding debt securities or other debt instruments; the Company's ability to reduce its debt and the timing of such reductions, if any; projected free cash flow; liquidity and financing requirements, including funding sources and availability; the Company's hedging strategy and projected margin posting obligations; the Company's tax position and projected effective tax rate; and the expected impact of changes in laws. The forward-looking statements included in this news release or made during the above referenced conference call involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently known by the Company. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond the Company's control. These risks and uncertainties include, but are not limited to, volatility of commodity prices; the costs and results of drilling and operations; uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future; the assumptions underlying production forecasts; the quality of technical data; the Company's ability to appropriately allocate capital and other resources among its strategic opportunities; access to and cost of capital; the Company's hedging and other financial contracts; inherent hazards and risks normally incidental to drilling for, producing, transporting, storing and processing natural gas, natural gas liquids (NGLs) and oil; operational risks and hazards incidental to the gathering, transmission and storage of natural gas as well as unforeseen interruptions; cyber security risks and acts of sabotage; availability and cost of drilling rigs, completion services, equipment, supplies, personnel, oilfield services and pipe, sand and water required to execute the Company's exploration and development plans, including as a result of inflationary pressures or tariffs; risks associated with operating primarily in the Appalachian Basin; the ability to obtain environmental and other permits and the timing thereof; construction, business, economic, competitive, regulatory, judicial, environmental, political and legal uncertainties related to the development and construction by the Company or its joint ventures of pipeline and storage facilities and transmission assets and the optimization of such assets; the Company's ability to renew or replace expiring gathering, transmission or storage contracts at favorable rates, on a long-term basis or at all; risks relating to the Company's joint venture arrangements; government regulation or action, including regulations pertaining to methane and other greenhouse gas emissions; negative public perception of the fossil fuels industry; increased consumer demand for alternatives to natural gas; environmental and weather risks, including the possible impacts of climate change; and disruptions to the Company's business due to recently completed or pending divestitures, acquisitions and other significant strategic transactions, including the Olympus Energy Acquisition. These and other risks and uncertainties are described under the "Risk Factors" section and elsewhere in EQT Corporation's Annual Report on Form 10-K for the year ended December 31, 2024 and other documents EQT Corporation subsequently files from time to time with the Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse impact on it. Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, EQT Corporation does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise. EQT CORPORATION AND SUBSIDIARIES STATEMENTS OF CONDENSED CONSOLIDATED OPERATIONS (UNAUDITED) Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands, except per share amounts) Operating revenues: Sales of natural gas, natural gas liquids and oil $ 1,677,617 $ 1,099,752 $ 5,622,843 $ 3,293,174 Gain on derivatives 135,784 66,816 176,829 234,660 Pipeline and other 145,170 117,234 456,468 120,748 Total operating revenues 1,958,571 1,283,802 6,256,140 3,648,582 Operating expenses: Transportation and processing 377,133 440,845 1,144,458 1,529,093 Production 98,302 93,842 278,258 273,042 Operating and maintenance 60,302 40,518 161,582 65,824 Exploration 331 282 2,655 2,576 Selling, general and administrative 98,720 88,470 271,770 228,730 Depreciation, depletion and amortization 688,382 589,299 1,932,628 1,542,031 (Gain) loss on sale/exchange of long-lived assets (5,623) 10,117 (2,402) (309,865) Impairment and expiration of leases 3,476 12,095 9,391 58,963 Other operating expenses 34,338 290,174 224,302 354,337 Total operating expenses 1,355,361 1,565,642 4,022,642 3,744,731 Operating income (loss) 603,210 (281,840) 2,233,498 (96,149) Income from investments (44,638) (34,242) (138,274) (36,674) Other income (472) (3,960) (3,711) (23,596) Loss on debt extinguishment 1,909 365 19,478 5,651 Interest expense, net 109,929 158,299 333,166 268,390 Income (loss) before income taxes 536,482 (402,302) 2,022,839 (309,920) Income tax expense (benefit) 129,266 (104,870) 443,549 (124,790) Net income (loss) 407,216 (297,432) 1,579,290 (185,130) Less: Net income attributable to noncontrolling interests 71,354 3,391 217,142 2,688 Net income (loss) attributable to EQT Corporation $ 335,862 $ (300,823) $ 1,362,148 $ (187,818) Income (loss) per share of common stock attributable to EQT Corporation: Basic: Weighted average common stock outstanding 624,532 559,603 607,245 480,354 Net income (loss) attributable to EQT Corporation $ 0.54 $ (0.54) $ 2.24 $ (0.39) Diluted: Weighted average common stock outstanding 628,324 559,603 611,427 480,354 Net income (loss) attributable to EQT Corporation $ 0.53 $ (0.54) $ 2.23 $ (0.39) EQT CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) September 30, 2025 December 31, 2024 (Thousands) ASSETS Current assets: Cash and cash equivalents $ 235,736 $ 202,093 Accounts receivable (less allowance for credit losses: $1,127 and $12,529) 803,909 1,132,608 Derivative instruments, at fair value 123,559 143,581 Income tax receivable - 97,378 Prepaid expenses and other 103,788 139,019 Total current assets 1,266,992 1,714,679 Property, plant and equipment 47,904,599 44,505,504 Less: Accumulated depreciation and depletion 14,294,604 12,757,686 Net property, plant and equipment 33,609,995 31,747,818 Investments in unconsolidated entities 3,600,537 3,617,397 Net intangible assets 204,179 215,257 Goodwill 2,062,462 2,079,481 Other assets 451,125 455,623 Total assets $ 41,195,290 $ 39,830,255 LIABILITIES AND EQUITY Current liabilities: Current portion of debt $ 506,690 $ 320,800 Accounts payable 1,119,957 1,177,656 Derivative instruments, at fair value 189,635 446,519 Accrued interest 135,331 167,157 Other current liabilities 239,833 349,417 Total current liabilities 2,191,446 2,461,549 Revolving credit facility borrowings 278,000 150,000 Senior notes 7,433,132 8,853,377 Deferred income taxes 3,265,089 2,851,103 Asset retirement obligations and other liabilities 1,237,320 1,236,090 Total liabilities 14,404,987 15,552,119 Equity: Common stock, no par value, shares authorized: 1,280,000, shares issued: 624,064 and 596,870 19,490,656 18,014,711 Retained earnings 3,663,136 2,585,238 Accumulated other comprehensive loss (2,170) (2,321) Total common shareholders' equity 23,151,622 20,597,628 Noncontrolling interest in consolidated subsidiaries 3,638,681 3,680,508 Total equity 26,790,303 24,278,136 Total liabilities and equity $ 41,195,290 $ 39,830,255 EQT CORPORATION AND SUBSIDIARIES STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS (UNAUDITED) Nine Months Ended September 30, 2025 2024 (Thousands) Cash flows from operating activities: Net income (loss) $ 1,579,290 $ (185,130) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Deferred income tax expense (benefit) 446,674 (123,725) Depreciation, depletion and amortization 1,932,628 1,542,031 Gain on sale/exchange of long-lived assets (2,402) (309,865) Impairments 9,391 58,963 Income from investments (138,274) (36,674) Loss on debt extinguishment 19,478 5,651 Share-based compensation expense 43,824 141,578 Distributions from equity method investments 202,560 11,187 Other 7,836 13,160 Gain on derivatives (176,829) (234,660) Net cash settlements (paid) received on derivatives (118,390) 1,037,321 Net premiums paid on derivatives - (41,970) Changes in other assets and liabilities: Accounts receivable 296,345 331,452 Accounts payable (4,487) (122,252) Income tax receivable and payable 97,378 815 Other current assets 42,697 (10,965) Other items, net (237,154) (6,220) Net cash provided by operating activities 4,000,565 2,070,697 Cash flows from investing activities: Capital expenditures (1,675,691) (1,662,112) Cash paid for acquisitions, net of cash acquired (484,807) (864,242) Net cash (paid) received for sale/exchange of assets (8,603) 451,906 Capital contributions to equity method investments (44,406) (87,804) Other investing activities (10,388) (80) Net cash used in investing activities (2,223,895) (2,162,332) Cash flows from financing activities: Proceeds from revolving credit facility borrowings 3,018,000 3,578,000 Repayment of revolving credit facility borrowings (3,210,800) (2,316,000) Proceeds from issuance of debt - 750,000 Proceeds from net settlement of Capped Call Transactions - 93,290 Debt issuance costs (9,623) (18,854) Repayment and retirement of debt (905,698) (1,655,706) Net premiums paid on debt extinguishment (29,507) (1,543) Dividends paid (286,662) (232,603) Distributions to noncontrolling interest (259,217) (1,640) Cash paid for taxes to net settle share-based incentive awards (53,830) (92,492) Other financing activities (5,690) (2,814) Net cash (used in) provided by financing activities (1,743,027) 99,638 Net change in cash and cash equivalents 33,643 8,003 Cash and cash equivalents at beginning of period 202,093 80,977 Cash and cash equivalents at end of period $ 235,736 $ 88,980 EQT CORPORATION AND SUBSIDIARIES PRICE RECONCILIATION Three Months Ended September 30, Nine Months Ended September 30, 2025 2024 2025 2024 (Thousands, unless otherwise noted) NATURAL GAS Sales volume (MMcf) 595,642 547,225 1,666,421 1,520,574 NYMEX price ($/MMBtu) $ 3.07 $ 2.15 $ 3.37 $ 2.12 Btu uplift 0.17 0.12 0.19 0.12 Natural gas price ($/Mcf) $ 3.24 $ 2.27 $ 3.56 $ 2.24 Basis ($/Mcf) (a) $ (0.70) $ (0.56) $ (0.50) $ (0.40) Cash settled basis swaps ($/Mcf) 0.02 (0.09) (0.02) (0.10) Average differential, including cash settled basis swaps ($/Mcf) (0.68) (0.65) (0.52) (0.50) Average adjusted price ($/Mcf) 2.56 1.62 3.04 1.74 Cash settled derivatives ($/Mcf) 0.10 0.61 (0.05) 0.75 Average natural gas price, including cash settled derivatives ($/Mcf) $ 2.66 $ 2.23 $ 2.99 $ 2.49 Natural gas sales, including cash settled derivatives $ 1,586,374 $ 1,222,498 $ 4,987,247 $ 3,786,058 LIQUIDS NGLs, excluding ethane: Sales volume (MMcfe) (b) 23,650 22,253 66,997 63,393 Sales volume (Mbbl) 3,942 3,710 11,166 10,566 NGLs price ($/Bbl) $ 31.82 $ 35.20 $ 37.12 $ 38.18 Cash settled derivatives ($/Bbl) 0.70 (0.11) (0.21) (0.20) Average NGLs price, including cash settled derivatives ($/Bbl) $ 32.52 $ 35.09 $ 36.91 $ 37.98 NGLs sales, including cash settled derivatives $ 128,183 $ 130,140 $ 412,206 $ 401,232 Ethane: Sales volume (MMcfe) (b) 12,157 9,864 32,759 32,416 Sales volume (Mbbl) 2,026 1,644 5,460 5,403 Ethane price ($/Bbl) $ 6.86 $ 5.56 $ 8.01 $ 5.97 Ethane sales $ 13,901 $ 9,135 $ 43,730 $ 32,237 Oil: Sales volume (MMcfe) (b) 2,946 2,072 7,196 6,593 Sales volume (Mbbl) 491 345 1,199 1,099 Oil price ($/Bbl) $ 49.12 $ 61.25 $ 51.09 $ 60.43 Oil sales $ 24,119 $ 21,144 $ 61,270 $ 66,403 Total liquids sales volume (MMcfe) (b) 38,753 34,189 106,952 102,402 Total liquids sales volume (Mbbl) 6,459 5,699 17,825 17,068 Total liquids sales $ 166,203 $ 160,419 $ 517,206 $ 499,872 TOTAL Total natural gas and liquids sales, including cash settled derivatives (c) $ 1,752,577 $ 1,382,917 $ 5,504,453 $ 4,285,930 Total sales volume (MMcfe) 634,395 581,414 1,773,373 1,622,976 Average realized price ($/Mcfe) $ 2.76 $ 2.38 $ 3.10 $ 2.64 (a) Basis represents the difference between the ultimate sales price for natural gas, including the effects of delivered price benefit or deficit associated with the Company's firm transportation agreements, and the NYMEX natural gas price. (b) NGLs, ethane and oil were converted to Mcfe at a rate of six Mcfe per barrel. (c) Also referred to herein as Production adjusted operating revenues, a non-GAAP supplemental financial measure. View original content to download multimedia:https://www.prnewswire.com/news-releases/eqt-reports-third-quarter-2025-results-302590541.html SOURCE EQT Corporation (EQT-IR)
Weatherford Announces Third Quarter 2025 Results
Weatherford Announces Third Quarter 2025 Results Third quarter revenue of $1,232 million increased 2% sequentiallyThird quarter operating income of $178 million decreased 25% sequentiallyThird quarter net income of $81 million decreased 40% sequentially; net income margin of 6.6%Third quarter adjusted EBITDA* of $269 million increased 6% sequentially; adjusted EBITDA margin* of 21.8% increased 74 basis points sequentiallyThird quarter cash provided by operating activities of $138 million and adjusted free cash flow* of $99 millionExpanded the credit facility by $280 million with aggregate commitments of $1 billionAnnounced the offer of $1,200 million in aggregate principal amount of 6.75% Senior Notes due 2033 and the cash tender offer to purchase $1,300 million in aggregate principal amount of our outstanding 8.625% Senior Notes due 2030Credit rating upgrades from Moody's to âBa2' (Positive Outlook), S&P Global Ratings to âBB' (Stable Outlook), and from Fitch Ratings to âBB' (Stable Outlook)Shareholder return of $25 million for the quarter, which included dividend payments of $18 million and share repurchases of $7 millionBoard approved quarterly cash dividend of $0.25 per share, payable on December 4, 2025, to shareholders of record as of November 6, 2025Hosted 2025 FWRD conference, showcasing digital transformation, next-generation well technologies, and industry collaboration to shape the future of energy. The event marked the launch of Weatherford's Industrial Intelligence Digital Portfolio, introducing AI-driven, edge-enabled technologies designed to transform energy operations through automation, efficiency, and data-powered decision-making *Non-GAAP - refer to the section titled Non-GAAP Financial Measures Defined and GAAP to Non-GAAP Financial Measures Reconciled HOUSTON, Oct. 21, 2025 (GLOBE NEWSWIRE) -- Weatherford International plc (NASDAQ: WFRD) ("Weatherford" or the "Company") announced today its results for the third quarter of 2025. Revenues for the third quarter of 2025 were $1,232 million, an increase of 2% sequentially and a decrease of 13% year-over-year. Operating income in the third quarter of 2025 was $178 million, a decrease of 25% sequentially and a decrease of 27% year-over-year. Net income in the third quarter of 2025 was $81 million, with a 6.6% margin, a decrease of 40%, or 472 basis points, sequentially, and a decrease of 48%, or 457 basis points, year-over-year. Adjusted EBITDA* was $269 million, with a 21.8% margin, an increase of 6% or 74 basis points, sequentially, and a decrease of 24%, or 336 basis points, year-over-year. Basic income per share in the third quarter of 2025 was $1.13, a decrease of 40% sequentially and a decrease of 48% year-over-year. Diluted income per share in the third quarter of 2025 was $1.12, a decrease of 40% sequentially and a decrease of 46% year-over-year. Third quarter 2025 cash flows provided by operating activities were $138 million, an increase of 8% sequentially and a decrease of 47% year-over-year. Adjusted free cash flow* was $99 million, an increase of 25% sequentially and a decrease of 46% year-over-year. Capital expenditures were $44 million in the third quarter of 2025, a decrease of 19% sequentially and a decrease of 44% year-over-year. Girish Saligram, President and Chief Executive Officer, commented, "In a quarter defined by continued industry headwinds, I am proud of the One Weatherford team for delivering across the board. Our swift and decisive actions in the first half of the year provided momentum to make noticeable improvements in the third quarter with a ramp up of margins and commercial wins. The financial performance, which exceeded our guidance range, was a direct result of the rigor and effectiveness of our operating paradigm. With the expansion of our credit facility, the refinancing of a portion of our debt at significantly improved terms, and recent rating upgrades from the agencies, we have further strengthened our financial foundation. At our FWRD 2025 conference, we showcased tangible proof points of our innovation as a catalyst for long-term value creation. The event highlighted more than 20 product launches across all segments and I am particularly excited about Intelligent Completions and the introduction of Weatherford Intelligence, a single, powerful platform that drives efficiency, automation, and smarter decision-making. We remain on track to meet our full year 2025 guidance, with Latin America collections representing a timing factor in adjusted free cash flow projections. While activity in the first half of 2026 is expected to remain muted, we continue to be positive on the mid-to-long term activity outlook for the market and are well positioned to deliver strong performance for the next few years." *Non-GAAP - refer to the section titled Non-GAAP Financial Measures Defined and GAAP to Non-GAAP Financial Measures Reconciled Operational & Commercial Highlights Petroleo Brasilieiro S.A. (âPetrobras') awarded Weatherford a three-year $147 million contract to deliver Tubular Running Services ("TRS") in deepwater Brazil.SNGN Romgaz S.A. awarded Weatherford an eight-year contract to provide real-time monitoring services and transmission of dynamic parameters from the wellheads of gas wells in onshore Romania.Talos Energy awarded Weatherford a contract to provide Managed Pressure Drilling ("MPD") and TRS in their Gulf of America operations.Crescent Petroleum Diyala West Limited awarded Weatherford a contract for the supply of Downhole Valves and provision of related services in the newly developed field of Khashm Al Hamar in Iraq.Shell awarded Weatherford a two-year contract to provide Cementation Products in offshore U.S.Petronas Indonesia awarded Weatherford a four-year contract to provide MPD services for an offshore drilling campaign in Indonesia.YPF S.A. awarded Weatherford a one-year contract extension for the provision of Drilling Fluids in Central Argentina.Pertamina awarded Weatherford a two-year contract to provide Downhole Deployment Valve Technology in Indonesia.Brunei Shell Petroleum awarded Weatherford a five-year contract extension to provide Fishing, Milling and Associated Services in Brunei.Kuwait Energy awarded Weatherford a two-year contract to provide Fishing tools and services in onshore Iraq.bp awarded Weatherford a three-year contract extension to provide Liner Hangers, Annular Safety Valves, and Sand Screens in offshore Azerbaijan.A major oilfield services company awarded Weatherford a three-year contract to provide Cementation Products for an Exploration & Development campaign in offshore Suriname.A major operator awarded Weatherford a three-year contract to provide Intervention Services & Drilling Tools ("ISDT") in onshore and offshore Italy.Ecopetrol S.A. awarded Weatherford four six-year contracts to provide Artificial Lift Equipment and Services in onshore Colombia. Technology Highlights Drilling & Evaluation ("DRE") In Kuwait, Weatherford completed the first deployment of its MultiViewTM tool, enabling faster evaluation of three targeted barriers in a gas injection well compared to conventional methods. The operation reduced operating time, improved efficiency, and delivered a comprehensive solution aligned with operator expectations.In Bahrain, Weatherford drilled the region's longest extended-reach well for an NOC, achieving more than 12,000 feet in a single run. The milestone also marks the longest run using the MagnusTM 675 tool size outside the U.S., with just two longer laterals completed domestically in 2020. Well Construction and Completions ("WCC") In Brazil, Weatherford completed seven installations of its RFID OptiROSSTM remotely operated sliding sleeve for Petrobras, enabling secondary injection points in three-zone open hole completions. The RFID-driven solution reduced rig time, minimized personnel exposure, improved well integrity, and optimized acid stimulation logistics, delivering stronger returns over the life of the well.In Kuwait, Weatherford completed the first deployment of its Pressure Isolation Tool for KOC, marking the inaugural use of this technology in Kuwait and the Middle East. The operation delivered significant cost savings by leveraging existing liner hanger inventory, reduced operational risks, and ensured reliable performance in challenging downhole conditions. Production and Intervention ("PRI") In Thailand, Weatherford completed two runs of its Advanced Formation Testing and Sampling Service, showcasing significant operational advancements and reliability for PTTEP. Equipped with new fluid density and viscosity sensors, the service enabled precise characterization of reservoir fluids, improved sampling efficiency, and delivered meaningful cost savings for customers. Others In Colombia, Weatherford completed well testing across four zones in the country's first stratigraphic well for La Luna, advancing gas deliverability insights for the region. The integrated operation combined Wireline, Pressure Pumping, Completions, ISDT, TRS and Digital Solutions, encompassing borehole clean out, zone perforation, drill stem testing and a completion strategy informed by results. This achievement demonstrates Weatherford's execution in complex scenarios and opens new opportunities in Colombia's gas markets. Corporate Treasury On September 18, 2025, we announced the expansion of our credit facility by $280 million with aggregate commitments of $1 billion. The facility is now comprised of a $600 million revolver tranche, $400 million allocated to performance letters of credit, an increased accordion feature, which could expand lender commitments to up to $1.15 billion, subject to certain conditions, and extends maturity from 2028 to 2030. As of September 30, 2025, the Company's pro forma liquidity stands at approximately $1.6 billion. On September 22, 2025, we announced a private offering of $1,200 million in aggregate principal amount of 6.75% Senior Notes due 2033 ("the 2033 Notes"). The net proceeds of the offering, together with cash on hand, are intended to fund the previously announced tender offer for up to $1,300 million of our 8.625% Senior Notes due 2030 ("the 2030 Notes"). As of the date of this release, an aggregate principal amount of approximately $893 million of the 2030 Notes have been tendered and paid. On October 20, 2025, we issued a notice to redeem an amount of the 2030 Notes equal to the amount of the Tender Offer that remained unsubscribed at its expiration date.On September 22, 2025, we announced the Credit Rating upgrades from: Moody's to âBa2' (Positive Outlook) from âBa3'S&P Global Ratings to âBB' (Stable Outlook) from âBB-' and;Fitch Ratings to âBB' (Stable Outlook) from âBB-' Shareholder Return During the third quarter of 2025, Weatherford paid dividends of $18 million and repurchased shares for approximately $7 million, resulting in a total shareholder return of $25 million. During the nine months ended September 30, 2025, Weatherford paid dividends of $54 million and repurchased shares for approximately $94 million, resulting in a total shareholder return of $148 million. On October 15, 2025, our Board declared a cash dividend of $0.25 per share of the Company's ordinary shares, payable on December 4, 2025, to shareholders of record as of November 6, 2025. Results by Reportable Segment Drilling and Evaluation ("DRE") Third quarter 2025 DRE revenue of $346 million increased by $11 million, or 3% sequentially, primarily from higher Drilling Services activity in Latin America, and Middle East/North Africa/Asia partly offset by lower MPD and Drilling Services activity in Europe/Sub-Sahara Africa/Russia and North America. Year-over-year DRE revenue decreased by $89 million, or 20%, primarily from lower activity in Latin America, North America and Middle East / North Africa / Asia, partly offset by higher Wireline activity in Europe/Sub-Sahara Africa/ Russia. Third quarter 2025 DRE segment adjusted EBITDA of $83 million increased by $14 million, or 20% sequentially, primarily from higher Drilling Services and Wireline activity and fall through, partly offset by lower MPD activity. Year-over-year DRE segment adjusted EBITDA decreased by $28 million, or 25%, primarily from lower activity in Latin America, partly offset by higher Wireline fall through. Well Construction and Completions ("WCC") Third quarter 2025 WCC revenue of $468 million increased by $12 million, or 3% sequentially, primarily from higher Completions activity in Middle East/North Africa/Asia and North America, partly offset by lower Cementation Products activity in Middle East/North Africa/Asia and North America. Year-over-year WCC revenues decreased by $41 million, or 8%, primarily from lower activity in Latin America, Europe/Sub-Sahara Africa/Russia and Middle East/North Africa/Asia, partly offset by higher Completions activity in North America. Third quarter 2025 WCC segment adjusted EBITDA of $125 million increased by $7 million, or 6% sequentially, primarily from higher Completions and Well Services activity and fall through, partly offset by lower Cementation Products activity in Middle East/North Africa/Asia. Year-over-year WCC segment adjusted EBITDA decreased by $26 million, or 17%, primarily from lower activity across all geographies, especially in Latin America. Production and Intervention ("PRI") Third quarter 2025 PRI revenue of $326 million was largely flat sequentially, primarily from lower Sub-sea Intervention and ISDT activity, partly offset by higher Artificial Lift and Digital Solutions activity in Middle East/North Africa/Asia. Year-over-year PRI revenue decreased by $45 million, or 12%, primarily from lower activity across all geographies, especially in Latin America due to the sale of our Pressure Pumping business in Argentina, partly offset by higher Sub-sea intervention activity in Latin America. Third quarter 2025 PRI segment adjusted EBITDA of $59 million decreased by $4 million, or 6% sequentially, primarily from lower Sub-sea Intervention activity and fall through partly offset by higher Artificial Lift activity in Middle East/North Africa/Asia. Year-over-year PRI segment adjusted EBITDA decreased by $24 million, or 29%, primarily from lower activity across all geographies especially in Latin America due to the sale of our Pressure Pumping business in Argentina, partly offset by higher Sub-sea intervention activity in Latin America. Revenue by Geography North America Third quarter 2025 North America revenue of $243 million increased by $2 million, or 1% sequentially, primarily from higher Completions activity in Canada, partly offset by lower Artificial Lift activity in U.S. Land and Cementation Products activity in U.S. offshore. Year-over-year, North America decreased by $23 million, or 9%, primarily from lower DRE and PRI activity, partly offset by higher Completions activity in Canada and U.S. Offshore. International Third quarter 2025 international revenue of $989 million increased by $26 million, or 3% sequentially and decreased by $154 million, or 13% year-over-year. Third quarter 2025 Latin America revenue of $214 million increased by $19 million, or 10% sequentially, primarily from higher Drilling Services activity in Mexico, partly offset by lower Sub-sea intervention activity in Brazil. Year-over-year, Latin America revenue decreased by $144 million, or 40%, primarily from lower activity in Mexico and Argentina, partly offset by higher Sub-sea intervention activity. Third quarter 2025 Middle East/North Africa/Asia revenue of $533 million increased by $9 million, or 2% sequentially, primarily from higher Completions and Artificial Lift activity partly offset by lower Cementation Products activity. Year-over-year, the Middle East/North Africa/Asia revenue decreased by $9 million, or 2%, primarily from lower activity across all the segments partly offset by higher Completions, Well Services and Artificial Lift activity. Third quarter 2025 Europe/Sub-Sahara Africa/Russia revenue of $242 million decreased by $2 million, or 1% sequentially, primarily from lower activity across all the segments, partly offset by higher Wireline activity in Europe. Year-over-year, Europe/Sub-Sahara Africa/Russia revenue was largely flat year-over-year, primarily from lower activity in WCC and PRI, partly offset by higher Wireline activity in Europe. About WeatherfordWeatherford delivers innovative energy services that integrate proven technologies with advanced digitalization to create sustainable offerings for maximized value and return on investment. Our world-class experts partner with customers to optimize their resources and realize the full potential of their assets. Operators choose us for strategic solutions that add efficiency, flexibility, and responsibility to any energy operation. The Company conducts business in approximately 75 countries and has approximately 17,000 team members representing approximately 110 nationalities and 310 operating locations. Visit weatherford.com for more information and connect with us on social media. Conference Call Details Weatherford will host a conference call on Wednesday, October 22, 2025, to discuss the Company's results for the third quarter ended September 30, 2025. The conference call will begin at 8:30 a.m. Eastern Time (7:30 a.m. Central Time). Listeners are encouraged to download the accompanying presentation slides which will be available in the investor relations section of the Company's website. Listeners can participate in the conference call via a live webcast at https://www.weatherford.com/investor-relations/investor-news-and-events/events/ or by dialing +1 877-328-5344 (within the U.S.) or +1 412-902-6762 (outside of the U.S.) and asking for the Weatherford conference call. Participants should log in or dial in approximately 10 minutes prior to the start of the call. A telephonic replay of the conference call will be available until November 5, 2025, at 5:00 p.m. Eastern Time. To access the replay, please dial +1 877-344-7529 (within the U.S.) or +1 412-317-0088 (outside of the U.S.) and reference conference number 8574819. A replay and transcript of the earnings call will also be available in the investor relations section of the Company's website. Contacts For Investors: Luke Lemoine Senior Vice President, Corporate Development & Investor Relations +1 713-836-7777 investor.relations@weatherford.com For Media: Kelley Hughes Senior Director, Communications, Marketing & Sustainability media@weatherford.com Forward-Looking Statements This news release contains projections and forward-looking statements concerning, among other things, the Company's adjusted EBITDA*, adjusted EBITDA margin*, adjusted free cash flow*, shareholder return program, forecasts or expectations regarding business outlook, prospects for its operations, capital expenditures, expectations regarding future financial results, and are also generally identified by the words "believe," "project," "expect," "anticipate," "estimate," "outlook," "budget," "intend," "strategy," "plan," "guidance," "may," "should," "could," "will," "would," "will be," "will continue," "will likely result," and similar expressions, although not all forward-looking statements contain these identifying words. Such statements are based upon the current beliefs of Weatherford's management and are subject to significant risks, assumptions, and uncertainties. Should one or more of these risks or uncertainties materialize, or underlying assumptions prove incorrect, actual results may vary materially from those indicated in our forward-looking statements. Readers are cautioned that forward-looking statements are only estimates and may differ materially from actual future events or results, based on factors including but not limited to: global political, economic and market conditions, political disturbances, war or other global conflicts, terrorist attacks, changes in global trade policies, tariffs and sanctions, weak local economic conditions and international currency fluctuations; general global economic repercussions related to U.S. and global inflationary pressures and potential recessionary concerns; various effects from conflicts in the Middle East and the Russia Ukraine conflicts, including, but not limited to, nationalization of assets, extended business interruptions, sanctions, treaties and regulations (including changes in the regulatory environment) imposed by various countries, associated operational and logistical challenges, and impacts to the overall global energy supply; cybersecurity issues; our ability to comply with, and respond to, climate change, environmental, social and governance and other sustainability initiatives and future legislative and regulatory measures both globally and in specific geographic regions; the potential for a resurgence of a pandemic in a given geographic area and related disruptions; the price and price volatility of, and demand for, oil and natural gas; the macroeconomic outlook for the oil and gas industry; our ability to generate cash flow from operations to fund our operations; our ability to effectively and timely adapt our technology portfolio, products and services to remain competitive, and to address and participate in changes to the market demands, including for the transition to alternate sources of energy such as geothermal, carbon capture and responsible abandonment, including our digitalization efforts, increases in the prices and lead times, and the lack of availability of our procured products and services, including due to macroeconomic and geopolitical conditions such as tariffs and changes in trade policies, our ability to timely collect from customers; our ability to effectively execute our capital allocation framework; our ability to return capital to shareholders, including those related to the timing and amounts (including any plans or commitments in respect thereof) of any dividends and share repurchases; and the realization of additional cost savings and operational efficiencies. These risks and uncertainties are more fully described in Weatherford's reports and registration statements filed with the Securities and Exchange Commission, including the risk factors described in the Company's Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. Accordingly, you should not place undue reliance on any of the Company's forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law, and we caution you not to rely on them unduly. *Non-GAAP - refer to the section titled Non-GAAP Financial Measures Defined and GAAP to Non-GAAP Financial Measures Reconciled Segment adjusted EBITDA is our primary measure of segment profitability under U.S. GAAP ASC 280 "Segment Reporting" and represents segment earnings before interest, taxes, depreciation, amortization, share-based compensation, restructuring charges and other adjustments. Research and development expenses are included in segment adjusted EBITDA.All Other includes results from non-core business activities (including integrated services and projects), and Corporate includes overhead support and centrally managed or shared facilities costs. All Other and Corporate do not individually meet the criteria for segment reporting.Included the maximum potentially dilutive shares contingently issuable for an acquisition consideration during the three months ended September 30, 2024, the value of which was adjusted out of Net Income Attributable to Weatherford in calculating diluted income per share. We report our financial results in accordance with U.S. generally accepted accounting principles (GAAP). However, Weatherford's management believes that certain non-GAAP financial measures (as defined under the SEC's Regulation G and Item 10(e) of Regulation S-K) may provide users of this financial information additional meaningful comparisons between current results and results of prior periods and comparisons with peer companies. The non-GAAP amounts shown in the following tables should not be considered as substitutes for results reported in accordance with GAAP but should be viewed in addition to the Company's reported results prepared in accordance with GAAP. Adjusted EBITDA* - Adjusted EBITDA* is a non-GAAP measure and represents consolidated income before interest expense, net, income taxes, depreciation and amortization expense, and excludes, among other items, restructuring charges, share-based compensation expense, as well as other charges and credits. Management believes adjusted EBITDA* is useful to assess and understand normalized operating performance and trends. Adjusted EBITDA* should be considered in addition to, but not as a substitute for consolidated net income and should be viewed in addition to the Company's reported results prepared in accordance with GAAP. Adjusted EBITDA margin* - Adjusted EBITDA margin* is a non-GAAP measure which is calculated by dividing consolidated adjusted EBITDA* by consolidated revenues. Management believes adjusted EBITDA margin* is useful to assess and understand normalized operating performance and trends. Adjusted EBITDA margin* should be considered in addition to, but not as a substitute for consolidated net income margin and should be viewed in addition to the Company's reported results prepared in accordance with GAAP. Adjusted Free Cash Flow* - Adjusted Free Cash Flow* is a non-GAAP measure and represents cash flows provided by (used in) operating activities, less capital expenditures plus proceeds from the disposition of assets. Management believes adjusted free cash flow* is useful to understand our performance at generating cash and demonstrates our discipline around the use of cash. Adjusted free cash flow* should be considered in addition to, but not as a substitute for cash flows provided by operating activities and should be viewed in addition to the Company's reported results prepared in accordance with GAAP. Net Debt* - Net Debt* is a non-GAAP measure that is calculated taking short and long-term debt less cash and cash equivalents and restricted cash. Management believes the net debt* is useful to assess the level of debt in excess of cash and cash and equivalents as we monitor our ability to repay and service our debt. Net debt* should be considered in addition to, but not as a substitute for overall debt and total cash and should be viewed in addition to the Company's results prepared in accordance with GAAP.â Net Leverage* - Net Leverage* is a non-GAAP measure which is calculated by dividing by taking net debt* divided by adjusted EBITDA* for the trailing 12 months. Management believes the net leverage* is useful to understand our ability to repay and service our debt. Net leverage* should be considered in addition to, but not as a substitute for the individual components of above defined net debt* divided by consolidated net income attributable to Weatherford and should be viewed in addition to the Company's reported results prepared in accordance with GAAP. *Non-GAAP - as defined above and reconciled to the GAAP measures in the section titled GAAP to Non-GAAP Financial Measures Reconciled Other Charges, Net in the three and nine months ended September 30, 2025 and 2024 primarily includes fees to third-party financial institutions related to collections of certain receivables from our largest customer in Mexico and other miscellaneous charges and credits. *Non-GAAP - as reconciled to the GAAP measures above and defined in the section titled Non-GAAP Financial Measures Defined *Non-GAAP - as reconciled to the GAAP measures above and defined in the section titled Non-GAAP Financial Measures Defined
Matador Resources Company Reports Third Quarter 2025 Results, Increases Full-year 2025 Guidance and Provides 2026 Outlook
Matador Resources Company Reports Third Quarter 2025 Results, Increases Full-year 2025 Guidance and Provides 2026 Outlook DALLAS, Oct. 21 /BusinessWire/ -- Matador Resources Company (NYSE:MTDR) ("Matador" or the "Company") today reported financial and operating results for the third quarter of 2025 and updated full-year 2025 guidance. A slide presentation summarizing the highlights of Matador's third quarter 2025 earnings release is also included on the Company's website at www.matadorresources.com on the Events and Presentations page under the Investor Relations tab. Management Summary Comments Joseph Wm. Foran, Matador's Founder, Chairman and CEO, commented, "Last week we were pleased to announce yet another per share cash dividend increase from $1.25 to $1.50 per year. This dividend is to be paid proportionally each quarter. For the record, Matador's Board of Directors has already raised the dividend once this year and, with this raise, Matador's Board raised the dividend seven times in four years. The Board's decision to increase the dividend at this time is based on our positive outlook for the Company going forward, including Matador's strong liquidity position, free cash flow generation, further growth in our midstream asset, and the growing number of engineered inventory locations for drilling. In addition to the increased dividend, as of October 21, 2025, Matador has repurchased 1.3 million of its outstanding shares for approximately $55 million (a weighted average price of approximately $41 per share). Matador's overall growth and financial progress was recently highlighted in The Dallas Morning News' listing of the top 150 publicly-traded companies in Dallas-Fort Worth (DFW) by 2024 revenue across all industries. Matador was ranked 36th this year, advancing 11 places from last year's ranking of 47th. In fact, Matador has now grown to be the largest publicly-traded exploration and production company in DFW by revenue and the most profitable public company per employee in 2024 among the top 50 public companies in the DFW area." Third Quarter 2025 Financial and Operational Highlights Matador is pleased to report today: Record production of 209,184 barrels of oil and natural gas equivalent ("BOE") per day for the quarter, which exceeded the midpoint of July 2025 guidance of 199,750 BOE per day by 5%, which was a 22% year-over-year gain in production from the third quarter of 2024; Oil production of 119,556 barrels per day for the quarter, which exceeded the midpoint of July 2025 guidance of 117,250 barrels per day by 2%, which was a 19% year-over-year gain in production from the third quarter of 2024; Record quarterly natural gas production of 537.8 million cubic feet ("MMcf") per day, which exceeded the midpoint of July 2025 guidance of 495 MMcf per day by 9%; Drilling and completion costs of approximately $855 per completed lateral foot for the quarter, which was 3% less than the midpoint of July 2025 guidance of $880 per completed lateral foot; 34.5 net operated locations turned to sales during the quarter, which exceeded by 15% the midpoint of July 2025 guidance of 30 net operated wells that were estimated to be turned to sales in the quarter; and $105 million reduction in the balance outstanding on Matador's Reserves-Based Loan ("RBL") from $390 million at June 30, 2025 to $285 million at September 30, 2025. 2025 and 2026 Guidance Updates Increased 2025 full-year production guidance range from 200,000 to 205,000 BOE per day to 205,500 to 206,500 BOE per day; Increased the number of operated wells expected to be drilled and turned to sales in full-year 2025 from 106.3 net operated wells to 118.3 net operated wells. These 12 additional net operated wells turned to sales in 2025 are expected to increase production rates in the fourth quarter of 2025 and the first quarter of 2026; Base case for 2026 organic production is expected to yield approximately 210,000 BOE per day with expected organic oil production growth of 2 to 5% from full-year 2025 to full-year 2026 (exclusive of acquisitions); Updated full-year 2025 drilling, completing and equipping ("D/C/E") capital expenditure ("CapEx") estimate from $1.18 to $1.37 billion to $1.47 to $1.55 billion primarily due to the drilling and completion of the 12 additional net operated wells noted above, which was made possible by operational efficiencies and historical opportunities to experience lower service pricing during the second half of a production year; Decreased expected full-year 2025 drilling and completion cost per lateral foot from a range of $865 to $895 per completed lateral foot to a lower range of $835 to $855 per completed lateral foot; Highly capital-efficient program expected for 2026 with flexibility to adjust production and CapEx depending on external factors such as commodity prices and the economy; and An improved capital program for full-year 2026, which is expected to result in 8 to 12% lower total capital expenditures in 2026 compared to 2025 for approximately the same amount of lateral footage. The favorable cost per foot expected in 2026 should allow Matador multiple options for ways to make good use of these expected capital savings. Matador's Land Program Mr. Foran continued, "A key component of this growth is Matador's `brick-by-brick' land acquisition strategy and selective lease acquisition program, which is not only improving the quality and potential of Matador's over 200,000 net acre land position in the Delaware Basin but also has increased Matador's various working interests or mineral positions in key areas. During the third quarter of 2025, Matador completed over $125 million in transactions in key areas. All acquisitions made this quarter were in the Delaware Basin and consisted primarily of undeveloped acreage, including working interests in Matador wells turned to sales in the third quarter of 2025. Over time, these targeted acquisitions by our land team have positioned us with over 10 years of engineered locations with average rates of return of approximately 50% at oil price levels even as low as $50 per barrel." Upstream Operations Guidance Matador exceeded the midpoint of July 2025 guidance estimates for BOE volumes for the third quarter of 2025 of 199,750 BOE per day by 5% delivering 209,184 BOE per day. These better-than-expected results reflect the strength and size of Matador's long-term production base, its accelerated operational execution in the field, the outperformance of recent wells turned online and the responsiveness and the runtimes of its midstream system. These efforts allowed Matador to turn to sales 46 gross (34.5 net) operated wells during the third quarter of 2025, an increase of 4.5 net operated wells above July 2025 guidance estimate of 30 net operated wells to be turned to sales for the same period. As a result of these accelerated operating activities combined with our improved efficiencies and lower well costs, Matador now expects its full-year 2025 D/C/E CapEx to be in the $1.47 to $1.55 billion range for a revised 2025 competed well count of 118.3, up from previous completed well count guidance of 106.3. Notably, 1.5 billion cubic feet ("Bcf") (17 MMcf per day) of this third quarter of 2025 production beat was the result of six non-operated wells in the Haynesville Shale in which Matador has working and mineral interests. This production beat demonstrates the value and potential of Matador's estimated 200 to 300 Bcf "gas bank" in Northwest Louisiana. This asset, which is 100% held-by-production and has high net revenue interests, gives Matador the ability to increase natural gas production whenever natural gas prices increase and stabilize. In light of the positive outcomes of these operations and the outperformance of various operated wells turned to sales, Matador has increased its full-year 2025 production guidance company-wide for both oil and natural gas production. Matador's continued operational execution and lower service pricing reduced drilling and completion cost per lateral foot, providing additional confidence in our decision to accelerate certain operating activities during the quarter. In fact, Matador expects not only better well results for full-year 2025 but also expects drilling and completion costs per lateral foot to be below the low end of our guidance range of $865 to $895 per completed lateral foot. Accordingly, Matador is revising its full-year 2025 range down to $835 to $855 per completed lateral foot. Driving factors for these capital efficiency improvements are related to the number of drilling days on wells and the expanded use of trimul-frac, remote frac operations and other targeted performance initiatives. The successful integration of these processes has increased Matador's overall completion efficiency in 2025 by 20% as compared to the average time required to complete lateral footage in 2024. 2026 Guidance Matador expects our capital and production successes in 2025, including the acceleration of certain operating activities at lower prices, will lead to high rates of return and an even more capital-efficient operating program in 2026. Matador plans to provide its customary full-year 2026 forecast along with its February 2026 earnings release. Matador has the ability to flex its capital program up or down based upon changes in economic conditions, including commodity and service prices. Given current market conditions, Matador expects an organic increase in production to approximately 210,000 BOE per day in 2026 with expected oil production growth of 2 to 5% from 2025 to 2026. Furthermore, Matador believes it can achieve this growth or more while reducing total CapEx by 8 to 12% from 2025 to 2026 while completing and turning to sales approximately the same lateral footage in 2026 as in 2025. Matador expects that this capital and operating plan will allow it to advance its other top priorities, which include (i) maintaining a strong balance sheet, (ii) continuing to grow its proved reserves in various ways, (iii) increasing engineered inventory locations with new horizons and areas across its asset position, (iv) maintaining its brick-by-brick acreage acquisition strategy and (v) continuing to enhance its midstream businesses to service the growth of Matador and other third-party producers. Yet, Matador is fully prepared to make adjustments and to update our guidance as necessary in today's volatile times and conditions to keep our shareholders, the public and other interested parties informed of our plans and opportunities. San Mateo Effect While the land, engineering and geology teams continue to organically grow our asset positions, Matador's integrated midstream business, San Mateo, is contributing to Matador's revenue and production efficiency. In this regard, San Mateo provides critical and timely flow assurance, including gathering and processing optionality, for our production as well as for third-party customers. These services generate a significant and growing revenue stream. This quarter's excellent midstream operating results reflect the team's solid technical expertise and extra effort to successfully grow these efficiencies and assets in 2025. During September 2025, San Mateo turned online the Ranger North Compressor station and associated gathering system. This compressor station is currently designed for 30 MMcf per day and can be expanded to up to 70 MMcf per day and is San Mateo's first station built to handle sour gas. The ability to accommodate sour gas increases optionality for San Mateo to add additional third-party customers in the northeastern part of San Mateo's operating area in Lea County, New Mexico. The Marlan plant expansion was also put into service in the second quarter of 2025. This plant, together with San Mateo's other facilities, continue to provide increased flow assurance out of the basin for Matador and San Mateo's third-party customers, many of which are repeat customers. Now that the Marlan plant expansion is online and processing natural gas, San Mateo processed a record 533 MMcf per day during the third quarter of 2025, an increase of 10% from 486 MMcf per day in the second quarter of 2025, contributing to third quarter of 2025 San Mateo net income of $50 million and Adjusted EBITDA of $74 million, which were in line with expectations and sets up San Mateo for anticipated record annual Adjusted 2025 EBITDA of $285 to $295 million. In light of San Mateo's significant cash flows and growth potential, Matador continues to believe that the value of San Mateo is not fully realized in Matador's current share price. The team is continuing to work towards strategic solutions for increasing San Mateo's value and potential. Financial Summary Matador's integrated upstream and midstream business generated net income of $176 million with earnings per share of $1.42 and adjusted earnings per share of $1.36 in the third quarter of 2025. Net cash provided by operating activities was $722 million, or an increase of 44% from $501 million in the second quarter of 2025, and adjusted EBITDA was $567 million during the third quarter of 2025, leading to adjusted free cash flow of $93 million. Matador used this $93 million of free cash flow and the benefit from working capital changes of $123 million during the third quarter of 2025 to pay down an additional $105 million of borrowings under its RBL during the third quarter of 2025. This paydown reduced total borrowings under the RBL from $390 million at June 30, 2025 to $285 million as of September 30, 2025. In total, Matador has paid down $311 million in borrowings under the RBL during the first nine months of 2025 and maintains a strong balance sheet with a debt-to-EBITDA leverage ratio under 1.0x and approximately $2 billion in available liquidity under its current RBL as of September 30, 2025. Shareholder Returns On October 15, 2025, Matador announced that its Board of Directors approved a 20% increase in Matador's dividend policy, raising the dividend from $1.25 annually, or $0.3125 per quarter, to $1.50 annually, or $0.375 per quarter. In accordance with this new dividend policy, the Board declared a quarterly cash dividend of $0.375 per share of common stock payable on December 5, 2025 to shareholders of record as of November 10, 2025. Matador's base dividend represents an increased annualized yield to shareholders of approximately 3.5% as of October 20, 2025 based upon Matador's current share price. In addition to our base dividend, in 2025, Matador implemented a share repurchase program to return additional value to shareholders by opportunistically repurchasing shares of our common stock. In total, under Matador's present share repurchase authorization, Matador has repurchased $55 million, or 1.3 million shares of our common stock at a weighted average price of approximately $41 per share, representing over 1% of the total shares of common stock outstanding as of October 21, 2025. Matador's Board of Directors, management, and staff also continue to be regular purchasers of Matador's shares in the open market further aligning ourselves with our shareholders. Matador's directors and executive officers purchased approximately 67,000 shares of Matador stock during 2025. In addition, over 95% of Matador employees continued to participate in Matador's Employee Share Purchase Plan, or ESPP. Closing Thoughts Joseph Wm. Foran, Matador's Founder, Chairman and CEO, commented, "The combined achievements of Matador's planning, reservoir, land, operations and midstream teams and the recent completion of the new Marlan plant expansion have helped solidify and widen our asset base as well as round out our growth strategy as we head into 2026. The management team, Board of Directors and staff remain confident in this positive outlook despite occasional headwinds. All of us would like to thank the staff, shareholders, service providers, and board members for their efforts closing out what should be a record year for Matador and for increasing our chances for continuing success going forward." All references to Matador's net income, adjusted net income, Adjusted EBITDA and adjusted free cash flow reported throughout this earnings release are those values attributable to Matador Resources Company shareholders after giving effect to any net income, adjusted net income, Adjusted EBITDA or adjusted free cash flow, respectively, attributable to third-party non-controlling interests, including in San Mateo. Matador owns 51% of San Mateo. For a definition of adjusted net income, adjusted earnings per diluted common share, Adjusted EBITDA and adjusted free cash flow and reconciliations of such non-GAAP financial metrics to their comparable GAAP metrics, please see "Supplemental Non-GAAP Financial Measures" below. Full-Year 2025 Guidance Update Effective October 21, 2025, Matador increased its full-year 2025 guidance range for oil production, natural gas production and total BOE production as well as for CapEx as set forth in the table below. Operational and Financial Update Third Quarter 2025 Oil, Natural Gas and Total BOE Production As summarized in the table below, Matador's total BOE production averaged 209,184 BOE per day in the third quarter of 2025, which was a Company record and a 22% year-over-year increase from an average of 171,480 BOE per day in the third quarter of 2024. The better-than-expected oil and natural gas production was primarily due to the continued outperformance of Matador's producing wells and wells that were turned to sales in the third quarter of 2025, including six non-operated Haynesville shale wells where Matador owned primarily mineral interests, which had combined third quarter of 2025 natural gas production of 1.5 Bcf or 17 MMcf per day, net to Matador. Another highlight of Matador's outperformance has been our high quality Avalon wells in Lea County, New Mexico. The Gavilon #104H, which Matador turned online in September 2024, is an excellent example of the potential value and productivity of these wells. In approximately one year, the Gavilon #104H had more than paid out with cumulative production of 280,000 barrels of oil and 358 MMcf of natural gas as of September 30, 2025. Matador currently believes that there are over 85 potential future drilling locations in the Avalon formation in this area. Third Quarter 2025 Realized Commodity Prices The following table summarizes Matador's realized commodity prices during the third quarter of 2025, as compared to the second quarter of 2025 and the third quarter of 2024. Third Quarter 2025 Capital Expenditures Matador's D/C/E CapEx guidance range for the third quarter of 2025 was $300 to $370 million with a range of between 28 to 32 net operated wells turned to sales. During the quarter, due to operational efficiencies achieved and in order to capitalize on lower service pricing, Matador elected to accelerate certain operating activities. Matador turned to sales 34.5 net operated wells, or 4.5 net operated wells above the midpoint of our July 2025 guidance estimates. Total third quarter D/C/E CapEx was $430 million, or $95 million above the midpoint of our July 2025 guidance range. Additional CapEx attributable to these incremental 4.5 net operated wells turned to sales was approximately $15 million. The remaining CapEx above our guidance range was attributable to (i) unforecasted non-operated well activity of $15 million, (ii) increased working interest additions on wells turned to sales in the third quarter of 2025 of $9 million and (iii) costs associated with wells that are expected to be turned to sales in the fourth quarter of 2025 of $56 million. Midstream CapEx of $42.8 million for the third quarter of 2025 were consistent with Matador's expected range of $25 to $55 million in total midstream CapEx. Midstream Update San Mateo had quarterly net income of $50 million and quarterly Adjusted EBITDA of $74 million. The table below sets forth San Mateo's throughput volumes for the third quarter of 2025, as compared to the second quarter of 2025 and third quarter of 2024. Fourth Quarter 2025 Estimates Fourth Quarter 2025 Estimated Oil, Natural Gas and Total BOE Production Growth As noted in the table below, Matador anticipates oil production of 119,556 Bbl per day in the third quarter of 2025 to increase in the fourth quarter of 2025 due to larger well batches that were turned on late in the third quarter of 2025 and will therefore fully contribute to production in the fourth quarter of 2025. Matador anticipates natural gas production of 538 MMcf per day in the third quarter of 2025 to decrease in the fourth quarter of 2025 due to (i) voluntary shut-ins of wells with high natural gas to oil ratios during October 2025 when several long-haul pipelines underwent maintenance causing Waha natural gas prices to be negative and (ii) the natural decline of six non-operated Haynesville shale wells that led to outperformance in the third quarter of 2025. The negative Waha pricing led Matador to shut in approximately 0.9 Bcf of natural gas and 45,000 Bbl of oil to date in October 2025 due to those negative gas prices. These volumes have been removed from our fourth quarter estimates and deferred to future periods. Fourth Quarter 2025 Estimated Wells Turned to Sales At October 21, 2025, Matador expects to turn to sales 27.5 net operated horizontal wells in the Delaware Basin during the fourth quarter of 2025. Due to the acceleration of drilling and completion activities noted above, Matador expects to turn to sales 12 net wells more than previously expected for the full-year 2025. In addition, Matador expects to turn to sales 13.6 net operated horizontal wells in January 2026, which are expected to provide a favorable increase in production from 2025 to 2026. Fourth Quarter 2025 Estimated Capital Expenditures Matador expects D/C/E CapEx for the fourth quarter of 2025 will be approximately $300 to $380 million, which is a 21% decrease as compared to $429.9 million for the third quarter of 2025, primarily due to timing of completions in the third quarter of 2025 compared to completions in the fourth quarter of 2025. Matador expects its midstream CapEx, including its proportionate share of San Mateo's CapEx, will be approximately $10 to $30 million in the fourth quarter of 2025, which is a 53% reduction in CapEx as compared to $42.8 million in CapEx for the third quarter of 2025. Third Quarter 2025 Earnings Conference Call The Company will host a live conference call on Wednesday, October 22, 2025, at 10:00 a.m. Central Time to review its third quarter 2025 financial results and operational highlights. To access the live conference call by phone, you can use the following link https://register-conf.media-server.com/register/BIf0215354457a4bb591304082cdf18330 and you will be provided with dial in details. To avoid delays, it is recommended that participants dial into the conference call 15 minutes ahead of the scheduled start time. The live conference call will also be available through the Company's website at www.matadorresources.com on the Events and Presentations page under the Investor Relations tab. The replay for the event will be available on the Company's website at www.matadorresources.com on the Events and Presentations page under the Investor Relations tab for one year. About Matador Resources Company Matador is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Its current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. Matador also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, Matador conducts midstream operations in support of its exploration, development and production operations and provides natural gas processing, oil transportation services, natural gas, oil and produced water gathering services and produced water disposal services to third parties. For more information about Matador Resources Company, visit www.matadorresources.com. Forward-Looking Statements This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. "Forward-looking statements" are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as "could," "believe," "would," "anticipate," "intend," "estimate," "expect," "may," "should," "continue," "plan," "predict," "potential," "project," "hypothetical," "forecasted" and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such forward-looking statements include, but are not limited to, statements about guidance, projected or forecasted financial and operating results, future liquidity, the payment of dividends, the amount and timing of share repurchases, results in certain basins, objectives, project timing, expectations and intentions, regulatory and governmental actions and other statements that are not historical facts. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, disruption from Matador's acquisitions or dispositions making it more difficult to maintain business and operational relationships; significant transaction costs associated with Matador's acquisitions or dispositions; the risk of litigation and/or regulatory actions related to Matador's acquisitions or dispositions, as well as the following risks related to financial and operational performance: general economic conditions; Matador's ability to execute its business plan, including whether its drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; its ability to replace reserves and efficiently develop current reserves; the operating results of Matador's midstream oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on Matador's operations due to seismic events; its ability to make acquisitions on economically acceptable terms; its ability to integrate acquisitions; availability of sufficient capital to execute its business plan, including from future cash flows, capital markets, available borrowing capacity under its revolving credit facilities and otherwise; the operating results of and the availability of any potential distributions from our joint ventures; weather and environmental conditions; the impact of the One Big Beautiful Bill Act; and the other factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador's filings with the Securities and Exchange Commission ("SEC"), including the "Risk Factors" section of Matador's most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation to update these forward-looking statements to reflect events or circumstances occurring after the date of this press release, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements are qualified in their entirety by this cautionary statement. Selected Financial and Operating Items Sequential and year-over-year quarterly comparisons of selected financial and operating items are shown in the following table: Matador Resources Company and Subsidiaries CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED Matador Resources Company and Subsidiaries CONDENSED CONSOLIDATED STATEMENTS OF INCOME - UNAUDITED Matador Resources Company and Subsidiaries CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - UNAUDITED Supplemental Non-GAAP Financial Measures Adjusted EBITDA This press release includes the non-GAAP financial measure of Adjusted EBITDA. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of the Company's consolidated financial statements, such as securities analysts, investors, lenders and rating agencies. "GAAP" means Generally Accepted Accounting Principles in the United States of America. The Company believes Adjusted EBITDA helps it evaluate its operating performance and compare its results of operations from period to period without regard to its financing methods or capital structure. The Company defines, on a consolidated basis and for San Mateo, Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income or net cash provided by operating activities as determined by GAAP. All references to Matador's Adjusted EBITDA are those values attributable to Matador Resources Company shareholders after giving effect to Adjusted EBITDA attributable to third-party non-controlling interests, including in San Mateo. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or net cash provided by operating activities as determined in accordance with GAAP or as an indicator of the Company's operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure. Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents the calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively, that are of a historical nature. Where references are pro forma, forward-looking, preliminary or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue hardship because such Adjusted EBITDA numbers are estimations, approximations and/or ranges. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items, including future income taxes, full-cost ceiling impairments, unrealized gains or losses on derivatives and gains or losses on asset sales and impairment. For the same reasons, the Company is unable to address the probable significance of the unavailable information, which could be material to future results. Adjusted EBITDA - Matador Resources Company Adjusted EBITDA - San Mateo (100%) Adjusted Net Income and Adjusted Earnings Per Diluted Common Share This press release includes the non-GAAP financial measures of adjusted net income and adjusted earnings per diluted common share. These non-GAAP items are measured as net income attributable to Matador Resources Company shareholders, adjusted for dollar and per share impact of certain items, including unrealized gains or losses on derivatives, the impact of full-cost ceiling impairment charges, if any, and non-recurring transaction costs for certain acquisitions or other non-recurring income or expense items, along with the related tax effect for all periods. This non-GAAP financial information is provided as additional information for investors and is not in accordance with, or an alternative to, GAAP financial measures. Additionally, these non-GAAP financial measures may be different than similar measures used by other companies. The Company believes the presentation of adjusted net income and adjusted earnings per diluted common share provides useful information to investors, as it provides them an additional relevant comparison of the Company's performance across periods and to the performance of the Company's peers. In addition, these non-GAAP financial measures reflect adjustments for items of income and expense that are often excluded by securities analysts and other users of the Company's financial statements in evaluating the Company's performance. The table below reconciles adjusted net income and adjusted earnings per diluted common share to their most directly comparable GAAP measure of net income attributable to Matador Resources Company shareholders. Adjusted Free Cash Flow This press release includes the non-GAAP financial measure of adjusted free cash flow. This non-GAAP item is measured, on a consolidated basis for the Company and for San Mateo, as net cash provided by operating activities, adjusted for changes in working capital and cash performance incentives that are not included as operating cash flows, less cash flows used for capital expenditures, adjusted for changes in capital accruals. On a consolidated basis, these numbers are also adjusted for the cash flows related to non-controlling interest in subsidiaries that represent cash flows not attributable to Matador shareholders. Adjusted free cash flow should not be considered an alternative to, or more meaningful than, net cash provided by operating activities as determined in accordance with GAAP or an indicator of the Company's liquidity. Adjusted free cash flow is used by the Company, securities analysts and investors as an indicator of the Company's ability to manage its operating cash flow, internally fund its D/C/E capital expenditures, pay dividends and service or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities or accounts payable related to capital expenditures. Additionally, this non-GAAP financial measure may be different than similar measures used by other companies. The Company believes the presentation of adjusted free cash flow provides useful information to investors, as it provides them an additional relevant comparison of the Company's performance, sources and uses of capital associated with its operations across periods and to the performance of the Company's peers. In addition, this non-GAAP financial measure reflects adjustments for items of cash flows that are often excluded by securities analysts and other users of the Company's financial statements in evaluating the Company's cash spend. The table below reconciles adjusted free cash flow to its most directly comparable GAAP measure of net cash provided by operating activities. All references to Matador's adjusted free cash flow are those values attributable to Matador shareholders after giving effect to adjusted free cash flow attributable to third-party non-controlling interests, including in San Mateo. Adjusted Free Cash Flow - Matador Resources Company Adjusted Free Cash Flow - San Mateo (100%) View source version on businesswire.com: https://www.businesswire.com/news/home/20251021313421/en/ back
NOG Provides Third Quarter Update
NOG Provides Third Quarter Update Acquires Core Uinta Basin Royalty and Minerals Bolt-on with Significant Inventory; Executes on Additional Ground Game; Well Performance Driving Increased Production Guidance MINNEAPOLIS, Oct. 21 /BusinessWire/ -- Northern Oil and Gas, Inc. (NYSE:NOG) ("NOG" or the "Company") today provided an update on a number of business matters, including a recent bolt-on acquisition, an update on ground game transactions, capital expenditure and production guidance and other third quarter information. UINTA ROYALTY AND MINERAL ACQUISITION HIGHLIGHTS $98.3 million initial closing settlement for non-budgeted bolt-on acquisition of producing royalty and mineral interests with significant undeveloped inventory in Duchesne and Uintah Counties Substantially all of the assets reside under NOG's existing Uinta footprint, operated by SM Energy ~1,000 net royalty acres (~8,000 royalty acres standardized to 1/8th royalty) with significant inventory of over 400 gross locations Average net revenue interest of ~1.3% on an 8/8ths basis across all acquired spacing units; transaction increases NOG's average effective NRI from ~80% to ~87% covering the entirety of NOG's Uinta position Forward one-year unhedged cash flow from operations expected to be approximately $14 million at recent strip pricing, representing a free cash flow yield of approximately 14% Transaction expected to be accretive to key financial metrics, including earnings per share, free cash flow and cash flow per share over a multi-year period GROUND GAME ACQUISITIONS Significant ground game success in the third quarter across NOG's entire platform, including the Williston, Permian, Uinta and Appalachian Basins Completes $59.8 million in acquisition costs inclusive of associated ground game development across 22 ground game transactions and three trades Ground game transactions add ~2,500 net acres and 5.8 net wells Executed multiple trades and signed a joint development agreement covering seven spacing units in the Williston Basin BUSINESS UPDATE AND GUIDANCE Better than expected well performance across all four active basins Modest increase in D&C list in the third quarter helping to build low-breakeven momentum into year-end Total production expected to be 131 MBoe/d in the third quarter, with oil representing over 55% Increasing annual production guidance to 75,000 - 76,500 Bopd and 132,500 - 134,000 Boepd for oil and total volumes, respectively Expect total capital expenditures of ~$272 million for the third quarter, inclusive of ground game, but excluding non-budgeted and other capital expenditures Tightening annual capital expenditure guidance range to $950 - $1,025 million UINTA ROYALTY AND MINERAL ACQUISITION In August 2025, NOG closed on its acquisition of royalty and mineral interests, representing approximately ~1,000 net royalty acres (~8,000 royalty acres standardized to 1/8th royalty) located primarily in Duchesne and Uintah Counties, UT for a purchase price of $98.3 million in cash, subject to typical post-closing adjustments. The acquisition was funded with a previously placed $9.8 million acquisition deposit, cash on hand, operating free cash flow and borrowings under the Company's revolving credit facility. Production for the properties for 2026 is expected to average approximately ~900 boe per day (2-stream, ~85%+ oil), with the expectation of steady production growth on the properties over a multi-year period. De minimis capital expenditures are anticipated on a go-forward basis. NOG hedged a significant portion of the oil production at signing. The acquired assets include over 400 gross locations and represent an average net revenue interest of approximately 1.3% on an 8/8ths basis across all acquired spacing units. This transaction increased NOG's average effective NRI from 80% to 87% across the Company's Uinta properties. SM Energy operates on substantially all of the acreage. NOG's acquisition underwriting ascribed value to just the future locations in the current proposed drilling plan. Given the stacked pay of the Uinta Basin, the acquired assets contain significant additional inventory and upside. GROUND GAME ACQUISITIONS NOG's signature ground game program notched another sequential increase deploying $59.8 million of acquisition and development capital with 22 transactions and three trades across all four of the Company's basins, adding over 2,500 net acres and 5.8 net wells. In addition, NOG executed on multiple trades aimed at high-grading its acreage position across the Williston and Uinta Basins with several operators, and executed another joint development agreement across seven extended-lateral drilling units in the Williston Basin with a private operator. Year to date, the Company has deployed over $95.8 million of acquisition and development capital across more than 50 ground game transactions, adding over 11.6 net wells and 6,100 net acres with incremental locations across all of NOG's active basins. MANAGEMENT COMMENTS "The variety of acquisition types comprising the third quarter's transactions highlight several of our key strategic advantages: technical knowledge of our basins of operation, and the ability to leverage proprietary knowledge of future development on our existing properties driving our ability to acquire additional revenue and working interests overlaying our land positions," commented Nick O'Grady, Chief Executive Officer of NOG. "The Uinta royalty transaction, in particular, will further lower our breakevens in an already low-cost basin. Finally, well performance on our base assets continues to exceed expectations across the board, driving increased guidance. This, combined with a robust backlog of growth opportunities, continues to set NOG up well as we head into 2026." BUSINESS UPDATE AND GUIDANCE Well performance has materially exceeded Company expectations across all four basins. Additionally, NOG saw a significant increase in development on its acreage throughout the third quarter with strong completions as the Company exited the third quarter. Despite increased completion activity in the quarter, the D&C list still increased by 0.3 net wells, building low-breakeven momentum into year-end. For the quarter, activity was in line with expectations with reduced oil production and continued growth in gas production. The Company expects total capital expenditures of approximately $272 million for the third quarter, driven primarily by robust ground game success. Total production is expected to be ~131,000 Boepd in 3Q, with oil production approximately 72,200 - 72,300 Bopd, which the Company expects to mark the low period for the year. Given the significantly stronger than expected well performance, as well as the increase in development activity, NOG's production volumes are poised to increase significantly as it exits 2025. As a result, NOG is increasing annual production guidance as shown in the table below. In addition, the Company is tightening its annual capital expenditure guidance range. UPDATED 2025 FULL YEAR PRODUCTION AND CAPITAL EXPENDITURE GUIDANCE UPDATE ON HEDGING AND OTHER MATTERS In the third quarter, the Company recorded unrealized mark-to-market gains on derivatives of approximately $15.4 million, driven by changes to the value of the Company's derivatives portfolio. Realized hedge gains were an estimated $55.4 million, driven by the Company's natural gas, crude oil and basis hedges. The Company continues to execute its policy of protecting its capital program by periodically entering into financial derivative instruments with counterparties to lock in future commodity prices on a portion of its expected production. The Company has successfully continued to increase its hedge portfolio at attractive prices. As of the date of this release, the Company had an average of over 50,000 barrels per day of oil hedged for the fourth quarter of 2025, an average of over 48,000 barrels per day of oil hedged for the first quarter of 2026 and an average of over 35,000 barrels per day of oil hedged for calendar 2026, through a combination of swaps and collars. Additionally, NOG has an average of over 230 MMBtu per day of natural gas hedged for the fourth quarter of 2025, an average of over 220 MMBtu per day of natural gas hedged for the first quarter of 2026 and an average of over 200 million MMBtu per day of natural gas hedged for calendar 2026, through a combination of swaps and collars. An updated copy of NOG's hedge tables can be found below. The following table summarizes NOG's open crude oil derivative contracts scheduled to settle after September 30, 2025. The following table summarizes NOG's open gas commodity derivative contracts scheduled to settle after September 30, 2025. The following table summarizes NOG's open NGL commodity derivative swap contracts scheduled to settle after September 30, 2025. IMPAIRMENT UPDATE NOG accounts for its assets under the full-cost method under SEC guidelines, as opposed to the successful efforts method, which does not perform price-based asset tests. Driven by lower recent average oil prices, NOG expects to record a non-cash impairment charge of $310 to $330 million in the third quarter of 2025 under the "ceiling test" of the full cost pool on its assets. This non-cash charge will have no impact on cash flows. ABOUT NOG NOG is a real asset company with a primary strategy of acquiring and investing in non-operated minority working and mineral interests in the premier hydrocarbon producing basins within the contiguous United States. More information about NOG can be found at www.noginc.com. PRELIMINARY INFORMATION The preliminary unaudited third quarter 2025 financial and operating information included in this press release (including with respect to acquisitions, production, development activity, hedging, non-cash impairment charges, and other matters) are based on estimates and subject to completion of NOG's financial closing procedures. Such information has been prepared by management solely based on currently available information. The preliminary information does not represent and is not a substitute for a comprehensive statement of financial and operating results, and NOG's actual results may differ materially from these estimates because of final adjustments, the completion of NOG's financial closing procedures, and other developments after the date of this release. SAFE HARBOR This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the "Securities Act") and the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical facts included in this release regarding NOG's financial position, common stock dividends, including any increases thereto, business strategy, plans and objectives of management for future operations and industry conditions are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as "estimate," "project," "predict," "believe," "expect," "continue," "anticipate," "target," "could," "plan," "intend," "seek," "goal," "will," "should," "may" or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements. Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond NOG's control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on NOG's properties and properties pending acquisition, the effects of the COVID-19 pandemic and related economic slowdown, NOG's ability to acquire additional development opportunities, changes in NOG's reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which NOG conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, NOG's ability to consummate any pending acquisition transactions (including the transactions described herein), other risks and uncertainties related to the closing of pending acquisition transactions (including the transactions described herein), NOG's ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting NOG's operations, products, services and prices. NOG has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond NOG's control. NOG does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws. View source version on businesswire.com: https://www.businesswire.com/news/home/20251021821649/en/ back
PermRock Royalty Trust Declares Monthly Cash Distribution
PermRock Royalty Trust Declares Monthly Cash Distribution DALLAS, Oct. 21, 2025 /PRNewswire/ -- PermRock Royalty Trust (NYSE: PRT) (the "Trust") today declared a monthly cash distribution to record holders of its trust units representing beneficial interests in the Trust ("Trust Units") as of October 31, 2025, and payable on November 17, 2025, in the amount of $384,018.36 ($0.031565 per Trust Unit), based principally upon production during the month of August 2025. The following table displays underlying oil and natural gas sales volumes and average received wellhead prices attributable to the current and prior month net profits interest calculations: Underlying Sales Volumes Average Price Oil Natural Gas Oil Natural Gas Bbls Bbls/D Mcf Mcf/D (per Bbl) (per Mcf) Current Month 22,490 725 25,914 836 $58.06 $2.31 Prior Month 20,993 677 15,784 509 $65.79 $3.94 Oil cash receipts for the properties underlying the Trust totaled $1.31 million for the current month, a decrease of $0.07 million from the prior month's distribution period. This decrease was primarily due to a decrease in oil prices that was not offset by the increase in oil sales volumes. Natural gas cash receipts for the properties underlying the Trust totaled $0.06 million for the current month. This amount is essentially unchanged from the prior month's distribution period because the decrease in natural gas prices was offset by the increase in natural gas sales volumes. Total direct operating expenses, including marketing, lease operating expenses, and workover expenses, were $0.61 million, an increase of $0.18 million from the prior month's distribution period. This increase was related to completion of workover projects and the implementation of a chemical treatment program. Severance and ad valorem taxes included in this month's net profits calculation were $0.14 million. Total capital expenditures during the production month of August 2025 were $0.04 million. T2S Permian Acquisition II LLC ("T2S") informed the Trust that this amount was related to capital additions to a well operated by a third-party operator. T2S informed the Trust that this month's net profits calculation included the application of $0.10 million net to the Trust of funds previously reserved by T2S to cover capital obligations and expenses. About PermRock Royalty Trust PermRock Royalty Trust is a Delaware statutory trust formed to own a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties owned and operated by T2S in the Permian Basin of West Texas. For more information on PermRock Royalty Trust, please visit our website at www.permrock.com. Cautionary Statement Concerning Forward-Looking Statements Certain statements contained in this press release constitute "forward-looking statements." These forward-looking statements represent the Trust's and T2S's expectations or beliefs concerning future events, and it is possible that the results described in this press release will not be achieved. These forward-looking statements include the amount and date of any anticipated distribution to unitholders, future cash retentions, advancements or recoupments from distributions, and statements regarding T2S's operations and the resulting impact on the computation of the Trust's net profits. The amount of cash received or expected to be received by the Trust (and its ability to pay distributions) has been and will continue to be directly affected by volatility in commodity prices and oversupply. Other important factors that could cause actual results to differ materially from those projected in the forward-looking statements include expenses of the Trust and reserves for anticipated future expenses, uncertainties in estimating the cost of drilling activities and risks associated with drilling and operating oil and natural gas wells. Any forward-looking statement speaks only as of the date on which it is made, and, except as required by law, the Trust does not undertake any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. New factors emerge from time to time, and it is not possible for the Trust to predict all such factors. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in the Trust's Annual Report on Form 10-K filed with the SEC on March 31, 2025, and other public filings filed with the SEC. The risk factors and other factors noted in the Trust's public filings with the SEC could cause its actual results to differ materially from those contained in any forward-looking statement. The Trust's filed reports are or will be available over the Internet at the SEC's website at http://www.sec.gov. Contact: PermRock Royalty Trust Argent Trust Company, Trustee Nancy Willis, Director of Royalty Trust Services, Trust Administrator Toll-free: (855) 588-7839 Fax: (214) 559-7010 Website: www.permrock.com e-mail: trustee@permrock.com View original content:https://www.prnewswire.com/news-releases/permrock-royalty-trust-declares-monthly-cash-distribution-302589925.html SOURCE PermRock Royalty Trust
MEG Announces Postponement of Special Meeting of Shareholders to Vote on the Cenovus Transaction to Thursday, October 30, 2025
MEG Announces Postponement of Special Meeting of Shareholders to Vote on the Cenovus Transaction to Thursday, October 30, 2025 Approximately 63% of the MEG Shares represented by proxy or expected to be voted in person at the Meeting are FOR the approval of the Cenovus Transaction, despite opposition from Strathcona which is assumed to have voted against the Cenovus TransactionThe Meeting has been postponed, pursuant to Cenovus exercising its contractual postponement right, to Thursday, October 30, 2025 at 9:00 a.m. (Calgary Time) to allow MEG Shareholders additional time to deposit their proxies and vote FOR the Cenovus TransactionDeadline for MEG Shareholders to deposit their proxies to vote on the Cenovus Transaction revised to Wednesday, October 29, 2025 at 9:00 a.m. (Calgary Time)Deadline for MEG Shareholders to make an election with respect to their preferred form of consideration to be received under the Cenovus Transaction revised to Tuesday, October 28, 2025 at 4:30 p.m. (Calgary Time)On October 14, 2025, leading independent proxy advisory firm ISS reaffirmed its recommendation that MEG Shareholders vote FOR the Cenovus TransactionFor questions or assistance with voting or making elections, contact Sodali & Co., 1.888.999.2785 or 1.289.695.3075 for banks, brokers, and callers outside North America, assistance@investor.sodali.comAll amounts in Canadian dollars unless specified. CALGARY, AB, Oct. 21, 2025 /CNW/ - MEG Energy Corp. (TSX: MEG) ("MEG", or the "Company") announced today that its special meeting (the "Meeting") of holders ("MEG Shareholders") of common shares of MEG ("MEG Shares") to vote on the proposed plan of arrangement (the "Cenovus Transaction") involving MEG, the MEG Shareholders and Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) ("Cenovus"), previously scheduled for Wednesday, October 22, 2025, has been postponed to Thursday, October 30, 2025 at 9:00 a.m. (Calgary Time). The Meeting has been postponed at the request of Cenovus pursuant to its postponement right under the arrangement agreement between MEG and Cenovus dated August 21, 2025 (the "Arrangement Agreement") as amended by an amending agreement dated October 7, 2025 (the "Amending Agreement"). At the time the Meeting was postponed, approximately 63% of the MEG Shares represented by proxy or expected to be voted in person at the Meeting are FOR the approval of the Cenovus Transaction, despite opposition from Strathcona Resources Ltd. ("Strathcona") which is assumed to have voted against the Cenovus Transaction. The Cenovus Transaction is conditional upon, among other things, the approval by MEG Shareholders holding at least 66â % of the MEG Shares represented in person or by proxy at the Meeting. The Meeting has been postponed to provide MEG Shareholders additional time to deposit proxies and vote FOR the Cenovus Transaction. Vote FOR the Cenovus Transaction The Board of Directors of MEG (the "MEG Board") unanimously recommends MEG Shareholders vote FOR the Cenovus Transaction for the following reasons: Enhanced Premium. The implied value of the transaction consideration of $29.52 per MEG Share based on the closing price of the common shares of Cenovus (the "Cenovus Shares") on October 20, 2025 represents a 44% premium to MEG's unaffected 20-day volume-weighted average share price on May 15, 2025, the last trading day before Strathcona's initial public announcement that it intended to acquire MEG. The Cenovus Transaction values MEG at approximately $8.5 billion (including assumed debt), or approximately $79,000 per bpd, the highest value ever paid for a pure-play oil sands asset.Preferred Strategic Alternative After Comprehensive Review of All Alternatives. MEG's comprehensive review process involved outreach to over 15 parties and the publicly-announced process gave other parties the opportunity to express interest. MEG received three non-binding proposals, including one from Cenovus, and through rigorous negotiations, MEG secured an increase in the Cenovus offer from $25.00 to $27.25 per MEG Share (at announcement) and increased the equity component from 20% to 25%. Following further negotiation, the Amending Agreement provided for increased transaction consideration of $29.52 per MEG Share, as of October 20, 2025, with an increase in the equity component from 25% to 50%, representing the third enhancement from the terms originally put forward by Cenovus.Participation in Realization of Significant Synergies. The Cenovus Transaction provides MEG Shareholders the ability to participate in future upside through ownership in Cenovus, an industry-leading producer with significant scale and growth potential. The combined company will benefit from greater efficiencies and significant synergies, and Cenovus expects to realize approximately $150 million in near-term annual synergies, increasing to over $400 million per year in 2028 and beyond. Increased equity consideration under the Amending Agreement further enhances participation by MEG Shareholders in the synergies expected from the Cenovus Transaction.Upside Potential in Cenovus Shares. 100% of equity research analysts covering Cenovus rate the Cenovus Shares with a "buy" recommendation. The Cenovus Transaction offers MEG Shareholders an option to choose their preferred form of consideration in the form of the Cash Consideration (as defined herein), the Share Consideration (as defined herein) or a combination thereof. Increased equity consideration under the Amending Agreement further enhances upside participation for MEG Shareholders.Accelerates MEG's Standalone Value. Cenovus plans to spend an incremental ~$400 million of capital between 2026-2028 to accelerate value and deliver production capacity of 150,000 bpd at Christina Lake by 2028, 15,000 bpd above what is expected of MEG's standalone business plan.Certainty of Value and Robust Liquidity. The Cenovus Transaction offers a high degree of value certainty, with 50% of the value of total consideration in highly liquid Cenovus Shares and 50% in cash. The Cenovus Shares will be freely tradeable immediately upon closing.Recommended by Both Independent Proxy Advisory Firms. On September 26, 2025 and September 30, 2025, Institutional Shareholder Services Inc. ("ISS") and Glass, Lewis & Co., respectively, announced that they recommend MEG Shareholders vote FOR the Cenovus Transaction. On October 14, 2025, ISS reaffirmed its recommendation that MEG Shareholders vote FOR the Cenovus Transaction following MEG's announcement on October 8, 2025 of the improved consideration.For additional details, please refer to MEG's investor presentation dated October 8, 2025, which is available at www.megenergy.com/offer-update. Vote FOR the Cenovus Transaction Today – Deadline Approaching The MEG Board urges you to deposit your proxy form or voting instruction form and vote FOR the Cenovus Transaction ahead of the revised proxy deadline of Wednesday, October 29, 2025 at 9:00 a.m. (Calgary Time) (the "Revised Proxy Deadline"). No further action is required of MEG Shareholders who have already voted their MEG Shares FOR the Cenovus Transaction.MEG Shareholders who have not already voted are recommended to vote their MEG Shares FOR the Cenovus Transaction promptly, and in any case, prior to the Revised Proxy Deadline, using the instructions provided in their proxy form or voting instruction form.MEG Shareholders who previously voted their MEG Shares AGAINST the Cenovus Transaction are recommended to revoke their prior vote and cast their vote FOR the Cenovus Transaction promptly, and in any case, prior to the Revised Proxy Deadline. The later-dated proxy form or voting instruction form will revoke any previous vote made by such MEG Shareholders.MEG Shareholders who tendered their MEG Shares to the now terminated unsolicited take-over bid by Strathcona, as varied and extended, are recommended to cast their vote FOR the Cenovus Transaction promptly, and in any case, prior to the Revised Proxy Deadline.Due to time sensitivity and the Canada Post strike, MEG Shareholders are strongly encouraged to only vote online or by telephone using the instructions below: Registered MEG Shareholders Beneficial MEG Shareholders Who? If your MEG Shares are held in your name and represented by a physical certificate or direct registration system advice ("DRS Advice") If your MEG Shares are held with a broker, bank or other intermediary Telephone Call 1.866.732.VOTE (8683) (toll-free in North America) or 1.312.588.4290 (outside North America) using the 15-digit control number found in your proxy. If you have not received your 15-digit control number, please contact 1-800-564-6253 (toll-free in North America) or +1-514-982-7555 (outside North America). Call the toll-free number on your voting instruction form (VIF) and vote using the 16-digit control number provided therein Online www.investorvote.com (requires your 15-digit control number from your broker) www.proxyvote.com (requires your 16-digit control number from your broker) Questions and Assistance with Voting If you are a beneficial MEG Shareholder and have not yet received your voting materials, please contact your broker or investment advisor to obtain your 16-digit control number and vote immediately at www.proxyvote.com. Alternatively, contact Sodali & Co. at 1-888-999-2785 or assistance@investor.sodali.com for help casting your vote. Reminder to Submit Your Election for Your Preferred Consideration MEG also reminds MEG Shareholders to submit their elections in respect of the consideration to be received pursuant to the Cenovus Transaction. To be valid, MEG Shareholders must submit their elections to Computershare Investor Services Inc. (the "Depositary"), who is acting as depositary in connection with the Cenovus Transaction, by Tuesday, October 28, 2025 at 4:30 p.m. (Calgary Time) (the "Revised Election Deadline"). The Cenovus Transaction provides MEG Shareholders with a choice to elect their preferred form of consideration and each MEG Shareholder will be entitled to elect to receive: i. $29.50 in cash per MEG Share ("Cash Consideration"); or ii. 1.240 Cenovus Shares per MEG Share ("Share Consideration"); or iii. a combination of Cash Consideration and Share Consideration, in all cases, subject to rounding and proration based on maximum aggregate Cash Consideration of approximately $3.8 billion and maximum aggregate Share Consideration of approximately 157.7 million Cenovus Shares, as set out in the Arrangement Agreement, as amended by the Amending Agreement. The value of the Cenovus Transaction consideration represents a mix of 50% cash and 50% Cenovus Shares. On a fully prorated basis, consideration per MEG Share represents approximately $14.75 in cash and 0.620 of a Cenovus Share. The consideration to be received by MEG Shareholders values MEG at $29.52 per MEG Share on a fully prorated basis at Cenovus's closing share price on October 20, 2025, representing an enterprise value of approximately $8.5 billion, including assumed debt. MEG Shareholders who do not submit their election ahead of the Revised Election Deadline will be deemed to have elected to receive Cash Consideration with respect to 50% of their MEG Shares and Share Consideration with respect to 50% of their MEG Shares. No further action is required of MEG Shareholders who previously submitted an election and who do not wish to change such election, including the mix of Cash Consideration and Share Consideration elected.MEG Shareholders who previously submitted an election and who wish to change such election, including the mix of Cash Consideration and Share Consideration elected, must re-submit their election using the instructions below prior to the Revised Election Deadline.MEG Shareholders who have not submitted an election are encouraged to submit their election in respect of the Cenovus Transaction using the instructions below prior to the Revised Election Deadline.MEG Shareholders who have already made an election, whether for all Cash Consideration, all Share Consideration, or a combination thereof, are encouraged to consider their election in light of the Cenovus Transaction. If a MEG Shareholder desires to change their prior election, such MEG Shareholder should re-submit their election using the instructions below prior to the Revised Election Deadline. Notwithstanding the election or deemed election of a MEG Shareholder for Cash Consideration or Share Consideration, such MEG Shareholder may receive a combination of Cash Consideration and Share Consideration (or a different combination than what was elected by such MEG Shareholder), depending on the elections (including deemed elections) made by all other MEG Shareholders. A MEG Shareholder will not actually receive any consideration until the Cenovus Transaction is completed and all required documents are submitted to the Depositary, including a Letter of Transmittal and Election Form and any certificate(s) or DRS Advice(s) representing their MEG Shares. Due to the time sensitivity and the Canada Post strike, MEG recommends that all MEG Shareholders make their elections and courier or hand deliver the required documentation as soon as possible and in advance of the Revised Election Deadline to permit delivery to the Depositary at or prior to the Revised Election Deadline in accordance with the below instructions. Please courier or hand deliver the required documentation to Computershare Investor Services Inc. at any of the following addresses: Toronto: 320 Bay Street, 14th Floor, Toronto, ON, M5H 4A6, Canada, 1.416.263.2900 Montreal: 650 de Maisonneuve Blvd. West, 7th floor, Montreal, QC, H3A 3T2, Canada, 1.514.982.7888 Vancouver: 510 Burrard St, 3rd Floor, Vancouver, BC, V6C 3B9, Canada, 1.604.661.9400 Calgary: 800 – 324 8 Avenue SW Calgary, AB, T2P 2Z2, Canada, 1.403.267.6800 Registered MEG Shareholders: No further action is required of registered MEG Shareholders who have already submitted an election and who do not wish to change such election, including the mix of Cash Consideration and Share Consideration elected. For the benefit of registered MEG Shareholders who have not yet made an election in respect of the consideration they wish to receive under the Cenovus Transaction, or who wish to change their election, MEG has delivered a revised Letter of Transmittal and Election Form to each registered MEG Shareholder which outlines the necessary documentation and information required to make such election. The revised Letter of Transmittal and Election Form reflecting the Cenovus Transaction is for use by registered MEG Shareholders only and can be found at: https://www.megenergy.com/investors/shareholder-information/special-meeting-of-meg-shareholders/ and on MEG's SEDAR+ issuer profile at www.sedarplus.ca. Registered MEG Shareholders can refer to the instructions contained in the revised Letter of Transmittal and Election Form and should ensure they provide the required documentation and information to the Depositary ahead of the Revised Election Deadline. Beneficial MEG Shareholders: No further action is required of beneficial MEG Shareholders who have already submitted an election and who do not wish to change such election, including the mix of Cash Consideration and Share Consideration elected. Beneficial MEG Shareholders (MEG Shareholders whose MEG Shares are not registered in their name but are held by an intermediary or broker) who have not yet made an election or who wish to change their election may provide instructions to their broker or other nominee to make or change the election on such beneficial MEG Shareholder's behalf. Intermediaries and brokers may establish earlier deadlines to make an election, and MEG urges such beneficial MEG Shareholders to contact their intermediary or broker for specific instructions. Registered MEG Shareholders have the right to dissent with respect to the Cenovus Transaction and to be paid by MEG the fair value of their MEG Shares in accordance with the provisions of Section 191 of the Business Corporations Act (Alberta), as modified by the interim order of the Court of King's Bench of Alberta (the "Court") granted September 9, 2025 (the "Interim Order") and the plan of arrangement, as amended by the Amending Agreement. Any dissent notices must be received by MEG, c/o Burnet, Duckworth & Palmer LLP, attention: Paul Chiswell, email: pchiswell@bdplaw.com by 5:00 p.m. (Calgary Time) on the revised deadline of Monday, October 27, 2025. MEG Shareholders should review the Circular (as defined herein) for additional information with respect to their rights of dissent and how to exercise such dissent rights. MEG's application to the Court for a final order in respect of the Cenovus Transaction will follow the MEG Meeting (the "Final Order Application"). MEG Shareholders and any other interested parties that wish to attend the Final Order Application must file with the Court and serve upon MEG, c/o Burnet, Duckworth & Palmer LLP, attention: Paul Chiswell, email: pchiswell@bdplaw.com, a notice of intention to appear on or before 5:00 p.m. (Calgary Time) on the revised deadline of Monday, October 27, 2025, which notice must comply with the instructions set out in the Circular. MEG filed an information circular ("Circular") on September 12, 2025, providing further details on the Cenovus Transaction, election process and the upcoming Meeting. MEG Shareholders are encouraged to review the Circular. In accordance with the Interim Order, certain information provided in the Circular was revised in MEG's press release dated October 10, 2025 to reflect recent updates. Copies of the Circular, the revised Letter of Transmittal and Election Form, the Amending Agreement, and additional information on the Meeting can be found at: https://www.megenergy.com/investors/shareholder-information/special-meeting-of-meg-shareholders/. Updated Meeting Details MEG Shareholders will vote on the Cenovus Transaction at the Meeting which will be held on Thursday, October 30, 2025 at 9:00 a.m. (Calgary Time) at Brookfield Place, 225 – 6th Avenue S.W., Suite 1400, Calgary, Alberta or through a live audio webcast accessible at https://meetings.lumiconnect.com/400-560-917-636. The password for the live audio webcast of the Meeting is "meg2025", case-sensitive. Advisors BMO Capital Markets and Burnet, Duckworth & Palmer LLP are acting as financial advisor and legal counsel, respectively, to the Company. RBC Capital Markets and Norton Rose Fulbright Canada LLP are acting as financial advisor and legal counsel, respectively, to the Special Committee of the MEG Board. Forward-Looking Information Certain statements contained in this news release may contain forward-looking statements and forward-looking information (collectively, "forward-looking information") within the meaning of applicable Canadian securities laws. All statements other than statements of historical fact may be forward-looking statements. Forward-looking information is frequently characterized by words such as "will", "expects", "plan", "potential", "growth", "future" and other similar words or statements that certain events or conditions "likely", "may", "should", "would", "might" or "could" occur. Forward-looking information is often, but not always, identified by such words. Forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements, many of which are beyond MEG's control. MEG believes the expectations reflected in the forward-looking information are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking information included in this news release should not be unduly relied upon. Specific forward-looking information contained in this news release includes, among others, statements pertaining to the following: the timing of the Revised Proxy Deadline and of the Revised Election Deadline and the impact of failing to meet such deadlines; expectations regarding the MEG Shares to be voted at the Meeting; the completion of the Cenovus Transaction, including the anticipated timing thereof and satisfaction of the closing conditions under the Amending Agreement; anticipated benefits of the Cenovus Transaction including participation in future upside of Cenovus; that the combined company will benefit from greater efficiencies and significant synergies including Cenovus's expectations to realize $150 million in near-term annual synergies, increasing to $400 million per year in 2028 and beyond; the scale and growth potential of Cenovus; Cenovus's plans to spend incremental capital of approximately $400 million between 2026-2028 to deliver production capacity of 150,000 bpd at Christina Lake by 2028; the expected production capacity that would result from MEG's standalone business plan; that the Cenovus Transaction offers a high degree of value certainty; that the Cenovus Shares will be freely tradeable upon closing and that such Cenovus Shares will be highly liquid; the treatment of previously submitted proxies; the form of consideration that MEG Shareholders will receive under the Cenovus Transaction, including as a result of proration based on elections (including deemed elections) made by other MEG Shareholders; the timing of receipt of consideration under the Cenovus Transaction; the exercise of dissent rights in respect of the Cenovus Transaction; the timing of the Final Order Application; the timing and location of the Meeting; the impact of any Canada Post strike on the ability of MEG Shareholders to submit their proxies or Letters of Transmittal and Election Forms in respect of the Cenovus Transaction; and other similar statements. Forward-looking information is based on, among other things, MEG's expectations regarding its future, growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. Such forward-looking information reflects MEG's current beliefs and assumptions and is based on information currently available to it. With respect to forward-looking information contained in this news release, assumptions have been made regarding, among other things: the satisfaction of the conditions to closing the Cenovus Transaction; the approval of the Cenovus Transaction at the Meeting and the completion of the Cenovus Transaction on anticipated terms and timing, or at all; MEG's standalone business plan; the future Cenovus Share price and the liquidity of the Cenovus Shares; that Cenovus is an industry-leading producer with significant scale and growth potential; that actions by third parties do not delay or otherwise adversely affect completion of the Cenovus Transaction; future crude oil, bitumen blend, natural gas, electricity, condensate and other diluent prices; that tariffs currently in effect will remain the same; the combined company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; foreign exchange rates and interest rates; the applicability of technologies for the recovery and production of reserves and contingent resources; the recoverability of reserves and contingent resources; the ability to produce and market production of bitumen blend successfully to customers; MEG's ability to maintain its dividend and capital programs; future production levels and SOR; future capital and other expenditures; operating costs; anticipated sources of funding for operations and capital investments; the regulatory framework governing royalties, land use, taxes and environmental matters, including federal and provincial climate change policies, in the jurisdictions in which MEG and Cenovus conduct and will conduct their business; future debt levels; geological and engineering estimates in respect of reserves and contingent resources; the geography of the areas in which MEG is conducting exploration and development activities; the impact of increasing competition; the ability to obtain financing on acceptable terms; and business prospects and opportunities. Many of the foregoing assumptions are subject to change and are beyond MEG's control. Some of the risks that could affect MEG's future results and could cause actual results to differ materially from those expressed in the forward-looking information include: the risk that the Cenovus Transaction may be varied, accelerated or terminated in certain circumstances; risks relating to the outcome of the Cenovus Transaction, including the risks associated with approval at the Meeting; the risk that the conditions to closing the Cenovus Transaction may not be satisfied, or to the extent permitted, waived; the risk that operating results will differ from what is currently anticipated; MEG's status and stage of development; the concentration of MEG's production in a single project; the majority of MEG's total reserves and contingent resources are non-producing and/or undeveloped; the uncertainty of reserve and resource estimates; long-term reliance on third parties; the effect or outcome of litigation; the effect of any diluent supply constraints and increases in the cost thereof; the potential delays of and costs of overruns on projects and future expansions of MEG's assets; operational hazards; competition for, among other things, capital, the acquisition of reserves and resources, pipeline capacity and skilled personnel; risks inherent in the bitumen recovery process; changes to royalty regimes; the failure of MEG to meet specific requirements in respect of its oil sands leases; claims made by Indigenous peoples; unforeseen title defects and changes to the mineral tenure framework; risks arising from future acquisition activities; sufficiency of funds; fluctuations in market prices for crude oil, natural gas, electricity and bitumen blend; future sources of insurance for MEG's property and operations; public health crises, similar to the COVID-19 pandemic, including weakness and volatility of crude oil and other petroleum products prices from decreased global demand resulting from public health crises; risk of war (including the conflicts between Russia and Ukraine and Israel, Hamas and Iran); general economic, market and business conditions; volatility of commodity inputs; variations in foreign exchange rates and interest rates; hedging strategies; national or global financial crisis; environmental risks and hazards, including natural hazards such as regional wildfires, and the cost of compliance with environmental legislation and regulations, including greenhouse gas regulations, potential climate change legislation and potential land use regulations; enacted and proposed export and import restrictions, including but not limited to tariffs, export taxes or curtailment on exports; failure to accurately estimate abandonment and reclamation costs; the need to obtain regulatory approvals and maintain compliance with regulatory requirements; the extent of, and cost of compliance with, laws and regulations and the effect of changes in such laws and regulations from time to time including changes which could restrict MEG's ability to access foreign capital; failure to obtain or retain key personnel; potential conflicts of interest; changes to tax laws (including without limitation, a potential United States border adjustment tax) and government incentive programs; the potential for management estimates and assumptions to be inaccurate; risks associated with establishing and maintaining systems of internal controls; risks associated with the tariffs imposed on the import and export of commodities and the possibility that such tariffs may change; political risks and terrorist attacks; risks associated with downgrades in the credit ratings for MEG's securities; cybersecurity errors, omissions or failures; restrictions contained in MEG's credit facilities, other agreements relating to indebtedness and any future indebtedness; any requirement to incur additional indebtedness; MEG defaulting on its obligations under its indebtedness; and the inability of MEG to generate cash to service its indebtedness. The foregoing list of risks, uncertainties and factors is not exhaustive. The effect of any one risk, uncertainty or factor on particular forward-looking information is not determinable with certainty as these factors are independent, and management's future course of action would depend on an assessment of all available information at that time. Although, based on information available to MEG on the date of this news release, MEG believes that the expectations in and assumptions used in such forward-looking information are reasonable, MEG gives no assurances as to future results, levels of activity or achievements and cannot make assurances that actual results will be consistent with such forward-looking information. Accordingly, readers are cautioned that the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive. Further information regarding the assumptions and risks inherent in the making of forward-looking statements and in respect of the Cenovus Transaction can be found under the heading "Risk Factors" in MEG's annual information form dated February 27, 2025 for the year ended December 31, 2024 and under the heading "Forward-Looking Statements" in the Circular, along with MEG's other public disclosure documents which are available through the Company's website at http://www.megenergy.com/investors and through the SEDAR+ website at www.sedarplus.ca. The forward-looking information included in this news release is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this news release is made as of the date of this news release and MEG assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by applicable Canadian securities laws. Due to the risks, uncertainties and assumptions inherent in forward-looking information, readers should not place undue reliance on this forward-looking information. For further information: Shareholder Questions: MEG Investor Relations, 403.767.0515, invest@megenergy.com Sodali & Co., 1.888.999.2785 or 1.289.695.3075 for banks, brokers, and callers outside North America, assistance@investor.sodali.com Media Questions: MEG Media Relations, 403.775.1131, media@megenergy.com SOURCE MEG Energy Corp. View original content to download multimedia: http://www.newswire.ca/en/releases/archive/October2025/21/c9716.html