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Expro Group Holdings N.V. to Participate at the Barclays 39th Annual CEO Energy-Power Conference
Expro Group Holdings N.V. to Participate at the Barclays 39th Annual CEO Energy-Power Conference HOUSTON, Aug. 07 /BusinessWire/ -- Expro Group Holdings N.V. (NYSE:XPRO) ("Expro" or the "Company") today announced that Michael Jardon, Chief Executive Officer, will participate in a panel discussion with certain industry peers at the Barclays CEO Energy-Power Conference at 1:50 p.m. ET on Wednesday, September 3, 2025. Expro's presentation can be accessed via Barclays CEO Energy-Power Conference or under the Investor section of www.expro.com. ABOUT EXPRO Working for clients across the well life cycle, Expro is a leading provider of energy services, offering cost-effective, innovative solutions and what the Company considers to be best-in-class safety and service quality. The Company's extensive portfolio of capabilities spans well construction, well flow management, subsea well access, and well intervention and integrity solutions. With roots dating to 1938, Expro has approximately 8,500 employees and provides services and solutions to leading exploration and production companies in both onshore and offshore environments in more than 50 countries. For more information, please visit and connect with Expro on X (formerly Twitter): @ExproGroup and LinkedIn: @Expro. View source version on businesswire.com: https://www.businesswire.com/news/home/20250807095705/en/ back
Enerflex Ltd. Announces Second Quarter 2025 Financial and Operational Results
Enerflex Ltd. Announces Second Quarter 2025 Financial and Operational Results RECORD ADJUSTED EBITDA OF $130 MILLION ENGINEERED SYSTEMS BACKLOG STEADY AT $1.2 BILLION; ENERGY INFRASTRUCTURE CONTRACT BACKLOG REMAINS STRONG AT $1.5 BILLION CAPITAL EXPENDITURES FOR 2025 TARGETED AT APPROXIMATELY $120 MILLION, INCLUDING APPROXIMATELY $60 MILLION FOR GROWTH OPPORTUNITIES $18 MILLION RETURNED TO SHAREHOLDERS DURING Q2/25 THROUGH DIVIDEND AND SHARE REPURCHASES CALGARY, Alberta, Aug. 07, 2025 (GLOBE NEWSWIRE) -- Enerflex Ltd. (TSX:EFX.CA) (NYSE:EFXT) ("Enerflex" or the "Company") today reported its financial and operational results for the three months ended June 30, 2025. All amounts presented are in U.S. Dollars unless otherwise stated. Q2/25 FINANCIAL AND OPERATIONAL OVERVIEW Generated revenue of $615 million compared to $614 million in Q2/24 and $552 million in Q1/25.Recorded gross margin before depreciation and amortization of $175 million, or 29% of revenue, compared to $173 million, or 28% of revenue in Q2/24 and $161 million, or 29% of revenue during Q1/25. EI and After-Market Services ("AMS") product lines generated 65% of consolidated gross margin before depreciation and amortization during Q2/25.Engineered Systems ("ES") gross margin before depreciation and amortization decreased to 18% in Q2/25 compared to 19% in Q2/24, primarily due to product mix. SG&A was $61 million for the three months ended June 30, 2025, down $14 million from the prior year period, driven by cost-saving initiatives, improved operational efficiencies, and the absence of one-time integration costs incurred in Q2/24.Adjusted earnings before finance costs, income taxes, depreciation, and amortization ("adjusted EBITDA") of $130 million is a new quarterly record for Enerflex and compares to $122 million in Q2/24 and $113 million during Q1/25. Adjusted EBITDA benefitted from higher gross margin before depreciation and amortization, cost-saving initiatives and operational efficiencies.Cash provided by operating activities before changes in working capital increased to $89 million in Q2/25 compared to $63 million in Q2/24 and $62 million in Q1/25, a function of higher adjusted EBITDA, lower net finance costs, and lower current tax expense.Free cash flow was a use of cash of $39 million in Q2/25 compared to a use of cash of $4 million during Q2/24 and source of cash of $85 million during Q1/25. Compared to the second quarter of 2024, an increase in cash provided by operating activities before changes in working capital was more than offset by increased growth capital spending and a build in net working capital, notably: (1) strategic inventory investments to support future projects, including work in progress related to EI assets and purchases of select major components with increasing lead times; (2) income taxes payable; and (3) executive transition costs.Return on capital employed ("ROCE")1 increased to 16.4% in Q2/25 compared to 1.7% in Q2/24 and 14.2% in Q1/25. ROCE during the second quarter of 2025 was the highest in over five years, benefitting on a year-over-year basis from an increase in trailing 12-month EBIT and lower average capital employed, predominantly due to a decline in net debt.Net earnings increased to $60 million or $0.49 per share in Q2/25 compared to $5 million or $0.04 per share in Q2/24 and $24 million or $0.19 per share in Q1/25. Compared to Q2/24, profitability benefitted from higher gross margin, lower SG&A expenses, lower net finance costs, reduced income tax expense, and an unrealized gain of $15 million related to the redemption options of its senior secured notes.Invested $71 million in the business, consisting of $34 million in capital expenditures ($23 million for growth) and $37 million for expansion of an EI project in the EH region that was commissioned in Q3/25 and accounted for as a finance lease. The Company now expects capital expenditures of approximately $120 million this year (previous guidance of $110 million to $130 million), including approximately $60 million allocated to growth opportunities.ES backlog as at June 30, 2025 of $1.2 billion was consistent on a year-over-year and sequential basis, providing strong visibility into future revenue generation and business activity levels. Bookings of $365 million during Q2/25 compared to $331 million in Q2/24, $205 million in Q1/25 and a trailing eight quarter average of $329 million. The ES book-to-bill ratio (calculated as bookings divided by revenue) was 1.1x during Q2/25 and was 1.0x on a trailing 12-month basis, highlighting that the Company is consistently replenishing its backlog in line with project execution.Enerflex's U.S. contract compression business continues to perform well, led by increasing natural gas production in the Permian. This business generated revenue of $38 million and gross margin before depreciation and amortization of 74% during Q2/25 compared to $37 million and 65% in Q2/24 and $36 million and 72% during Q1/25. Revenue during Q2/25 reflects a shift in rental mix towards longer-term projects and a year-over-year reduction in non-rental activity.Utilization remained stable at 94% across a fleet size of approximately 456,000 horsepower. Enerflex expects its North American contract compression fleet will grow to over 475,000 horsepower by the end of 2025. 1 ROCE is calculated by taking EBIT for the 12-month trailing period divided by capital employed. Capital employed is average debt and Shareholders' equity less average cash for the trailing four quarters. SHAREHOLDER RETURNS The Board of Directors has declared a quarterly dividend of C$0.0375 per share, payable on September 2, 2025, to shareholders of record on August 18, 2025.During Q2/25, Enerflex repurchased 1,899,200 Common Shares at an average price of C$10.08 per share. Under the current normal course issuer bid ("NCIB"), the Company is authorized to acquire up to a maximum of 6,159,695 Common Shares or approximately 5% of its public float as at the application date, for cancellation. The NCIB commenced on April 1, 2025 and will terminate no later than March 31, 2026. BALANCE SHEET AND LIQUIDITY Enerflex exited Q2/25 with net debt of $608 million, which included $71 million of cash and cash equivalents, a decrease of $155 million compared to Q2/24 and $44 million higher than the first quarter of 2025. The increase in net debt compared to the first quarter of 2025 was a function of higher cash provided by operating activities before changes in working capital being more than offset by increased growth capital spending and a build in net working capital.Enerflex's bank-adjusted net debt-to-EBITDA ratio was approximately 1.3x at the end of Q2/25, down from 2.2x at the end of Q2/24 and consistent with Q1/25.On July 11, Enerflex entered into an amended and restated credit agreement with respect to its syndicated secured revolving credit facility (the "RCF"). The maturity date of the RCF has been extended by three years to July 11, 2028, and availability is unchanged at $800 million. The Company also continues to maintain a $70 million unsecured credit facility (the "LC Facility") with one of the lenders in its RCF syndicate. MANAGEMENT COMMENTARY Preet S. Dhindsa, Enerflex's President and Chief Executive Officer (Interim), stated: "We're proud to deliver another quarter of strong financial and operational performance, reflecting the consistent execution and resilience of our global platform. Our Energy Infrastructure and After-Market Services business lines continue to perform well, reinforcing Enerflex's capacity to generate stable returns. We maintain solid visibility in our Engineered Systems business, supported by a healthy $1.2 billion backlog at the end of Q2/25, while continuing to closely monitor evolving market dynamics. The long-term fundamentals driving our growth, including global energy security, and the continued increases in demand for natural gas, remain firmly in place and we believe Enerflex is well positioned to take advantage of opportunities across our global platform." Joe Ladouceur, Enerflex's Chief Financial Officer (Interim), added: "Enerflex maintained a solid financial position in Q2/25, holding our leverage ratio steady at 1.3 times. Our focus remains on generating sustainable free cash flow, maintaining balance sheet strength, and driving long-term value creation. We continue to prioritize profitability and operational resilience to ensure Enerflex delivers strong and reliable returns for our shareholders." 1EBITDA is defined as earnings before finance costs, income taxes, depreciation and amortization. EBIT is defined as earnings before finance costs and income taxes. 2Net debt is defined as total long-term debt less cash and cash equivalent as presented in the Financial Statements. 3Refer to the "ES Bookings and Backlog" section of the MD&A for further details.4Refer to the "EI Contract Backlog" section of the MD&A for further details.5Refer to the "GM before D&A by Product Line and Recurring GM before D&A" section of the MD&A for further details.6Refer to the "Adjusted EBITDA" section of the MD&A for further details. 7Refer to the "Non-IFRS Measures" section of the MD&A for further details.8Determined by using the trailing 12-month period. Enerflex's interim consolidated financial statements and notes (the "financial statements") and Management's Discussion and Analysis ("MD&A") as at June 30, 2025, can be accessed on the Company's website at www.enerflex.com and under the Company's SEDAR+ and EDGAR profiles at www.sedarplus.ca and www.sec.gov/edgar, respectively. OUTLOOK Enerflex's near-term priorities remain unchanged and include: (1) enhancing the profitability of core operations; (2) leveraging the Company's leading position in core operating countries to capitalize on expected increases in natural gas and produced water volumes; and (3) maximizing free cash flow to further strengthen Enerflex's financial position, provide direct shareholder returns, and invest in selective customer supported growth opportunities. Enerflex continues to expect operating results to be underpinned by the highly contracted EI product line and the recurring nature of AMS, which together are expected to account for approximately 65% of gross margin before depreciation and amortization during 2025. The EI product line is supported by customer contracts expected to generate approximately $1.5 billion of revenue over their remaining terms. Demand in the ES product line remains constructive, although the Company is actively monitoring near-term risks and uncertainties, including the impact of tariffs and commodity price volatility. Enerflex expects ES revenue to remain steady in the near term, supported by a backlog of approximately $1.2 billion as at June 30, 2025, and gross margin for the ES product line to align more closely with historical averages, reflective of a shift in project mix. The medium-term outlook for each of Enerflex's product lines remains attractive, supported by anticipated growth in the supply of natural gas and associated liquids, especially within Enerflex's North American footprint. Capital Allocation Enerflex is refining its capital expenditure guidance for 2025. The Company now expects capital expenditures of approximately $120 million this year (prior guidance of $110 million to $130 million), including approximately $60 million allocated to growth opportunities (prior guidance of $40 million to $60 million) and $60 million for maintenance and PP&E expenditures (prior guidance $70 million). Growth investments will focus on customer-supported opportunities, primarily in the U.S. contract compression business line, where market fundamentals remain strong. This strength is underpinned by expected increases in natural gas production in the Permian Basin and continued capital discipline from industry participants. Providing meaningful direct shareholder returns is a priority for Enerflex. During Q2/25, Enerflex returned $18 million to shareholders through dividend ($4 million) and share repurchases ($14 million). The current NCIB commenced on April 1, 2025, and will terminate no later than March 31, 2026, with the Company authorized to acquire up to a maximum of 6,159,695 Common Shares or approximately 5% of its public float as at the application date, for cancellation. During Q2/25, Enerflex repurchased 1,899,200 Common Shares at an average price of C$10.08 per share Going forward, capital allocation decisions will be based on delivering value to Enerflex shareholders and measured against Enerflex's ability to maintain balance sheet strength. In addition to disciplined growth capital spending, share repurchases and dividends, Enerflex will also consider further debt reduction to strengthen its balance sheet and lower net finance costs. Unlocking greater financial flexibility positions the Company to respond to evolving market conditions and capitalize on opportunities to optimize its debt stack. DIVIDEND DECLARATION Enerflex is committed to paying a sustainable quarterly cash dividend to shareholders. The Board of Directors has declared a quarterly dividend of C$0.0375 per share, payable on September 2, 2025, to shareholders of record on August 18, 2025. CONFERENCE CALL AND WEBCAST DETAILS Investors, analysts, members of the media, and other interested parties, are invited to participate in a conference call and audio webcast on Thursday, August 7, 2025 at 8:00 a.m. (MDT), where members of senior management will discuss the Company's results. A question-and-answer period will follow. To participate, register at https://register-conf.media-server.com/register/BI5f86b18a965d4257a4408154efdc3493. Once registered, participants will receive the dial-in numbers and a unique PIN to enter the call. The audio webcast of the conference call will be available on the Enerflex website at www.enerflex.com under the Investors section or can be accessed directly at https://edge.media-server.com/mmc/p/b7388nss/. NON-IFRS MEASURES Throughout this news release and other materials disclosed by the Company, Enerflex employs certain measures to analyze its financial performance, financial position, and cash flows, including net debt-to-EBITDA ratio and bank-adjusted net debt-to-EBITDA ratio. These non-IFRS measures are not standardized financial measures under IFRS and may not be comparable to similar financial measures disclosed by other issuers. Accordingly, non-IFRS measures should not be considered more meaningful than generally accepted accounting principles measures as indicators of Enerflex's performance. Refer to "Non-IFRS Measures" of Enerflex's MD&A for the three months ended June 30, 2025, for information which is incorporated by reference into this news release and can be accessed on Enerflex's website at www.enerflex.com and under the Company's SEDAR+ and EDGAR profiles at www.sedarplus.ca and www.sec.gov/edgar, respectively. 1The Company included net earnings (loss), income taxes, and net finance costs on a consolidated basis to reconcile to EBIT.2Net finance costs are considered corporate expenditures and therefore have not been allocated to reporting segments.3EBIT includes $15 million gain on redemption options associated with the Notes. Debt is managed within Corporate and is not allocated to reporting segments. 1The Company included net earnings (loss), income taxes, and net finance costs on a consolidated basis to reconcile to EBIT.2Net finance costs are considered corporate expenditures and therefore have not been allocated to reporting segments. FREE CASH FLOW The Company defines free cash flow as cash provided by (used in) operating activities, less total capital expenditures (growth and maintenance) for EI assets - operating leases and PP&E, mandatory debt repayments, and lease payments, while proceeds on disposals of PP&E and EI assets - operating leases are added back. Free cash flow may not be comparable to similar measures presented by other companies as it does not have a standardized meaning under IFRS. Management uses this non-IFRS measure to assess the level of free cash generated to fund other non-operating activities. These activities could include dividend payments, share repurchases, and non-mandatory debt repayments. Free cash flow is also used in calculating the dividend payout ratio. 1Enerflex also refers to cash provided by operating activities before changes in working capital and other as "Funds from Operations" or "FFO".2Enerflex also refers to cash provided by operating activities as "Cashflow from Operations" or "CFO". BANK-ADJUSTED NET DEBT-TO-EBITDA RATIO The Company defines net debt as short- and long-term debt less cash and cash equivalents at period end, which is then divided by EBITDA for the trailing 12-months. In assessing whether the Company is compliant with the financial covenants related to its debt instruments, certain adjustments are made to net debt and EBITDA to determine Enerflex's bank-adjusted net debt-to-EBITDA ratio. These adjustments and Enerflex's bank-adjusted net-debt-to EBITDA ratio are calculated in accordance with, and derived from, the Company's financing agreements. GROSS MARGIN BEFORE DEPRECIATION AND AMORTIZATION Gross margin before depreciation and amortization is a non-IFRS measure defined as gross margin excluding the impact of depreciation and amortization. The historical costs of assets may differ if they were acquired through acquisition or constructed, resulting in differing depreciation. Gross margin before depreciation and amortization is useful to present operating performance of the business before the impact of depreciation and amortization that may not be comparable across assets. ADVISORY REGARDING FORWARD-LOOKING INFORMATION This news release contains "forward-looking information" within the meaning of applicable Canadian securities laws and "forward-looking statements" (and together with "forward-looking information", "FLI") within the meaning of the safe harbor provisions of the US Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are FLI. The use of any of the words "anticipate", "believe", "could", "expect", "future", "may", "potential", "should", "will" and similar expressions, (including negatives thereof) are intended to identify FLI. In particular, this news release includes (without limitation) FLI pertaining to: expectations that the North American contract compression fleet will grow to over 475,000 horsepower by the end of 2025;Enerflex's ability to leverage long-term fundamentals, including global energy security, and the continued increases in demand for natural gas to take advantage of opportunities across Enerflex's global platform, and the time required in connection therewith, if at all;Enerflex's ability to generate sustainable free cash flow, maintain its balance sheet strength, and drive long-term value creation, and the time required in connection therewith, if at all;disclosures under the heading "Outlook" including: Enerflex's ability to deliver on its near-term priorities, including (1) enhancing the profitability of its core operations; (2) leveraging the Company's leading position in core operating countries to capitalize on expected increases in natural gas and produced water volumes; and (3) maximizing free cash flow to further strengthen Enerflex's financial position, provide direct shareholder returns, and invest in selective customer supported growth opportunities, and the time required in connection therewith, if at all;the highly contracted EI product line and the recurring nature of AMS will, together, account for approximately 65% of Enerflex's gross margin before depreciation and amortization during 2025;customer contracts within Enerflex's EI product line will generate approximately $1.5 billion of revenue over their remaining terms;ES gross margins are expected to align more closely with historical averages while ES revenue will remain steady in the near term;supply of natural gas and associated liquids and produced water volumes are anticipated to grow, especially within Enerflex's North American footprint, supporting an attractive medium-term outlook for each of Enerflex's product lines;total capital expenditures in 2025 will be approximately $120 million, including approximately $60 million allocated to growth opportunities and $60 million for maintenance and PP&E expenditures;continued strength in the market fundamentals for U.S. contract compression, underpinned by expected increases in natural gas production in the Permian Basin and continued capital discipline from industry participants;considerations to further reduce debt which will strengthen Enerflex's balance sheet and lower net financing costs and that doing so will position the Company to respond to evolving market conditions and capitalize on opportunities to optimize its debt stack; the ability of Enerflex to continue to pay a sustainable quarterly cash dividend; andusing free cash generated to fund other non-operating activities including dividend payments, share repurchases, and non-mandatory debt repayments, if at all. FLI reflect Management's current beliefs and assumptions with respect to such things as the impact of general economic conditions; commodity prices; the markets in which Enerflex's products and services are used; general industry conditions, forecasts, and trends; changes to, and introduction of new, governmental regulations, laws, and income taxes; increased competition; availability of qualified personnel; political unrest and geopolitical conditions; and other factors, many of which are beyond the control of Enerflex. More specifically, Enerflex's expectations in respect of its FLI are based on a number of assumptions, estimates and projections developed based on past experience and anticipated trends, including but not limited to: the ability of the Company to navigate evolving market conditions and to adjust its business as needed to support long-term resilience and performance in response to increased near-term risks and uncertainties, including the impact of tariffs and commodity price volatility;natural gas and associated liquids and produced water volumes across Enerflex's global footprint will increase in line with expectations;market conditions, customer activity, and industry fundamentals will support stable demand across Enerflex's product lines and geographic regions throughout 2025;the high level of contractual commitments within the EI product line and the predictable, recurring revenue from AMS will continue;existing customer contracts within the EI product line will remain in effect and with no material cancellations or renegotiations over their remaining terms;the execution of projects within the ES product line will proceed as scheduled and the conversion to revenue will proceed without significant delays or cancellations;no significant unforeseen cost overruns or project delays;market conditions continuing to support the NCIB within the anticipated timeframe; andEnerflex will maintain sufficient cash flow, profitability, and financial flexibility to support the ongoing payment of a sustainable quarterly cash dividend, subject to market conditions, operational performance, and board approval. As a result of the foregoing, actual results, performance, or achievements of Enerflex could differ and such differences could be material from those expressed in, or implied by, the FLI. The principal risks, uncertainties and other factors affecting Enerflex and its business are identified under the heading "Risk Factors" in: (i) Enerflex's Annual Information Form for the year ended December 31, 2024, dated February 27, 2025; and (ii) Enerflex's Annual Report dated February 26, 2025, as well as in the Company's MD&A as at June 30, 2025 and in other filings with Canadian securities regulators and the SEC, copies of which are available under the electronic profile of the Company on SEDAR+ and EDGAR at www.sedarplus.ca and www.sec.gov/edgar, respectively. Other unpredictable or unknown factors not discussed in this news release could have material adverse effects on the actual results, performance, or achievements of Enerflex expressed in, or implied by, the FLI. The FLI included in this news release are made as of the date of this news release and are based on the information available to the Company at such time and, other than as required by law, Enerflex disclaims any intention or obligation to update or revise any FLI, whether as a result of new information, future events, or otherwise. This news release and its contents should not be construed, under any circumstances, as investment, tax, or legal advice. The outlook provided in this news release is based on assumptions about future events, including economic conditions and proposed courses of action, based on Management's assessment of the relevant information currently available. The outlook is based on the same assumptions and risk factors set forth above and is based on the Company's historical results of operations. The outlook set forth in this news release was approved by Management and the Board of Directors. Management believes that the prospective financial information set forth in this news release has been prepared on a reasonable basis, reflecting Management's best estimates and judgments, and represents the Company's expected course of action in developing and executing its business strategy relating to its business operations. The prospective financial information set forth in this news release should not be relied on as necessarily indicative of future results. Actual results may vary, and such variance may be material. ABOUT ENERFLEX Enerflex is a premier integrated global provider of energy infrastructure and energy transition solutions, deploying natural gas, low-carbon, and treated water solutions - from individual, modularized products and services to integrated custom solutions. With over 4,400 engineers, manufacturers, technicians, and innovators, Enerflex is bound together by a shared vision: Transforming Energy for a Sustainable Future. The Company remains committed to the future of natural gas and the critical role it plays, while focused on sustainability offerings to support the energy transition and growing decarbonization efforts. Enerflex's common shares trade on the Toronto Stock Exchange under the symbol "EFX" and on the New York Stock Exchange under the symbol "EFXT". For more information about Enerflex, visit www.enerflex.com. For investor and media enquiries, contact: Preet S. DhindsaPresident and Chief Executive Officer (Interim)E-mail: PDhindsa@enerflex.com Joe LadouceurChief Financial Officer (Interim)E-mail: JLadouceur@enerflex.com Jeff FetterlyVice President, Corporate Development and Capital MarketsE-mail: JFetterly@enerflex.com
ProFrac Holding Corp. Reports Second Quarter 2025 Results
ProFrac Holding Corp. Reports Second Quarter 2025 Results WILLOW PARK, Texas, Aug. 07 /BusinessWire/ -- ProFrac Holding Corp. (NASDAQ:ACDC) ("ProFrac", or the "Company") today announced financial and operational results for its second quarter ended June 30, 2025. Second Quarter 2025 Results Total revenue was $502 million compared to first quarter 2025 revenue of $600 million Net loss was $104 million compared to net loss of $15 million in first quarter 2025 Adjusted EBITDA(1) was $79 million compared to $130 million in first quarter 2025; 16% of revenue in the second quarter compared to 22% of revenue in first quarter 2025 Net cash provided by operating activities of $100 million compared to $39 million in first quarter 2025 Capital expenditures of $47 million compared to $53 million in first quarter 2025 Free cash flow(2) of $54 million compared to $(14) million in first quarter 2025 "Our second quarter results reflected the market headwinds that emerged following the sharp commodity price decline in early April, generally consistent with the outlook we provided with our first quarter results. That said, our operational excellence initiatives continued to deliver value, particularly our asset management program, which is driving impressive capital efficiency gains and enabling us to optimize our capital investments. Additionally, we exceeded our expectations on adjusted EBITDA less capital expenditures and continue to be a leader in our industry on that metric. Since second quarter end, a number of crews have returned to work and we have seen a modest improvement in frac calendar utilization versus the recent trough. Further, we're encouraged by increasing customer engagement around 2026 planning, and believe that given the current market dynamics in hydraulic fracturing, a simultaneous increase in both oil-directed and gas-directed activity could lead to favorable market tightening early next year," said Matt Wilks, ProFrac's Executive Chairman. "While we remain focused on operational excellence and the high-quality service delivery that differentiates ProFrac in the market, we also continue to be strategic and opportunistic in advancing key initiatives that further position us for long-term success. Our ProPilot platform, which is delivering transformational improvements in automated fracturing operations, is a prime example of this. We continue to invest in and develop our ProPilot automation system and have deployed ProPilot to all of our active fleets. Our innovative Flotek partnership unlocked immediate value while providing ownership exposure to a highly scalable gas quality and asset integrity management business. Additionally, we strengthened our financial flexibility through targeted debt refinancing measures that provide incremental liquidity. These initiatives underscore our commitment to creating sustainable competitive advantages while maintaining disciplined capital allocation," concluded Mr. Wilks. Outlook In the Stimulation Services segment, ProFrac's active fleet count reached a trough in late June-early July, and since that time the Company has redeployed incremental fleets as of July 31, 2025. Although activity has improved from the trough, the Company believes that its third quarter segment results will decrease relative to the second quarter results. The Company's asset management approach continues to provide capital efficiency in addition to flexibility in maintenance scheduling and fleet deployment, enabling optimal equipment performance and strategic resource allocation. In the Proppant Production segment, the Company expects volumes to remain relatively flat compared to the second quarter exit rate, with efficiency gains expected to drive segment profitability levels similar to the second quarter despite the lower sequential volumes. Business Segment Information The Stimulation Services segment generated revenues of $432 million in second quarter 2025, which resulted in $51 million of Adjusted EBITDA and a margin of 12%. This compared with $525 million in revenues in first quarter 2025, which resulted in $105 million of Adjusted EBITDA and a margin of 20%. The Proppant Production segment generated revenues of $78 million in second quarter 2025, which resulted in $15 million of Adjusted EBITDA and a margin of 19%. This compared with revenues of $67 million in first quarter 2025, which resulted in $18 million of Adjusted EBITDA and a margin of 27%. Approximately 58% of the Proppant Production segment's revenue was intercompany during second quarter 2025. The Manufacturing segment generated revenues of $56 million in second quarter 2025, which resulted in $7 million of Adjusted EBITDA and a margin of 13%. This compared with revenues of $66 million in first quarter 2025, which resulted in $4 million of Adjusted EBITDA and a margin of 6%. Approximately 78% of the Manufacturing segment's revenue was intercompany during second quarter 2025. Other Business Activities generated revenues of $65 million in second quarter 2025, which resulted in $8 million of Adjusted EBITDA and a margin of 12%. This compared with revenues of $62 million in first quarter 2025, which resulted in $8 million of Adjusted EBITDA and a margin of 13%. ProFrac's Other Business Activities include the results of Flotek Industries and Livewire Power. Capital Expenditures and Capital Allocation Cash capital expenditures totaled $47 million in the second quarter, a decline from the $53 million reported in first quarter 2025. The Company's vertical integration and various strategic initiatives enable it to respond rapidly to evolving market conditions. On capital allocation, the Company has made significant progress to reduce its capital expenditure needs without sacrificing service quality, operational efficiency or our ability to deploy high-quality additional fleets quickly. Previously the Company noted that it had identified approximately $70-100 million in potential capital expenditure reductions to flexibly align with evolving market conditions. The Company now expects to incur approximately $175 million to $225 million in capital expenditures in 2025 driven primarily by frac fleet maintenance and selective growth initiatives, as well as improvements at Alpine aimed at increasing quality and throughput at the mines, particularly in South Texas and at mines located in the Haynesville Shale. Balance Sheet and Liquidity Total debt outstanding as of June 30, 2025 was $1.08 billion while total principal amount of debt outstanding as of June 30, 2025 was $1.11 billion. Net debt(3) outstanding as of June 30, 2025 was $1.08 billion. Total cash and cash equivalents as of June 30, 2025 was $26 million, of which $5 million was related to Flotek and not accessible by the Company. As of June 30, 2025 the Company had $108 million of liquidity, including approximately $21 million in cash and cash equivalents, excluding Flotek, and $87 million of availability under its asset-based credit facility. Footnotes Conference Call ProFrac has scheduled a conference call on Thursday, August 7, 2025, at 11:00 a.m. Eastern / 10:00 a.m. Central. To register for and access the event, please click here. An archive of the webcast will be available shortly after the call's conclusion on the IR Calendar section of ProFrac's investor relations website for 90 days. About ProFrac Holding Corp. ProFrac Holding Corp. is a technology-focused, vertically integrated and innovation-driven energy services holding company providing hydraulic fracturing, proppant production, related completion services and complementary products and services to leading upstream oil and natural gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources. ProFrac operates through three business segments: Stimulation Services, Proppant Production and Manufacturing, in addition to Other Business Activities. For more information, please visit ProFrac's website at www.PFHoldingsCorp.com. Cautionary Statement Regarding Forward-Looking Statements Certain statements in this press release may be considered "forward-looking statements" within the meaning of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements may be accompanied by words such as "may," "should," "expect," "intend," "will," "estimate," "anticipate," "believe," "predict," or similar words. Forward-looking statements relate to future events or the Company's future financial or operating performance. These forward-looking statements include, among other things, statements regarding: the Company's strategies and plans for growth; the Company's positioning, resources, capabilities, and expectations for future performance; customer, market and industry demand and expectations; the Company's expectations about contributions of acquired entities; fleet deployment levels; the Company's expectations about price fluctuations, and macroeconomic conditions impacting the industry; competitive conditions in the industry; the Company's ability to increase the utilization of its mining assets and lower our mining costs per ton; success of the Company's ongoing strategic initiatives; the risks relating to launching a new business; the Company's intention to increase the number of fully integrated fleets; the Company's currently expected guidance regarding its 2025 financial and operational results; the Company's ability to earn its targeted rates of return; pricing of the Company's services in light of the prevailing market conditions; the impact of continued inflation, risk of a global recession, and U.S. trade policy, including the imposition of tariffs and retaliatory measures; the Company's currently expected guidance regarding its planned capital expenditures; statements regarding the Company's liquidity and debt obligations; the Company's anticipated timing for operationalizing and amount of contribution from its fleets and its sand mines; expectations regarding pricing per ton range; the amount of capital that may be available to the Company in future periods; any financial or other information based upon or otherwise incorporating judgments or estimates relating to future performance, events or expectations; any estimates and forecasts of financial and other performance metrics; and the Company's outlook and financial and other guidance. Such forward-looking statements are based upon assumptions made by the Company as of the date hereof and are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed or implied by such forward-looking statements. Factors that may cause actual results to differ materially from current expectations include, but are not limited to: the ability to achieve the anticipated benefits of the Company's acquisitions, mining operations, and vertical integration strategy, including risks and costs relating to integrating acquired assets and personnel; risks that the Company's actions intended to achieve its 2025 financial and operational guidance will be insufficient to achieve that guidance, either alone or in combination with external market, industry or other factors; risks related to the imposition of tariffs and retaliatory measures, and changes in U.S. trade policy; the failure to operationalize or utilize to the extent anticipated the Company's fleets and sand mines in a timely manner or at all; the Company's ability to deploy capital in a manner that furthers the Company's growth strategy, as well as the Company's general ability to execute its business plans; the risk that the Company may need more capital than it currently projects or that capital expenditures could increase beyond current expectations; risks regrading access to additional capital; industry conditions, including fluctuations in supply, demand and prices for the Company's products and services and for oil and natural gas; global and regional economic and financial conditions, including as they may be affected by hostilities in the Middle East and in Ukraine; the effectiveness of the Company's risk management strategies; and other risks and uncertainties set forth in the sections entitled "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements" in the Company's filings with the Securities and Exchange Commission ("SEC"), which are available on the SEC's website at www.sec.gov. Forward-looking statements are also subject to the risks and other issues described below under "Non-GAAP Financial Measures," which could cause actual results to differ materially from current expectations included in the Company's forward-looking statements included in this press release. Nothing in this press release should be regarded as a representation by any person that the forward-looking statements set forth herein will be achieved or that any of the contemplated results of such forward-looking statements will be achieved, including without limitation any expectations about the Company's operational and financial performance or achievements through and including 2025. There may be additional risks about which the Company is presently unaware or that the Company currently believes are immaterial that could also cause actual results to differ from those contained in the forward-looking statements. The reader should not place undue reliance on forward-looking statements, which speak only as of the date they are made. The Company anticipates that subsequent events and developments will cause its assessments to change. However, while the Company may elect to update these forward-looking statements at some point in the future, it expressly disclaims any duty to update these forward-looking statements, except as otherwise required by law. Non-GAAP Financial Measures Adjusted EBITDA, Free Cash Flow and Net Debt are non-GAAP financial measures and should not be considered as a substitute for net income (loss), net cash from operating activities, or GAAP measurements of debt, respectively, or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted EBITDA, Free Cash Flow and Net Debt are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, research analysts and others, to assess our financial performance. We believe Adjusted EBITDA is an important supplemental measure because it allows us to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization) and items outside the control of our management team (such as income tax rates). We believe Free Cash Flow is an important supplemental liquidity measure of the cash that is available (if any), after purchases of property and equipment, for operational expenses, investment in our business, and to make acquisitions, and Free Cash Flow is useful to investors as a liquidity measure because it measures our ability to generate or use cash in excess of our capital investments in property and equipment. We believe Net Debt is an important supplemental measure of indebtedness for management and investors because it provides a more complete understanding of our leverage position and borrowing capacity after factoring in cash and cash equivalents. We define Adjusted EBITDA as our net income (loss), before (i) interest expense, net, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) loss or gain on disposal of assets, net, (v) stock-based compensation, and (vi) other charges, such as certain credit losses, gain or loss on extinguishment of debt, unrealized loss or gain on investments, acquisition and integration expenses, litigation expenses and accruals for legal contingencies, acquisition earnout adjustments, severance charges, goodwill impairments, gains on insurance recoveries, transaction costs, third-party supply commitment charges, lease termination costs, and impairments of long-lived assets. We define Free Cash Flow as net cash provided by or (used in) operating activities less investment in property, plant and equipment plus proceeds from sale of assets. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA should not be considered as an alternative to net income (loss). Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of this non-GAAP financial measure may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Net cash provided by operating activities is the GAAP measure most directly comparable to Free Cash Flow. Free Cash Flow should not be considered as an alternative to net cash provided by operating activities. Free Cash Flow has important limitations as an analytical tool including that Free Cash Flow does not reflect the cash requirements necessary to service our indebtedness and Free Cash Flow is not a reliable measure for actual cash available to the Company at any one time. Because Free Cash Flow may be defined differently by other companies in our industry, our definition of this Non-GAAP Financial Measure may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Net Debt is defined as total debt plus unamortized debt discounts, premiums, and issuance costs less cash and cash equivalents. Total debt is the GAAP measure most directly comparable to Net Debt. Net Debt should not be considered as an alternative to total debt. Net Debt has important limitations as a measure of indebtedness because it does not represent the total amount of indebtedness of the Company. The presentation of Non-GAAP Financial Measures is not intended to be a substitute for, and should not be considered in isolation from, the financial measures reported in accordance with GAAP. The following tables present a reconciliation of the Non-GAAP Financial Measures of Adjusted EBITDA, Free Cash Flow and Net Debt to the most directly comparable GAAP financial measure for the periods indicated. - Tables to Follow- View source version on businesswire.com: https://www.businesswire.com/news/home/20250807902507/en/ back
Kinetik Reports Second Quarter 2025 Financial and Operating Results and Updates Full Year 2025 Guidance
Kinetik Reports Second Quarter 2025 Financial and Operating Results and Updates Full Year 2025 Guidance Generated second quarter net income of $74.4 million and Adjusted EBITDA1 of $242.9 million Commenced commissioning at the Kings Landing Complex ("Kings Landing") with full commercial in-service expected in late September 2025, providing long overdue relief for producers with material curtailed production on the Delaware North system and allowing for resumption of new development activity Updating the Company's 2025 Adjusted EBITDA1 Guidance range to $1.03 billion to $1.09 billion Continue to expect fourth quarter 2025 annualized Adjusted EBITDA1,2 of approximately $1.2 billion Narrowing the 2025 Capital Guidance range to $460 million to $530 million, including growth and maintenance Began construction of the ECCC Pipeline, connecting the western portion of Kinetik's system between Eddy and Culberson counties and providing further critical rich gas takeaway capacity relief for the Delaware North system HOUSTON & MIDLAND, Texas, Aug. 06 /BusinessWire/ -- Kinetik Holdings Inc. (NYSE:KNTK) ("Kinetik" or the "Company") today reported financial results for the quarter ended June 30, 2025. Second Quarter 2025 Results and Commentary For the three and six months ended June 30, 2025, Kinetik reported net income including noncontrolling interest of $74.4 million and $93.7 million, respectively. Kinetik generated Adjusted EBITDA1 of $242.9 million and $493.0 million, Distributable Cash Flow1 of $153.3 million and $310.3 million, and Free Cash Flow1 of $7.9 million and $128.3 million for the three and six months ended June 30, 2025, respectively. For the three months ended June 30, 2025, Kinetik processed natural gas volumes of 1.75 Bcf/d. "Kinetik navigated both successes and challenges in the second quarter of 2025," said Jamie Welch, Kinetik's President & Chief Executive Officer. "First and foremost, I am incredibly proud of our team's focus on operational execution and meeting our customers' needs during a period marked with macroeconomic uncertainty and market volatility. For the quarter, we reported Adjusted EBITDA1 of $243 million with processed gas volumes growing 11% year-over-year. That growth was partially offset by lower commodity pricing and higher operating costs." "Kinetik's earnings trajectory remains weighted to the second half of 2025 with the full in-service of Kings Landing. The associated return of curtailed production and customer development activity at Delaware North will result in material processed gas volume growth throughout the fourth quarter of this year and into 2026." Welch continued, "With the expected in-service timing for Kings Landing, some delays in producer development activity to early 2026, as well as commodity price headwinds and associated operating cost increases, particularly relating to rental equipment and electricity, we are updating our full year 2025 Adjusted EBITDA1 Guidance range to $1.03 billion to $1.09 billion." "Capital Expenditures3 were $126 million in the second quarter as we started commissioning Kings Landing. We now anticipate Capital Expenditures3 to be more weighted to the third quarter of 2025 driven by timing of Kings Landing completion. We are narrowing full year Capital Guidance to $460 million to $530 million, including growth and maintenance Capital Expenditures3 and any contingent consideration tied to the final cost of Kings Landing." "Looking ahead, Management remains confident in Kinetik's value proposition as we continue to see numerous commercial opportunities with both new and existing customers that are highly synergistic to our existing footprint and accretive to our business in 2026 and beyond." Financial Achieved quarterly net income of $74.4 million and Adjusted EBITDA1 of $242.9 million. Repurchased $172.8 million4 of Class A common stock year to date under the existing Repurchase Program, of which $72.6 million was repurchased during the second quarter of 2025. Completed refinancing of the Company's Term Loan A and Revolving Credit Facility, extending maturities to May 30, 2028 and May 30, 2030, respectively. Exited the quarter with a Leverage Ratio1,5 per the Company's Credit Agreement of 3.6x and a Net Debt to Adjusted EBITDA1,6 Ratio of 4.0x. Selected Key Metrics Operational and Construction Commenced commissioning at Kings Landing with full commercial in-service expected in late September 2025. Construction started on ECCC Pipeline with in-service expected during the first half of 2026. Filed acid gas injection permit for Kings Landing with approval expected by the end of 2025. Governance and Sustainability Listed Kinetik's common stock on NYSE Texas while maintaining its primary listing on the New York Stock Exchange. Published 2024 Sustainability Report highlighting the Company's sustainability initiatives, progress, and achievements. Infinium commenced construction on Project Roadrunner, an ultra-low carbon electrofuels production site, in Reeves County, Texas. Kinetik will be the long-term CO2 feedstock provider upon expected completion in 2027. Upcoming Tour Dates Kinetik plans to participate at the following upcoming conferences and events: Citi Natural Resources Conference in Las Vegas on August 12th - 13th Barclays CEO Energy-Power Conference in New York on September 3rd PEP Energy Conference in Austin on September 29th Wolfe Utilities, Midstream & Clean Energy Conference in New York on September 30th Investor Presentation An updated investor presentation will be available under Events and Presentations in the Investors section of the Company's website at www.ir.kinetik.com. Conference Call and Webcast Kinetik will host its second quarter 2025 results conference call on Thursday, August 7, 2025 at 8:00 am Central Daylight Time (9:00 am Eastern Daylight Time) to discuss second quarter results. To access a live webcast of the conference call, please visit the Investors section of Kinetik's website at www.ir.kinetik.com. A replay of the conference call will also be available on the website following the call. About Kinetik Holdings Inc. Kinetik is a fully integrated, pure-play, Permian-to-Gulf Coast midstream C-corporation operating in the Delaware Basin. Kinetik is headquartered in Houston and Midland, Texas. Kinetik provides comprehensive gathering, transportation, compression, processing and treating services for companies that produce natural gas, natural gas liquids, crude oil and water. Kinetik posts announcements, operational updates, investor information and press releases on its website, www.kinetik.com. Forward-looking statements This news release includes certain statements that may constitute "forward-looking statements" for purposes of the federal securities laws. Forward-looking statements include, but are not limited to, statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions. The words "anticipate," "believe," "continue," "could," "estimate," "expect," "intends," "may," "might," "plan," "seeks," "possible," "potential," "predict," "project," "prospects," "guidance," "outlook," "should," "would," "will," and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. These statements include, but are not limited to, statements about the Company's future business strategy and plans, expectations, and objectives for the Company's operations, including statements about strategy, synergies, sustainability goals and initiatives, portfolio monetization opportunities, expansion projects and the timing thereof, and future operations, and financial guidance; growth opportunities; the amount and timing of future shareholder returns; the Company's projected dividend amounts and the timing thereof; and the Company's leverage and financial profile. While forward-looking statements are based on assumptions and analyses made by us that we believe to be reasonable under the circumstances, whether actual results and developments will meet our expectations and predictions depend on a number of risks and uncertainties, which could cause our actual results, performance, and financial condition to differ materially from our expectations. See Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2024. Any forward-looking statement made by us in this news release speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement whether as a result of new information, future development, or otherwise, except as may be required by law. Additional information Additional information follows, including a reconciliation of Adjusted EBITDA, Distributable Cash Flow, Free Cash Flow, and Net Debt (non-GAAP financial measures) to the GAAP measures. Non-GAAP financial measures Kinetik's financial information includes information prepared in conformity with generally accepted accounting principles (GAAP) as well as non-GAAP financial information. It is management's intent to provide non-GAAP financial information to enhance understanding of our consolidated financial information as prepared in accordance with GAAP. Adjusted EBITDA, Distributable Cash Flow, Free Cash Flow, Dividend Coverage Ratio, Net Debt and Leverage Ratio are non-GAAP measures. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP and reconciliations from these results should be carefully evaluated. See "Reconciliation of GAAP to Non-GAAP Measures" elsewhere in this news release. This news release also includes certain forward-looking non-GAAP financial information. Reconciliations of these forward-looking non-GAAP measures to their most directly comparable GAAP measure are not available without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various reconciling items that would impact the most directly comparable forward-looking GAAP financial measure, that have not yet occurred, are out of Kinetik's control and/or cannot be reasonably predicted. Accordingly, such reconciliation is excluded from this new release. Forward-looking non-GAAP financial measures provided without the most directly comparable GAAP financial measures may vary materially from the corresponding GAAP financial measures. A non-GAAP financial measure. See "Non-GAAP Financial Measures" and "Reconciliation of GAAP to Non-GAAP Measures" for further details. A reconciliation of expected full year or annualized fourth quarter 2025 Adjusted EBITDA to net income (loss), the closest GAAP financial measure, cannot be provided without unreasonable efforts due to the inherent difficulty in quantifying certain amounts, including share-based compensation expense, which is affected by factors including future personnel needs and the future prices of our Class A Common Stock, which may be significant. Net of contributions in aid of construction and returns of invested capital from unconsolidated affiliates. Dollar value of Kinetik Class A common stock repurchased year to date as of August 6, 2025. Leverage Ratio is total debt less cash and cash equivalents divided by last twelve months Adjusted EBITDA, calculated per the Company's credit agreement. The calculation includes EBITDA Adjustments for Qualified Projects, Acquisitions and Divestitures. Net Debt to Adjusted EBITDA Ratio is defined as Net Debt divided by last twelve months Adjusted EBITDA. Dividend Coverage Ratio is Distributable Cash Flow divided by total declared dividends. Issued and outstanding shares of 156,322,500 is the sum of 63,545,388 shares of Class A common stock and 92,777,112 shares of Class C common stock. Excludes 7,680,492 shares of Class C common stock issued on July 1, 2025 in connection with the Durango Permian acquisition. Net Debt is defined as total current and long-term debt, excluding deferred financing costs, less cash and cash equivalents. (1) Adjusted EBITDA is defined as net income including noncontrolling interest adjusted for interest, taxes, depreciation and amortization, gain or loss on disposal of assets and debt extinguishment, the proportionate EBITDA from our EMI pipelines, share-based compensation expense, noncash increases and decreases related to commodity hedging activities, integration and transaction costs and extraordinary losses and unusual or non-recurring charges. Adjusted EBITDA provides a basis for comparison of our business operations between current, past and future periods by excluding items that we do not believe are indicative of our core operating performance. Adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income including non-controlling interest or any other measure of financial performance presented in accordance with GAAP. (2) Distributable Cash Flow is defined as Adjusted EBITDA, adjusted for the proportionate EBITDA from unconsolidated affiliates, returns on invested capital from unconsolidated affiliates, interest expense, net of amounts capitalized, unrealized gains or losses on interest rate swaps and maintenance capital expenditures. Distributable Cash Flow should not be considered as an alternative to the GAAP measure of net income including non-controlling interest or any other measure of financial performance presented in accordance with GAAP. We believe that Distributable Cash Flow is a useful measure to compare cash generation performance from period to period and to compare the cash generation performance for specific periods to the amount of cash dividends we make. (3) Free Cash Flow is defined as Distributable Cash Flow adjusted for growth capital expenditures, investments in unconsolidated affiliates, returns of invested capital from unconsolidated affiliates, cash interest, capitalized interest, realized gains or losses on interest rate swaps and contributions in aid of construction. Free Cash flow should not be considered as an alternative to the GAAP measure of net income including non-controlling interest or any other measure of financial performance presented in accordance with GAAP. We believe that Free Cash Flow is a useful performance measure to compare cash generation performance from period to period and to compare the cash generation performance for specific periods to the amount of cash dividends that we make. (4) Net Debt is defined as total short-term and long-term debt, excluding deferred financing costs, premiums and discounts, less cash and cash equivalents. Net Debt illustrates our total debt position less cash on hand that could be utilized to pay down debt at the balance sheet date. Net Debt should not be considered as an alternative to the GAAP measure of total long-term debt, or any other measure of financial performance presented in accordance with GAAP. View source version on businesswire.com: https://www.businesswire.com/news/home/20250806647507/en/ back
Ring Energy Announces Second Quarter 2025 Results and Updates Guidance
Ring Energy Announces Second Quarter 2025 Results and Updates Guidance THE WOODLANDS, Texas, Aug. 06, 2025 (GLOBE NEWSWIRE) -- Ring Energy, Inc. (NYSE American: REI) ("Ring" or the "Company") today reported operational and financial results for the second quarter of 2025 and updated guidance for the remainder of the year. Second Quarter 2025 Highlights Sold record 14,511 barrels of oil per day ("Bo/d"), exceeding the mid point of guidance and record 21,295 barrels of oil equivalent per day ("Boe/d") which was near the mid point of guidance;Reported net income of $20.6 million, or $0.10 per diluted share, and Adjusted Net Income1 of $11.0 million, or $0.05 per diluted share;Recorded Adjusted EBITDA1 of $51.5 million;Incurred Lease Operating Expense ("LOE") of $10.45 per Boe, 9% below the low end of guidance due to proactive efforts to reduce costs;Invested $16.8 million in capital expenditures which was lower than the mid point of guidance and 48% lower than 1Q 2025;Generated Adjusted Cash Flow from Operations1 of $41.6 million and record Adjusted Free Cash Flow ("AFCF")1 of $24.8 million;Remained cash flow positive for the 23rd consecutive quarter, paid down $12 million of debt during the period, and had liquidity of $137.0 million at June 30, 2025;Entered into a Third Amended and Restated Credit Agreement with a borrowing base of $585 million and an extended maturity of 34 months, to June 2029, supported by an 11-member banking syndicate; andReaffirmed production and capital expenditures guidance and lowered LOE per BOE guidance for the second half of 2025, provided 3Q 2025 guidance, and updated capital expenditures guidance for the full year 2025. Management Commentary Mr. Paul D. McKinney, Chairman of the Board and Chief Executive Officer, commented, "We are excited to announce our second quarter operational and financial performance and the results of our reduced capital spending initiatives. In response to the drop in oil prices that occurred early in the second quarter, we provided revised guidance reducing our second quarter and annual capital spending plans to reflect a year-over-year ("YOY") reduction of 36% while maintaining 2% YOY production growth. Our Q2 results demonstrate that we are successfully executing this plan. With the benefit of our first full quarter operating the Lime Rock assets, our oil sales set a new Company record this quarter coming in near the high-end of guidance and our total sales on a Boe basis were near to the mid-point of guidance, also setting a new Company record. We reduced our second quarter capex by 48% over the previous quarter which was near the low end of our revised Q2 guidance. Contributing to our success this quarter was the outperformance of our existing PDP assets and recently acquired Lime Rock assets as well as the robust performance of the new wells drilled and brought online so far this year. Thanks to the operational excellence of our team, we have continued to make progress reducing operating costs in this volatile commodity price environment. Our progress in this regard was evidenced by our lease operating expense of $10.45 per Boe in the quarter, which is below the low end of guidance which is why we reduced our LOE/Boe guidance by $0.50 for the last half of the year. As a result of our strong production, reduced capital expenditures, and reduced LOE, we generated a record of $24.8 million in Adjusted Free Cash Flow for the quarter despite an 11% reduction in realized pricing per Boe as compared to Q1. We are proud of the team and their efforts that led to these results and encouraged by the success and flexibility provided by our value-focused, proven strategy. The results of our second quarter demonstrate the quality and resilience of our team and assets and the changes we implemented this quarter should allow us to pay down debt more aggressively than we have in previous quarters despite lower commodity prices." Mr. McKinney concluded, "This quarter underscores a key strength of our value-focused, proven strategy, the ability to swiftly adapt to changing market conditions while delivering consistent shareholder value, even in low-price environments. Our focus on oil-rich assets with shallow declines, long lifespans, and low operating costs ensures resilience against commodity price volatility. Through a disciplined capital program that prioritizes high-return wells with low breakeven costs, we are more able to sustain production and liquidity. In higher-price markets, we balanced growth with improving the balance sheet; in today's lower-price landscape, we are prioritizing debt reduction. For the second half of 2025, we will seek to maximize cash flow, control costs, and further strengthen our financial position." Summary Results and Additional Key Items Adjusted Net Income, Adjusted EBITDA, and Adjusted Free Cash Flow are non-GAAP financial measures, which are described in more detail and reconciled to the most comparable GAAP measures, in the tables shown later in this release under "Non-GAAP Financial Information." In addition, see section titled "Condensed Operating Data" for additional details concerning costs and expenses discussed below. Select Expenses and Other Items (1) A summary listing of the Company's outstanding derivative positions at June 30, 2025 is included in the tables shown later in this release. For the remainder (July through December) of 2025, the Company has approximately 1.3 million barrels of oil (approximately 55% of oil sales guidance midpoint) hedged at an average downside protection price of $64.87 and approximately 1.5 billion cubic feet of natural gas (approximately 42% of natural gas sales guidance midpoint) hedged at an average downside protection price of $3.37. Balance Sheet and Liquidity Total liquidity (defined as cash and cash equivalents plus borrowing base availability under the Company's credit facility) at June 30, 2025 was approximately $137.0 million. On June 30, 2025, the Company had $448 million in borrowings outstanding on its credit facility that has a current borrowing base of $585 million. This reflects a reduction of $12 million from the balance of $460 million at March 31, 2025. The Company is targeting continued debt reduction, dependent on market conditions, the timing and level of capital spending, and other considerations. Drilling and Completion Activity In 2Q 2025, the Company drilled, completed, and placed on production two wells in the Central Basin Platform. This included one 1-mile horizontal well in Andrews County and one vertical well in Crane County, both with a working interest of 100%. The table below sets forth Ring's drilling and completion activities in the first and second quarter of 2025: Second Half 2025 and Q3 Sales Volumes, Capital Investment and Operating Expense Guidance The guidance in the table below represents the Company's current good faith estimate of the range of likely future results. Guidance could be affected by the factors discussed below in the "Safe Harbor Statement" section. (1) In addition to Company-directed drilling and completion activities, the capital spending outlook includes funds for targeted well recompletions, capital workovers, infrastructure upgrades, and well reactivations. Also included is anticipated spending for leasing acreage; and non-operated drilling, completion, capital workovers, and facility improvements. (2) Includes wells drilled, completed, and placed online. (3) Based on the $48 million midpoint of spending guidance in the second half of 2025, the Company continues to expect the following estimated allocation of capital, including: 61% for drilling, completion, and related infrastructure;33% for recompletions and capital workovers;4% for land, non-operated capital, and other; and2% for facility improvements (environmental and emission reducing upgrades). (4) Capital expenditures for the full year 2025 are now at a midpoint of $97 million (low of $87 million and high of $107 million). Conference Call Information Ring will hold a conference call on Thursday, August 7, 2025 at 11:00 a.m. ET (10 a.m. CT) to discuss its 2Q 2025 operational and financial results. An updated investor presentation will be posted to the Company's website prior to the conference call. To participate in the conference call, interested parties should dial 833-953-2433 at least five minutes before the call is to begin. Please reference the "Ring Energy 2Q 2025 Earnings Conference Call". International callers may participate by dialing 412-317-5762. The call will also be webcast and available on Ring's website at www.ringenergy.com under "Investors" on the "News & Events" page. An audio replay will also be available on the Company's website following the call. About Ring Energy, Inc. Ring Energy, Inc. is an oil and gas exploration, development, and production company with current operations focused on the development of its Permian Basin assets. For additional information, please visit www.ringenergy.com. Safe Harbor Statement This release contains 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 involve a wide variety of risks and uncertainties, and include, without limitation, statements with respect to the Company's strategy and prospects. The forward-looking statements include statements about the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of the Company, expected benefits to the Company and its stockholders from the Lime Rock Acquisition, and plans and objectives of management for future operations. Forward-looking statements also include assumptions and projections for third quarter and second half 2025 guidance for sales volumes, oil mix as a percentage of total sales, capital expenditures, operating expenses and the projected impacts thereon, and the number of wells expected to be drilled and completed. Forward-looking statements are based on current expectations and assumptions and analyses made by Ring and its management in light of their experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actual results and developments will conform to expectations is subject to a number of material risks and uncertainties, including but not limited to: declines in oil, natural gas liquids or natural gas prices; the level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities particularly in the winter; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base and interest rates under the Company's credit facility; Ring's ability to generate sufficient cash flows from operations to meet the internally funded portion of its capital expenditures budget; the impacts of hedging on results of operations; changes in U.S. energy, environmental, monetary, tax and trade policies, including with respect to tariffs or other trade barriers, and any resulting trade tensions; cost and availability of transportation and storage capacity as a result of oversupply, government regulation or other factors; and Ring's ability to replace oil and natural gas reserves. Such statements are subject to certain risks and uncertainties which are disclosed in the Company's reports filed with the Securities and Exchange Commission ("SEC"), including its Form 10-K for the fiscal year ended December 31, 2024, and its other SEC filings. Ring undertakes no obligation to revise or update publicly any forward-looking statements, except as required by law. Contact Information Al Petrie AdvisorsAl Petrie, Senior PartnerPhone: 281-975-2146 Email: apetrie@ringenergy.com (1) Boe is determined using the ratio of six Mcf of natural gas to one Bbl of oil (totals may not compute due to rounding.) The conversion ratio does not assume price equivalency and the price on an equivalent basis for oil, natural gas, and natural gas liquids may differ significantly. RING ENERGY, INC.Financial Commodity Derivative PositionsAs of June 30, 2025 The following tables reflect the details of current derivative contracts as of June 30, 2025 (quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts): (1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude. (2) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above. RING ENERGY, INC.Non-GAAP Financial Information Certain financial information included in this release are not measures of financial performance recognized by accounting principles generally accepted in the United States ("GAAP"). These non-GAAP financial measures are "Adjusted Net Income," "Adjusted EBITDA," "Adjusted Free Cash Flow" or "AFCF," "Adjusted Cash Flow from Operations" or "ACFFO," "G&A Excluding Share-Based Compensation," "G&A Excluding Share-Based Compensation and Transaction Costs," "Leverage Ratio," "All-In Cash Operating Costs," and "Cash Operating Margin." Management uses these non-GAAP financial measures in its analysis of performance. These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP performance measures which may be reported by other companies. Reconciliation of Net income to Adjusted Net Income "Adjusted Net Income" is calculated as net income minus the estimated after-tax impact of share-based compensation, ceiling test impairment, unrealized gains and losses on changes in the fair value of derivatives, and transaction costs for executed acquisitions and divestitures ("A&D"). Adjusted Net Income is presented because the timing and amount of these items cannot be reasonably estimated and affect the comparability of operating results from period to period, and current period to prior periods. The Company believes that the presentation of Adjusted Net Income provides useful information to investors as it is one of the metrics management uses to assess the Company's ongoing operating and financial performance, and also is a useful metric for investors to compare Ring's results with its peers. Reconciliation of Net income to Adjusted EBITDA The Company defines "Adjusted EBITDA" as net income plus net interest expense (including interest income and expense), unrealized loss (gain) on change in fair value of derivatives, ceiling test impairment, income tax (benefit) expense, depreciation, depletion and amortization, asset retirement obligation accretion, transaction costs for executed acquisitions and divestitures (A&D), share-based compensation, loss (gain) on disposal of assets, and backing out the effect of other income. Company management believes Adjusted EBITDA is relevant and useful because it helps investors understand Ring's operating performance and makes it easier to compare its results with those of other companies that have different financing, capital and tax structures. Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. Adjusted EBITDA, as Ring calculates it, may not be comparable to Adjusted EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use. Reconciliations of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow and Adjusted EBITDA to Adjusted Free Cash Flow The Company defines "Adjusted Free Cash Flow" or "AFCF" as Net Cash Provided by Operating Activities less changes in operating assets and liabilities (as reflected on Ring's Condensed Statements of Cash Flows), plus transaction costs for executed acquisitions and divestitures (A&D), current income tax expense (benefit), proceeds from divestitures of equipment for oil and natural gas properties, loss (gain) on disposal of assets, and less capital expenditures, credit loss expense, and other income. For this purpose, the Company's definition of capital expenditures includes costs incurred related to oil and natural gas properties (such as drilling and infrastructure costs and lease maintenance costs) but excludes acquisition costs of oil and gas properties from third parties that are not included in Ring's capital expenditures guidance provided to investors. Management believes that Adjusted Free Cash Flow is an important financial performance measure for use in evaluating the performance and efficiency of the Company's current operating activities after the impact of capital expenditures and net interest expense (including interest income and expense, excluding amortization of deferred financing costs) and without being impacted by items such as changes associated with working capital, which can vary substantially from one period to another. Other companies may use different definitions of Adjusted Free Cash Flow. Reconciliation of Net Cash Provided by Operating Activities to Adjusted Cash Flow from Operations The Company defines "Adjusted Cash Flow from Operations" or "ACFFO" as Net Cash Provided by Operating Activities, as reflected in Ring's Condensed Statements of Cash Flows, less the changes in operating assets and liabilities, which includes accounts receivable, inventory, prepaid expenses and other assets, accounts payable, and settlement of asset retirement obligations, which are subject to variation due to the nature of the Company's operations. Accordingly, the Company believes this non-GAAP measure is useful to investors because it is used often in its industry and allows investors to compare this metric to other companies in its peer group as well as the E&P sector. Reconciliation of General and Administrative Expense (G&A) to G&A Excluding Share-Based Compensation and Transaction Costs The following table presents a reconciliation of General and Administrative Expense ("G&A"), a GAAP measure, to G&A excluding share-based compensation, and G&A excluding share-based compensation and transaction costs for executed acquisitions and divestitures (A&D). Calculation of Leverage Ratio "Leverage" or the "Leverage Ratio" is calculated under the Company's existing senior revolving credit facility and means as of any date, the ratio of (i) Consolidated total debt as of such date to (ii) Consolidated EBITDAX for the four consecutive fiscal quarters ending on or immediately prior to such date for which financial statements are required to have been delivered under the Company's existing senior revolving credit facility. The Company defines "Consolidated EBITDAX" in accordance with its existing senior revolving credit facility that means for any period an amount equal to the sum of (i) consolidated net income (loss) for such period plus (ii) to the extent deducted in determining consolidated net income for such period, and without duplication, (A) consolidated interest expense, (B) income tax expense determined on a consolidated basis in accordance with GAAP, (C) depreciation, depletion and amortization determined on a consolidated basis in accordance with GAAP, (D) exploration expenses determined on a consolidated basis in accordance with GAAP, and (E) all other non-cash charges reasonably acceptable to Ring's senior revolving credit facility administrative agent determined on a consolidated basis in accordance with GAAP, in each case for such period minus (iii) all noncash income added to consolidated net income (loss) for such period; provided that, for purposes of calculating compliance with the financial covenants, to the extent that during such period the Company shall have consummated an acquisition permitted by the credit facility or any sale, transfer or other disposition of any property or assets permitted by the senior revolving credit facility, Consolidated EBITDAX will be calculated on a pro forma basis with respect to the property or assets so acquired or disposed of. Also set forth in Ring's existing senior revolving credit facility is the maximum permitted Leverage Ratio of 3.00. The following tables show the leverage ratio calculations for the quarters ended June 30, 2025 and June 30, 2024. All-In Cash Operating Costs The Company defines All-In Cash Operating Costs, a non-GAAP financial measure, as "all in cash" costs which includes lease operating expenses, G&A costs excluding share-based compensation, net interest expense (including interest income and expense, excluding amortization of deferred financing costs), workovers and other operating expenses, production taxes, ad valorem taxes, and gathering/transportation costs. Management believes that this metric provides useful additional information to investors to assess the Company's operating costs in comparison to its peers, which may vary from company to company. Cash Operating Margin The Company defines Cash Operating Margin, a non-GAAP financial measure, as realized revenues per Boe less all-in cash operating costs per Boe. Management believes that this metric provides useful additional information to investors to assess the Company's operating margins in comparison to its peers, which may vary from company to company. 1 A non-GAAP financial measure; see the "Non-GAAP Financial Information" section in this release for more information including reconciliations to the most comparable GAAP measures.
Quarterly Stockholder Update by Murphy Oil Corporation
Quarterly Stockholder Update by Murphy Oil Corporation HOUSTON, Aug. 06 /BusinessWire/ -- Murphy Oil Corporation (NYSE:MUR): Murphy Oil Corporation Stockholders, This year Murphy Oil Corporation celebrates its 75th anniversary of incorporation. Over the last 75 years, Murphy has built a legacy based on a pioneering spirit and thoughtful decision making. Murphy is different from other independent exploration and production companies of its size. We have both onshore and offshore production, operate in the United States and internationally, and have a proven track record of successfully conducting offshore frontier exploration. While our company's diversified business model is a key differentiator, it can be more complex to value compared to a pure-play US shale company. This letter aims to provide a deeper understanding of Murphy through additional context and leadership perspectives on key aspects of our business. This letter also serves as a supplement to our earnings release for the second quarter of 2025, and both documents are being furnished simultaneously to the Securities and Exchange Commission and our stockholders. Please see the information regarding forward-looking statements and non-GAAP financial information included at the end of this letter. Unless otherwise noted, the financial and operating highlights and metrics discussed in this letter exclude noncontrolling interest (NCI).1 SECOND QUARTER 2025 SUMMARY Murphy delivered solid operational and production performance in the second quarter while experiencing significantly lower commodities prices than we have seen in recent quarters. Second quarter oil, natural gas liquids, and natural gas production of 189.7 thousand barrels of oil equivalents per day (MBOEPD) exceeded the high end of our quarterly guidance range of 177.0 to 185.0 MBOEPD highlighted by oil production of 89.5 thousand barrels of oil per day (MBOPD) also exceeding guidance. Operating expenses in the second quarter were $11.80 per BOE, which is $1.94 per BOE lower than in the first quarter. Realized oil prices were $64.31 per barrel in the second quarter, which is $7.89 per barrel or 11 percent less than in the first quarter. In addition, realized natural gas prices were $1.88 per thousand cubic feet (MCF) in the second quarter, which is $0.79 per MCF or 29.5 percent lower than in the first quarter. This latter reduction is particularly significant as natural gas comprises 53 percent of our production mix. As a result, we recorded net income of $22.3 million, or $0.16 net income per diluted share, for the second quarter compared to $73.0 million, or $0.50 net income per diluted share in the first quarter, despite the large increase in production. Also in the second quarter, earnings before interest, taxes, depreciation and amortization (EBITDA) attributable to Murphy (non-GAAP) was $299.3 million, cash flow from operations was $358.1 million, and we generated free cash flow (non-GAAP) of $17.8 million. These financial results reflect the extraordinary impact of commodity prices on our business and reinforce the importance of concentrating on the parts of our business we can control: production rates and costs, a solid balance sheet and a first rate exploration program followed by best-in-class oil field development skills. OPERATIONAL UPDATE During the second quarter of 2025 we made significant progress in many important areas of our business: the onshore new well delivery program, Gulf of America workovers, Lac Da Vang (Golden Camel) field development, and preparations for exploration and appraisal wells which are planned for the second half of the year. At our Eagle Ford Shale (EFS) asset, we brought online 24 operated wells and 10 gross non-operated wells. All new EFS operated pads exceeded initial production expectations with our 16 new Karnes County wells delivering some of the highest initial production rates in Murphy EFS history (an average of 2,123 BOEPD per well). While the industry is experiencing declining EFS well performance, in contrast, we continue to enhance capital efficiency by modifying completion designs and operating practices to deliver improved well performance year over year. This also reflects the fact that we have a more deliberate EFS development schedule than most peers resulting in a more robust remaining tier-one well location inventory. At our Tupper Montney asset, we brought online five new wells, rounding out our 10-well program for the year. We tested a new completion design for those 10 wells, with approximately 50 percent higher proppant loading, and we have seen excellent early performance from the wells. All 10 new Tupper wells have 30-day initial production rates (an average of 19.2 million cubic feet per day) that are in the Murphy top 20 all-time Tupper high performer list. I must admit that I am very proud of our onshore team who continues to deliver impressive operational and technical improvements despite a new well program that has limited "shots on goal" compared to shale-only industry peers. Early in the second quarter in our offshore program, we completed the Samurai #3 workover and returned the well to production. Early in the third quarter, the Khaleesi #2 workover was completed, and the well was returned to production in July. Together these two workovers add 3.7 MBOEPD to our production totals in the third quarter. In addition, we are progressing the Marmalard #3 workover and expect to resume production from the well in August. These three wells, because of their high production rates, are important cash flow generators and high rate-of-return investments. They also highlight the importance of the Gulf of America to the company's production assets. In Vietnam, our Lac Da Vang (Golden Camel) field development execution continues to be impressive as construction of the LDV-A platform's jacket was completed in the third quarter and is being prepared for installation early in the fourth quarter. Furthermore, fabrication of the LDV-A platform's topsides, the Floating Storage and Offloading (FSO) vessel's hull and turret, pipelines, flexible risers, and subsea structures are all progressing on schedule for first oil in the fourth quarter of 2026. PRODUCTION As noted, second quarter production of 189.7 MBOEPD was 32.5 MBOEPD or 20.6 percent higher than first quarter production. This outperformance, as referenced above, was primarily driven by earlier online dates and higher than expected initial production rates from new onshore wells at Tupper Montney and Eagle Ford Shale. We now expect full year 2025 production to be closer to the midpoint of our guidance range of 174.5 to 182.5 MBOEPD. Second quarter production at Tupper Montney was particularly significant as it averaged 447 million cubic feet per day (MMCFD) or 74.7 MBOEPD. With our new wells online, we produced at Tupper West plant capacity throughout May and June. At EFS we achieved second quarter production of 39.5 MBOEPD, significantly higher than our quarterly guidance of 34.2 MBOEPD. During the quarter, EFS achieved a peak rate over 54 MBOEPD, the highest rate delivered since December 2019. Second quarter production from the Gulf of America averaged 65.7 MBOEPD, which was 1.1 MBOEPD higher than our quarterly guidance of 64.6 MBOEPD and nearly 4 MBOEPD higher than first quarter production. Our non-operated offshore Canada business delivered average production of 5.6 MBOEPD, which was lower than our quarterly guidance by 2.1 MBOEPD, due to higher than anticipated downtime. CAPITAL EXPENDITURES Capital expenditures (CAPEX) for the second quarter were $251 million and lower than our quarterly guidance of $300 million, primarily due to timing. In addition, second quarter CAPEX was $152 million lower than first quarter CAPEX primarily because of the unique $104 million Pioneer FPSO purchase in the first quarter. Murphy's onshore drilling and completions team continues to set new internal performance records. In the Catarina area of our Eagle Ford Shale asset, we increased the drilling Rate of Penetration (ROP) by 26 percent and reduced the spud-to-total depth timing by 20 percent compared to 2024. In the Tilden area, we improved capital efficiency by drilling two long lateral U-turn wells instead of four shorter lateral wells, which reduced capital expenditure by 33 percent with no reduction in oil recovery per lateral foot. In Canada, we drilled the longest horizontal wells in Murphy history in Kaybob Duvernay. Our completions team continues to refine completion designs by optimizing fluid and proppant intensities and leveraging automated physics-based models to enhance flowback strategies, which have led to improved initial well performance. In the third quarter, we expect CAPEX to be $260 million excluding acquisition costs. We continue to be comfortable with our full year 2025 CAPEX guidance of $1,135 to $1,285 million, which includes the Pioneer FPSO purchase but excludes a small Eagle Ford Shale acquisition discussed below. OPERATING COSTS As noted above, operating expenses in the second quarter averaged $11.80 per BOE, which is $1.94 per BOE, or 14.1 percent lower than in the first quarter, primarily due to higher production rates, lower Eagle Ford Shale operating costs, and lower offshore workover costs. In our offshore assets, most of the workover activity is behind us, so operating expenses in the second half of the year are expected to be more in line with historical trends. Accordingly, we anticipate operating expenses in the $10 to $12 per BOE range during the second half of 2025. In our Eagle Ford Shale asset, we have made great progress reducing operating costs which are down $12 million or 18 percent in the first half of 2025 compared to the first half of 2024. On a unit basis operating costs per BOE in the first half of 2025 were down 30 percent compared to the first half of 2024. The primary drivers of reduced operating costs are workforce optimization, lower repairs and maintenance expenses, lower rental equipment costs, and reduced water disposal costs. EXPLORATION AND APPRAISAL DRILLING Murphy's international frontier wildcat and Gulf of America nearfield exploration program remains a key differentiator from our peers. Our planned 2025 and 2026 exploration and appraisal activity will expose the company to transformational conventional volumes and will test for more than one billion BOEs in gross un-risked resource potential. We are on schedule to drill key exploration and appraisal wells in the second half of the year. In the Gulf of America, the Cello #1 and Banjo #1 exploration wells will be drilled in the third and fourth quarters. Both wells are located in Mississippi Canyon 385, near our operated Delta House floating production system and will flow back through this system if we are successful. In Vietnam, we will begin drilling a key appraisal well at our recent Hai Su Vang (Golden Sea Lion) oil discovery in the third quarter, with results expected in the fourth quarter. The discovery well was drilled near the crest of the structure, encountered 370 feet of net oil pay, and was flow tested at 10,000 BOPD. With our current understanding of the range of recoverable resources, we are confident that the discovery is significant and provides a highly profitable investment opportunity. However, since the discovery well did not encounter water, there is untested upside remaining. The appraisal well will be drilled off the crest of the structure to assess reservoir continuity and determine how much of the structure, below the current total depth, is filled with hydrocarbons. These findings will tighten the range of recoverable resources and potentially move the range higher. More than one appraisal well may be required to fully characterize the field. Our three-well Côte d'Ivoire exploration program remains on schedule to commence in the fourth quarter. This exploration program allows Murphy to evaluate three separate prospects representing various play types and large mean un-risked resources, with relatively low well costs and strong fiscal terms. COMMODITY PRICING In addition to the oil and natural gas price comments made above, I will point out a few other highlights. Our gassy onshore Canada business saw realized natural gas prices average $1.65 per MCF, which was $0.44 per MCF higher than the AECO benchmark due to our diversification and fixed forward selling strategies. In addition, and very importantly, Shell Canada Energy announced in late June that the first cargo of liquefied natural gas (LNG) had left the LNG Canada facility in Kitimat, British Columbia. Thus, after many decades of discussion, planning and finally construction, an LNG exporting facility is finally operating on the West Coast of Canada. This provides two billion cubic feet per day of additional demand for Canadian gas and is expected to result in higher AECO prices as LNG Canada production ramps up. FINANCIAL PERFORMANCE AND RETURN OF CAPITAL As previously communicated, our Capital Allocation Plan allocates a minimum of 50 percent of adjusted Free Cash Flow to share buybacks and potential dividend increases, with the remainder allocated to the balance sheet. In the first half of 2025 we distributed $93.4 million of dividends to shareholders. We also repurchased $100 million of stock or 3.6 million shares in the first quarter, reducing our shares outstanding to 142.7 million with $550 million remaining in our board authorized share repurchase program. BALANCE SHEET Total debt and net debt at the end of the second quarter were $1.476 billion and $1.096 billion, respectively. We had $200 million drawn on our unsecured revolving credit facility at the end of the quarter. We are favorably positioned with a strong balance sheet, and we remain committed to our $1.0 billion long-term debt target, which represents a 1.0x debt to EBITDA ratio at approximately $45 per barrel WTI. With that said, given current market conditions and our high potential exploration and appraisal program ahead of us, we currently expect to use available adjusted Free Cash Flow for share repurchases rather than bond repayments. OTHER BUSINESS In July 2025, we completed a small Eagle Ford Shale acquisition for a contract price of $23 million, subject to certain post-closing adjustments. The sale closed July 1, 2025, and has an effective date of June 15, 2025. For several years we have been telling investors that we screen many Eagle Ford Shale acquisition opportunities but typically do not find assets that are as good as or better than our existing business. With this highly accretive acquisition, we were able to increase our working interest in the Karnes County business that we already own and operate. CLOSING I am pleased with our solid operational results in the second quarter and our continued onshore well performance improvements. It's an exciting time at Murphy with our significant exploration and appraisal catalysts in the coming months. I'm confident that our talented and dedicated employees are capable of delivering shareholder value through our differentiated business model. Thank you for being a Murphy Oil Corporation Stockholder. Eric M. Hambly President and Chief Executive Officer CONFERENCE CALL AND WEBCAST SCHEDULED FOR AUGUST 7, 2025 Murphy will host a conference call to discuss second quarter 2025 financial and operating results on Thursday, August 7, 2025, at 9:00 a.m. ET. The call can be accessed either via the Internet through the events calendar on the Murphy Oil Corporation Investor Relations website at http://ir.murphyoilcorp.com or via telephone by dialing toll free 1-800-717-1738, reservation number 30769. For additional information, please refer to the Second Quarter 2025 Earnings Presentation available under the News and Events section of the Investor Relations website. FORWARD-LOOKING STATEMENTS This letter contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as "aim", "anticipate", "believe", "drive", "estimate", "expect", "expressed confidence", "forecast", "future", "goal", "guidance", "intend", "may", "objective", "outlook", "plan", "position", "potential", "project", "seek", "should", "strategy", "target", "will" or variations of such words and other similar expressions. These statements, which express management's current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance. In particular, statements, express or implied, concerning the company's future operating results or activities and returns or the company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and natural gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; geopolitical concerns; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the US or global capital markets, credit markets, banking system or economies in general, including inflation, trade policies, tariffs and other trade restrictions. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see "Risk Factors" in our most recent Annual Report on Form 10-K filed with the US Securities and Exchange Commission ("SEC") and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC's website and from Murphy Oil Corporation's website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the company; therefore, we encourage investors, the media, business partners and others interested in the company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this letter. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements. NON-GAAP FINANCIAL MEASURES This letter contains certain non-GAAP financial measures that management believes are useful tools for internal use and the investment community in evaluating Murphy Oil Corporation's overall financial performance. These non-GAAP financial measures are broadly used to value and compare companies in the crude oil and natural gas industry. Not all companies define these measures in the same way. In addition, these non-GAAP financial measures are not a substitute for financial measures prepared in accordance with US generally accepted accounting principles (GAAP) and should therefore be considered only as supplemental to such GAAP financial measures. Please see Exhibit 99.1 on Form 8-K filed on August 6, 2025, for reconciliations of the differences between the non-GAAP financial measures used in this letter and the most directly comparable GAAP financial measures. 1In accordance with GAAP, Murphy reports the 100 percent interest, including a 20 percent noncontrolling interest (NCI), in its subsidiary, MP Gulf of Mexico, LLC (MP GOM). The GAAP financials include the NCI portion of revenue, costs, assets and liabilities and cash flows. Unless otherwise noted, the financial and operating highlights and metrics discussed in this letter exclude the NCI, thereby representing only the amounts attributable to Murphy. View source version on businesswire.com: https://www.businesswire.com/news/home/20250805952115/en/ back
Vital Energy Reports Second-Quarter 2025 Financial and Operating Results
Vital Energy Reports Second-Quarter 2025 Financial and Operating Results TULSA, OK, Aug. 06, 2025 (GLOBE NEWSWIRE) -- Vital Energy, Inc. (NYSE: VTLE) ("Vital Energy" or the "Company") today reported second-quarter 2025 financial and operating results. Supplemental slides have been posted to the Company's website and can be found at www.vitalenergy.com. A conference call is planned for 7:30 a.m. CT, Thursday, August 7, 2025. A webcast will be available through the Company's website. Second-Quarter 2025 Highlights Reported a net loss of $582.6 million, Adjusted Net Income1 of $76.1 million and cash flow from operating activities of $252.3 millionGenerated Consolidated EBITDAX1 of $338.1 million and Adjusted Free Cash Flow1 of $36.1 millionReported capital investments of $257.0 million, excluding non-budgeted acquisitions and leasehold expenditures, above guidance of $215-$245 millionReported lease operating expense ("LOE") of $107.8 million, below guidance of $112-$118 millionReported total general and administrative expenses ("G&A") of $23.8 million, below guidance of $24.6-$26.7 millionProduced 137.9 thousand barrels of oil equivalent per day ("MBOE/d") and oil of 62.1 thousand barrels of oil per day ("MBO/d"), within guidance of 133.0-139.0 MBOE/d and 61.0-65.0 MBO/d, respectivelyCommenced production from the Company's first two J-Hook wellsOn schedule to TIL all 38 second-half 2025 wells by early OctoberDivested 3,800 net non-core acres in Crane and Upton counties, Texas, for $6.5 million in July 2025, with proceeds allocated to debt reduction 1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release. "Our second quarter results demonstrate our ongoing efforts to lower costs and optimize our assets, with the ultimate goal of enhancing returns," stated Jason Pigott, President and CEO. "We have made substantial progress to sustainably reduce operating, personnel and corporate costs as we streamline our business and strengthen our balance sheet. Additionally, we continue to lead the industry in the application of optimized well designs, completing our first J-Hook wells and commencing drilling on a section to be fully developed with 12 horseshoe wells. We remain committed to the capital and cost discipline that will allow us to generate sustainable Adjusted Free Cash Flow from our high-quality asset base." Second-Quarter 2025 Financial and Operations SummaryFinancial Results. The Company had a net loss of $582.6 million, or $(15.43) per diluted share. Results were impacted by a non-cash pre-tax impairment loss on oil and gas properties of $427.0 million and a valuation allowance against the Company's federal net deferred tax asset of $237.9 million. Adjusted Net Income was $76.1 million, or $2.02 per adjusted diluted share. Cash flows from operating activities were $252.3 million and Consolidated EBITDAX was $338.1 million. The impairment was related to the full cost ceiling limitation, driven primarily by the decline in the trailing 12-month SEC mandated oil price calculation, and excludes the value of the Company's commodity derivative positions and only includes the 171 proved undeveloped locations in the Company's current proved reserves out of approximately 920 inventory locations at the beginning of the year, net of divestitures. Additionally, as a result of the full cost ceiling impairment and the expectation of future impairments, a valuation allowance against the Company's net deferred tax asset was recorded. Production. Vital Energy's total and oil production averaged 137,864 BOE/d and 62,140 BO/d, respectively. Weather and temporary curtailments related to the installation of additional production equipment negatively impacted average daily production by 780 BOE/d, 500 BO/d of which was oil. Capital Investments. Total capital investments, excluding non-budgeted acquisitions and leasehold expenditures, were $257 million, including approximately $13 million related to drilling cost overruns and $11 million to accelerate development activity into the second quarter. Second quarter investments included $216 million in drilling and completions, $27 million in infrastructure investments, $8 million in other capitalized costs and $6 million in land, exploration and data-related costs. Operating Expenses. LOE was 6% lower than the midpoint of guidance at $107.8 million, driven by lower than expected costs on the recently acquired Point Energy assets and ongoing cost optimization across the Midland and Delaware basins that reduced field power generation and chemicals costs. G&A Expenses. Total G&A expenses were 7% below the midpoint of guidance at $23.8 million as the Company continued to reduce employee and professional costs. Adjusted Free Cash Flow and Net Debt. Adjusted Free Cash Flow was $36 million, with sustainable expense reductions largely offsetting drilling outspend. Net Debt1 increased by $8 million during the quarter as the Company's net changes in operating assets and liabilities decreased by $41 million. Liquidity. At June 30, 2025, the Company had $745 million outstanding on its $1.4 billion senior secured credit facility and cash and cash equivalents of $30 million. 1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release. 2025 OutlookProduction. Planned completion of 38 wells in late third quarter/early fourth quarter is expected to meaningfully increase production volumes. Total and oil production ranges for full-year 2025 were narrowed to account for actual second-quarter 2025 volumes and are expected to be 136.5-139.5 MBOE/d and 63.3-65.3 MBO/d, respectively. Capital Investments. Vital Energy reduced expectations for third quarter investments by $25 million to $235-$265 million, in part reflecting the acceleration of capital into the second quarter. Guidance for the fourth quarter is unchanged. Full-year 2025 capital expectations were narrowed to $850-$900 million. Operating Expenses. The Company expects recent improvements in operating expenses to be sustainable. Third quarter LOE is expected to be $109-$115 million and decline to $107-$113 million in the fourth quarter of 2025. G&A Expenses. In June, Vital Energy reduced its combined employee and contractor headcount by approximately 10%, resulting in sustainably lower G&A expense. Total G&A for both the third and fourth quarters of 2025 is expected to decline approximately 12% from second-quarter 2025 to a range of $20.0-$22.0 million. Non-core Divestitures. In July 2025, Vital Energy closed on the sale of approximately 3,800 net acres in Crane and Upton counties for $6.5 million. The sale included five of the Company's inventory locations in the Barnett formation with no impact to production. Year-to-date, Vital Energy has closed on non-core asset sales totaling $27 million. Adjusted Free Cash Flow and Net Debt. For full-year 2025, the Company expects to generate approximately $305 million of Adjusted Free Cash Flow at current oil prices of ~$67 per barrel WTI, inclusive of hedging proceeds, and reduce Net Debt by approximately $310 million. The estimated Net Debt reduction includes proceeds from non-core asset sales and increases in debt from working capital changes and organizational restructuring expenses. Through the first half of 2025, Vital Energy reduced Net Debt by $125 million. The Company expects to reduce Net Debt by approximately $25 million in the third quarter of 2025 and approximately $160 million in the fourth quarter. Third-Quarter 2025 GuidanceThe table below reflects the Company's guidance for production and capital investments. The table below reflects the Company's guidance for select revenue and expense items. Conference Call DetailsVital Energy plans to host a conference call at 7:30 a.m. CT on Thursday, August 7, 2025, to discuss its second-quarter 2025 financial and operating results. Supplemental slides will be posted to the Company's website. Interested parties are invited to listen to the call via the Company's website at www.vitalenergy.com, under the tab for "Investor Relations | News & Presentations | Upcoming Events." About Vital EnergyVital Energy, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Vital Energy's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin of West Texas. Additional information about Vital Energy may be found on its website at www.vitalenergy.com. Forward-Looking StatementsThis press release and any oral statements made regarding the contents of this release, including in the conference call referenced herein, contain forward-looking statements as defined under 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, that address activities that Vital Energy assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties. General risks relating to Vital Energy include, but are not limited to: the volatility of oil, NGL and natural gas prices, including the Company's area of operation in the Permian Basin; changes, uncertainty and instability in domestic and global production, supply and demand for oil, NGL and natural gas, and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+"); changes in general economic, business or industry conditions and market volatility, including as a result of slowing growth, inflationary pressures, monetary policy, tariffs, trade barriers, price and exchange controls and other regulatory requirements, including such changes that may be implemented by the United States ("U.S.") and foreign governments; the Company's ability to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties; the Company's ability to optimize spacing, drilling and completions techniques in order to maximize its rate of return, cash flows from operations and stockholder value; the ongoing instability and uncertainty in the U.S. and international energy, financial and consumer markets that could adversely affect the liquidity available to the Company and its customers and the demand for commodities, including oil, NGL and natural gas; competition in the oil and gas industry; the Company's ability to discover, estimate, develop and replace oil, NGL and natural gas reserves and inventory; insufficient transportation capacity in the Permian Basin and challenges associated with such constraint, and the availability and costs of sufficient gathering, processing, storage and export capacity; a decrease in production levels which may impair the Company's ability to meet its contractual obligations and ability to retain its leases; risks associated with the uncertainty of potential drilling locations and plans to drill in the future; the inability of significant customers to meet their obligations; revisions to the Company's reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties; the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services; ongoing war and political instability in Ukraine, Israel and the Middle East and the effects of such conflicts on the global hydrocarbon market and supply chains; risks related to the geographic concentration of the Company's assets; the Company's ability to hedge commercial risk, including commodity price volatility, and regulations that affect the Company's ability to hedge such risks; the Company's ability to continue to maintain the borrowing capacity under its Senior Secured Credit Facility or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices; the Company's ability to comply with restrictions contained in its debt agreements, including its Senior Secured Credit Facility and the indentures governing its senior unsecured notes, as well as debt that could be incurred in the future; the Company's ability to generate sufficient cash to service its indebtedness, fund its capital requirements and generate future profits; drilling and operating risks, including but not limited to, risks related to hydraulic fracturing, securing sufficient electricity to produce its wells without limitation, natural disasters and other matters beyond the Company's control; U.S. and international economic conditions and legal, tax, political and administrative developments, including the effects of energy, trade and environmental policies and existing and future laws and government regulations; the Company's ability to comply with federal, state and local regulatory requirements, including the One Big Beautiful Bill Act (the "OBBB Act") and any impact thereon by the OBBB Act taxes, tariffs and international trade; the impact of repurchases, if any, of securities from time to time; the Company's ability to maintain the health and safety of, as well as recruit and retain, qualified personnel, including senior management or other key personnel, necessary to operate its business; evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, third-party service provider failures, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing attacks, ransomware, social engineering, physical breaches or other actions; and the Company's belief that the outcome of any current legal proceedings will not materially affect its financial results and operations, and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2024 (the "2024 Annual Report"), subsequent Quarterly Reports on Form 10-Q and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). These documents are available through Vital Energy's website at www.vitalenergy.com under the tab "Investor Relations" or through the SEC's Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Vital Energy's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Vital Energy can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Vital Energy does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted Free Cash Flow, Adjusted Net Income, Net Debt and Consolidated EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, please see the supplemental financial information at the end of this press release.Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions. All amounts, dollars and percentages presented in this press release are rounded and therefore approximate. _______________________________________________________________________________(1) The numbers presented are calculated based on actual amounts and may not recalculate using the rounded numbers presented in the table above.(2) Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.(3) Price reflects the after-effects of the Company's commodity derivative transactions on its average sales prices. The Company's calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods. Vital Energy, Inc.Supplemental reconciliations of GAAP to non-GAAP financial measures Non-GAAP financial measuresThe non-GAAP financial measures of Adjusted Free Cash Flow, Adjusted Net Income, Consolidated EBITDAX, Net Debt and Net Debt to Consolidated EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Furthermore, these non-GAAP financial measures should not be considered in isolation or as a substitute for GAAP measures of liquidity or financial performance, but rather should be considered in conjunction with GAAP measures, such as net income or loss, operating income or loss or cash flows from operating activities. Adjusted Free Cash FlowAdjusted Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by (used in) operating activities (GAAP) before net changes in operating assets and liabilities and transaction expenses related to non-budgeted acquisitions, less capital investments, excluding non-budgeted acquisition costs. Management believes Adjusted Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Adjusted Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Adjusted Free Cash Flow reported by different companies. This release also includes certain forward-looking non-GAAP measures. Due to the forward-looking nature of such measures, no reconciliations of these non-GAAP measures to their respective most directly comparable GAAP measure are available without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various reconciling items that would impact the most directly comparable forward-looking GAAP financial measure, that have not yet occurred, are out of the Company's control and/or cannot be reasonably predicted. Accordingly, such reconciliations are excluded from this release. Forward-looking non-GAAP financial measures provided without the most directly comparable GAAP financial measures may vary materially from the corresponding GAAP financial measures. The following table presents a reconciliation of net cash provided by (used in) operating activities (GAAP) to Adjusted Free Cash Flow (non-GAAP) for the periods presented: Adjusted Net IncomeAdjusted Net Income is a non-GAAP financial measure that the Company defines as net income or loss (GAAP) plus adjustments for mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, organizational restructuring expenses, impairment expense, gains or losses on disposal of assets, income taxes, other non-recurring income and expenses and adjusted income tax expense. Management believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company's performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors. The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented: Consolidated EBITDAXConsolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, organizational restructuring expenses, gains or losses on disposal of assets, mark-to-market on derivatives, accretion expense, interest expense, income taxes and other non-recurring income and expenses. Consolidated EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Consolidated EBITDAX does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Consolidated EBITDAX is useful to an investor because this measure: is used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;helps investors to more meaningfully evaluate and compare the results of the Company's operations from period to period by removing the effect of the Company's capital structure from the Company's operating structure; andis used by management for various purposes, including (i) as a measure of operating performance, (ii) as a measure of compliance under the Senior Secured Credit Facility, (iii) in presentations to the board of directors and (iv) as a basis for strategic planning and forecasting. There are significant limitations to the use of Consolidated EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Consolidated EBITDAX, or similarly titled measures, reported by different companies. The Company is subject to financial covenants under the Senior Secured Credit Facility, one of which establishes a maximum permitted ratio of Net Debt, as defined in the Senior Secured Credit Facility, to Consolidated EBITDAX. See Note 7 in the 2024 Annual Report for additional discussion of the financial covenants under the Senior Secured Credit Facility. Additional information on Consolidated EBITDAX can be found in the Company's Eleventh Amendment to the Senior Secured Credit Facility, as filed with the SEC on September 13, 2023. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: The following table presents a reconciliation of net cash provided by (used in) operating activities (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: Net DebtNet Debt is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents, where cash and cash equivalents are capped at $100 million when there are borrowings on the Senior Secured Credit Facility. Management believes Net Debt is useful to management and investors in determining the Company's leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt to Consolidated EBITDAXNet Debt to Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as Net Debt divided by Consolidated EBITDAX for the previous four quarters, which requires various treatment of asset transaction impacts. Net Debt to Consolidated EBITDAX is used by the Company's management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting. Investor Contact:Ron Hagood918.858.5504ir@vitalenergy.com
Final Investment Decision for 20-year charter of MK II FLNG to Southern Energy in Argentina
Final Investment Decision for 20-year charter of MK II FLNG to Southern Energy in Argentina Golar LNG Limited ("Golar") is pleased to announce today that Southern Energy S.A. ("SESA") has reached Final Investment Decision for the charter of Golar's 3.5MTPA MK II FLNG, as contemplated under the terms of the definitive agreements executed by SESA and Golar in May 2025. The key commercial terms for the 20-year charter agreement include net charter hire to Golar of US$ 400 million per year, plus a commodity linked tariff component of 25% of FOB prices in excess of US$ 8/mmbtu. The FLNG, currently under conversion in China, will sail to Argentina following her redelivery, with contract start-up expected during 2028. The MKII FLNG will be moored in the San MatÃas Gulf near the FLNG Hilli, which is expected to start its 20-year charter with SESA during 2027. Combined, the two units have a nameplate capacity of 5.95MTPA, and the project expects to benefit from significant operational efficiencies and synergies from two FLNGs in the same area. SESA is a company formed to enable LNG exports from Argentina. SESA is owned by a consortium of leading Argentinian gas producers including Pan American Energy (30%), YPF (25%), Pampa Energia (20%) and Harbour Energy (15%), as well as Golar (10%). The MKII FLNG project remains subject to regulatory conditions precedent and satisfaction of other customary closing conditions which are progressing according to schedule and expected within 2025. Golar's Chief Executive Officer, Karl Fredrik Staubo, commented: "Today's FID marks another milestone for SESA in establishing Argentina as an attractive LNG exporter and building on Golar's position as the market leading FLNG service provider. FID solidifies $8 billion of net earnings visibility over 20 years to Golar, with attractive upside potential in the FLNG commodity tariff component and through our shareholding in SESA. We look forward to continuing to develop the SESA partnership into a leading LNG exporter in South America." 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. Hamilton, Bermuda August 6, 2025 Investor Questions: +44 207 063 7900Karl Fredrik Staubo - CEOEduardo Maranhão - CFOStuart Buchanan - Head of Investor Relations This information is subject to the disclosure requirements pursuant to Section 5-12 the Norwegian Securities Trading Act
Occidental Announces Second Quarter 2025 Results
Occidental Announces Second Quarter 2025 Results HOUSTON, Aug. 06, 2025 (GLOBE NEWSWIRE) -- Occidental (NYSE: OXY) today announced its second quarter 2025 financial results. The earnings release and accompanying financial schedules can be accessed via the Investor Relations section of the company's website, oxy.com. The earnings release is also available on the U.S. Securities and Exchange Commission's website at sec.gov. The company will hold a conference call to discuss the results on Thursday, August 7, 2025, at 1 p.m. Eastern/12 p.m. Central. The conference call may be accessed by calling 1-866-871-6512 (international callers dial 1-412-317-5417) or via webcast at oxy.com/investors. Participants may pre-register for the conference call at https://dpregister.com/sreg/10200631/ff63fe0694. A recording of the webcast will be posted on the Investor Relations section of the company's website within several hours after the call is completed. About Occidental Occidental is an international energy company with assets primarily in the United States, the Middle East and North Africa. We are one of the largest oil and gas producers in the U.S., including a leading producer in the Permian and DJ basins, and offshore Gulf of America. Our midstream and marketing segment provides flow assurance and maximizes the value of our oil and gas, and includes our Oxy Low Carbon Ventures subsidiary, which is advancing leading-edge technologies and business solutions that economically grow our business while reducing emissions. Our chemical subsidiary OxyChem manufactures the building blocks for life-enhancing products. We are dedicated to using our global leadership in carbon management to advance a lower-carbon world. Visit Oxy.com for more information. Contacts
DHT Holdings, Inc. Second Quarter 2025 Results
DHT Holdings, Inc. Second Quarter 2025 Results HAMILTON, BERMUDA, August 6, 2025 DHT Holdings, Inc. (NYSE:DHT) ("DHT" or the "Company") today announced its results for the quarter ended June 30, 2025. The full report is available here and in the below attachment. About DHT Holdings, Inc.DHT is an independent crude oil tanker company. Our fleet trades internationally and consists of crude oil tankers in the VLCC segment. We operate through our wholly owned management companies in Monaco, Norway, Singapore, and India. You may recognize us by our renowned business approach as an experienced organization with focus on first rate operations and customer service; our quality ships; our prudent capital structure that promotes staying power through the business cycles; our fleet employment with a combination of market exposure and fixed income contracts; our disciplined capital allocation strategy through cash dividends, investments in vessels, debt prepayments and share buybacks; and our transparent corporate structure maintaining a high level of integrity and corporate governance. For further information please visit www.dhtankers.com. Forward Looking StatementsThis press release contains certain forward-looking statements and information relating to the Company that are based on beliefs of the Company's management as well as assumptions, expectations, projections, intentions and beliefs about future events. When used in this document, words such as "believe," "intend," "anticipate," "estimate," "project," "forecast," "plan," "potential," "will," "may," "should" and "expect" and similar expressions are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. These statements reflect the Company's current views with respect to future events and are based on assumptions and subject to risks and uncertainties. Given these uncertainties, you should not place undue reliance on these forward-looking statements. These forward-looking statements represent the Company's estimates and assumptions only as of the date of this press release and are not intended to give any assurance as to future results. For a detailed discussion of the risk factors that might cause future results to differ, please refer to the Company's Annual Report on Form 20-F, filed with the SEC on March 20, 2025. The Company undertakes no obligation to publicly update or revise any forward-looking statements contained in this press release, whether as a result of new information, future events or otherwise, except as required by law. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this press release might not occur, and the Company's actual results could differ materially from those anticipated in these forward-looking statements. Contact:Laila C. Halvorsen, CFOPhone: +1 441 295 1422 and +47 984 39 935 E-mail: lch@dhtankers.com Attachment DHT Q2 2025 financial report
APA Corporation Announces Second-Quarter 2025 Financial and Operational Results
APA Corporation Announces Second-Quarter 2025 Financial and Operational Results HOUSTON, Aug. 06, 2025 (GLOBE NEWSWIRE) -- APA Corporation (Nasdaq: APA) today announced second-quarter 2025 results. Results can be found on the company's website by visiting www.apacorp.com or investor.apacorp.com. APA will host a conference call on Aug. 7 at 10 a.m. Central time via the webcast link available on the company website to discuss the results. Following the conference call, a replay will be available for one year on the "Investors" page of the company's website. About APA APA Corporation owns consolidated subsidiaries that explore for and produce oil and natural gas in the United States, Egypt and the United Kingdom and that explore for oil and natural gas offshore Suriname and elsewhere. APA posts announcements, operational updates, investor information and press releases on its website, www.apacorp.com. APA-F
Talos Energy Announces Second Quarter 2025 Operational and Financial Results
Talos Energy Announces Second Quarter 2025 Operational and Financial Results HOUSTON, Aug. 6, 2025 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for the three months ended June 30, 2025. Talos also provided third quarter 2025 guidance for production and updated its operational and financial guidance for the full year 2025. Second Quarter and Recent Key Highlights Announced enhanced corporate strategy designed to position Talos as a leading pure-play offshore E&P company.Improved full-year 2025 guidance reflects higher production, lower operating expenses and lower capital expenditures.Produced 93.3 thousand barrels of oil equivalent per day ("MBoe/d") (69% oil, 77% liquids).Initiated first production from Katmai West #2 and Sunspear wells(1).Resumed drilling operations at the Daenerys prospect, with results anticipated by the end of the third quarter of 2025.Recorded Net Loss of $185.9 million which includes $223.9 million of non-cash ceiling test impairment charges, or $1.05 Net Loss per diluted share, and Adjusted Net Loss(2) of $48.3 million, or $0.27 Adjusted Net Loss per diluted share(2).Generated Adjusted EBITDA(2) of $294.2 million.Allocated $126.1 million to capital expenditures, excluding plugging and abandonment and settled decommissioning obligations.Recorded net cash provided by operating activities of $351.6 million.Generated Adjusted Free Cash Flow(2) of $98.5 million.Repurchased approximately 3.8 million shares for $32.6 million.Improved balance sheet with $357.3 million of cash, an undrawn credit facility, a Net Debt to Last Twelve Months ("LTM") Adjusted EBITDA(2) of 0.7x, as of June 30, 2025.Increased hedge positions that cover over 38% of the second half of 2025 expected oil production at the midpoint of guidance, with a weighted average floor price approximately $71.50 per barrel, and mark-to-market hedge book value of $56 million, as of June 30, 2025."We continued to deliver on our commitments this quarter, with Adjusted EBITDA and Adjusted Free Cash Flow exceeding consensus estimates," said Paul Goodfellow, President and Chief Executive Officer of Talos. "This strong performance enabled us to repurchase 3.8 million shares for approximately $33 million, reflecting our continued commitment to returning capital to shareholders while also increasing our cash position to $357 million. Operationally, we reached several key milestones this quarter, including first production from our Katmai West #2 and Sunspear wells, the resumption of drilling at the high-impact Daenerys prospect, and continued advancement of our Monument development. We exited the second quarter with a solid financial foundation, including a leverage ratio of approximately 0.7x and total liquidity of approximately $1.0 billion." "With our enhanced corporate strategy in motion, we are strategically positioning Talos in the long-term to further lead in the offshore E&P sector, which we expect will play an increasing larger role in supplying global energy demand. We will continue to capitalize on this trend by leveraging our unique capabilities, low-cost operating structure, and solid balance sheet to ensure flexibility to manage through cycles while remaining committed to returning capital to shareholders." Footnotes: (1) In July, production from Sunspear was temporarily shut in due to an early failure of the surface-controlled subsurface safety valve ("SCSSV"). Talos expects Sunspear to return to production in late October 2025. (2) Please see "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. RECENT DEVELOPMENTS AND OPERATIONS UPDATE Corporate Strategy: In June 2025, Talos announced its enhanced corporate strategy designed to position the Company as a leading pure-play offshore exploration and production company. The three pillars of Talos's new strategy are: Improve our business every day. Talos is targeting approximately $100 million in increased annualized cash flow in 2026 through capital efficiency, margin enhancement, commercial opportunities, and general organizational improvements.Grow production and profitability. Talos plans to invest in high-margin organic projects, complemented by disciplined, accretive bolt-on acquisitions in deepwater basins, which will enhance production and profitability.Build a long-lived, scaled portfolio. Talos will take a strategic and measured approach in assessing opportunities within the Gulf of America and other conventional offshore basins. A scaled portfolio will provide Talos with significant production growth potential, and ultimately the ability to generate long-term consistent free cash flow.Share Repurchase Program: In the second quarter of 2025, Talos opportunistically repurchased approximately 3.8 million shares for $32.6 million, representing an average price of $8.48 per share. Year-to-date, the Company has repurchased 6.1 million shares for $54.6 million. Under Talos's share repurchase program, management expects to allocate up to 50% of its annual free cash flow to share repurchases. Purchases under the share repurchase program may be made from time to time in privately negotiated transactions or open market transactions under Rule 10b-18 of the Securities Exchange Act of 1934, as amended. These purchases will depend on market conditions, legal requirements, and other relevant factors. Production Updates: Sunspear: Late in the second quarter of 2025, Talos successfully initiated first production from the Sunspear well, which is tied back to the Talos-operated Prince platform. In July, production was temporarily shut in due to an early failure of the surface-controlled subsurface safety valve (SCSSV). The West Vela rig is scheduled to return to the well following the drilling of the Daenerys exploration prospect and Talos expects Sunspear to return to production in late October 2025. Estimates of Sunspear's initial productive capacity is expected to be at the high end of the range. Talos holds a 48.0% working interest ("W.I.") in the well, an entity managed by Ridgewood Energy Corporation holds a 47.5% W.I., and H.E. holds a 4.5% W.I. Katmai West: Also, late in the second quarter of 2025, Talos successfully initiated first production from the Katmai West #2 well. Total gross production from the Katmai East and West fields is approximately 35 Mboe/d (71% oil), which flows to the Talos-operated Tarantula platform. Given that the facility at Tarantula is at maximum capacity the current production rate is estimated to remain at that level for several years. The greater Katmai area is estimated to contain a total resource potential of up to 200 million barrels of oil equivalent ("MMBoe"). Talos, as operator, holds a 50% W.I., with entities managed by Ridgewood Energy Corporation holding 50% W.I. Project Updates: Daenerys: Talos is currently drilling the Daenerys exploratory well, utilizing the West Vela deepwater drillship. Daenerys is a high-impact subsalt prospect that will evaluate the regionally prolific Middle and Lower Miocene section and carries an estimated pre-drill gross resource potential between 100-300 MMBoe. Results are anticipated by the end of the third quarter of 2025. Talos, as operator, holds a 30% W.I., Shell Offshore Inc. holds a 25% W.I., Red Willow holds a 25% W.I., Cathexis holds a 10% W.I., and HEQ Deepwater holds a 10% W.I. Monument Discovery Farm-in: In March 2025, Talos increased its interest in the Monument discovery to a 29.76% W.I., up from 21.4% W.I. Monument is a large Wilcox oil discovery in Walker Ridge blocks 271, 272, 315, and 316. Talos expects to develop it as a subsea tie-back to the Shenandoah production facility in Walker Ridge. First production is expected between 20-30 MBoe/d gross by late 2026. There is an additional drilling location adjacent to the discovery with an estimated 25-35 MMBoe that could extend the resource. Beacon Offshore Energy LLC as operator, holds a 41.67% W.I., and Navitas Petroleum LP holds a 28.57% W.I. Impairment In the second quarter of 2025, the Company recorded a $223.9 million non-cash ceiling test impairment charge. Capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. The Company performs this ceiling test calculation each quarter utilizing pricing as defined by the U.S. Securities and Exchange Commission ("SEC"). SECOND QUARTER 2025 RESULTS Key Financial Highlights: ($ thousands, except per share and per Boe amounts) Three Months EndedJune 30, 2025 Total revenues $ 424,721 Net Income (Loss) $ (185,937) Net Income (Loss) per diluted share $ (1.05) Adjusted Net Income (Loss)(1) $ (48,316) Adjusted Net Income (Loss) per diluted share(1) $ (0.27) Adjusted EBITDA(1) $ 294,247 Adjusted EBITDA excluding hedges(1) $ 260,932 Capital Expenditures $ 126,057 (1) Please see "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. Production Production for the second quarter 2025 was 93.3 MBoe/d (69% oil, 77% liquids). Three Months Ended June 30, 2025 Oil (MBbl/d) 64.0 Natural Gas (MMcf/d) 129.7 NGL (MBbl/d) 7.7 Total average net daily (MBoe/d) 93.3 Three Months Ended June 30, 2025 Production % Oil % Liquids % Operated Deepwater 83.4 71 % 79 % 81 % Shelf and Gulf Coast 9.9 49 % 58 % 73 % Total average net daily (MBoe/d) 93.3 69 % 77 % 80 % Three Months Ended June 30, 2025 Average realized prices (excluding hedges): Oil ($/Bbl) $ 64.08 Natural Gas ($/Mcf) $ 3.34 NGL ($/Bbl) $ 17.23 Average realized price ($/Boe) $ 50.00 Average NYMEX prices: WTI ($/Bbl) $ 63.74 Henry Hub ($/MMBtu) $ 3.44 Lease Operating & General and Administrative Expenses Total lease operating expenses for the second quarter 2025, including workover, maintenance and insurance costs, were $137.0 million, or $16.12 per Boe. Adjusted General and Administrative expenses for the second quarter 2025, adjusted to exclude one-time transaction-related costs, and non-cash equity-based compensation, were $34.4 million, or $4.05 per Boe. ($ thousands, except per Boe amounts) Three Months Ended June 30, 2025 Lease Operating Expenses $ 136,971 Lease Operating Expenses per Boe $ 16.12 Adjusted General & Administrative Expenses(1) $ 34,364 Adjusted General & Administrative Expenses per Boe(1) $ 4.05 (1) Please see "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. Capital Expenditures Capital expenditures for the second quarter 2025, excluding plugging and abandonment and settled decommissioning obligations, totaled $126.1 million. ($ thousands) Three Months EndedJune 30, 2025 U.S. drilling & completions $ 102,961 Asset management(1) 7,042 Seismic and G&G, land, capitalized G&A and other 14,058 Total Capital Expenditures 124,061 Investment in Mexico 1,996 Total $ 126,057 (1) Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure. Plugging & Abandonment Expenditures Capital expenditures for plugging and abandonment and settled decommissioning obligations for the second quarter 2025 totaled $28.8 million. Three Months EndedJune 30, 2025 Plugging & Abandonment and Decommissioning Obligations Settled(1) $ 28,847 (1) Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. Liquidity and Leverage At June 30, 2025, Talos had a borrowing base of $925.0 million under its Bank Credit Facility, subject to a total availability cap of $800.0 million with approximately $42.8 million in outstanding letters of credit. Letters of credit that are outstanding reduce the available revolving credit commitments. Cash was $357.3 million, providing Talos approximately $1,114.5 million of liquidity at quarter end. On June 30, 2025, Talos had $1,250.0 million in total debt. Net Debt(1) was $892.7 million, Net Debt to Last Twelve Months ("LTM") Adjusted EBITDA(1) was 0.7x. Talos recently completed its regularly scheduled borrowing base redetermination, resulting in a borrowing base reduction from $925.0 million which was subject to a total availability cap of $800.0 million to $700.0 million under the Company's Bank Credit Facility. Footnotes: (1) Please see "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures. OPERATIONAL & FINANCIAL GUIDANCE UPDATES For the third quarter 2025, Talos expects average daily production to be in the range of 86.0 to 90.0 MBoe/d, with 69% oil volumes. Talos has revised its full year 2025 operational and financial guidance and expects average daily production to range from 91.0 to 95.0 MBoe/d, consisting of 69% oil and 78% liquids. Full year guidance reflects lower cash operating expenses and workover and lower capital expenditures. The following summarizes Talos's full-year 2025 operational and production guidance. Original Revised FY 2025 FY 2025 ($ Millions, unless highlighted): Low High Low High Production Oil (MMBbl) 22.7 24.0 23.0 24.0 Natural Gas (Bcf) 41.9 44.3 45.0 47.0 NGL (MMBbl) 3.1 3.3 2.8 3.0 Total Production (MMBoe) 32.8 34.7 33.3 34.7 Avg Daily Production (MBoe/d) 90.0 95.0 91.0 95.0 Cash Expenses Cash Operating Expenses and Workovers(1)(2)(4)(7) $ 580 $ 610 $ 555 $ 585 G&A(2)(3)(7) $ 120 $ 130 $ 120 $ 130 Capex Capital Expenditures(5) $ 500 $ 540 $ 490 $ 530 P&A Expenditures P&A, Decommissioning $ 100 $ 120 $ 100 $ 120 Interest Interest Expense(6) $ 155 $ 165 $ 155 $ 165 (1) Includes Lease Operating Expenses and Maintenance. (2) Includes insurance costs. (3) Excludes non-cash equity-based compensation and transaction and other expenses. (4) Includes reimbursements under production handling agreements. (5) Excludes acquisitions. (6) Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts. (7) Due to the forward-looking nature a reconciliation of Cash Operating Expenses and Workovers and G&A to the most directly comparable GAAP measure could not be reconciled without unreasonable efforts. HEDGES The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of June 30, 2025. Instrument Type Avg. DailyVolume W.A. Swap W.A. Floor W.A. Ceiling Crude - WTI (Bbls) (Per Bbl) (Per Bbl) (Per Bbl) July - September 2025 Fixed Swaps 25,370 $ 71.57 --- --- October - December 2025 Fixed Swaps 22,967 $ 71.33 --- --- January - March 2026 Fixed Swaps 14,000 $ 66.26 --- --- Collar 11,000 --- $ 60.46 $ 68.50 April - June 2026 Fixed Swaps 14,000 $ 65.11 --- --- Collar 11,000 --- $ 60.46 $ 68.50 July - September 2026 Fixed Swaps 2,000 $ 65.00 --- --- Collar 11,000 --- $ 60.46 $ 68.50 October - December 2026 Fixed Swaps 2,000 $ 65.00 --- --- Collar 11,000 --- $ 60.46 $ 68.50 Natural Gas - HH NYMEX (MMBtu) (Per MMBtu) (Per MMBtu) (Per MMBtu) July - September 2025 Fixed Swaps 50,000 $ 3.47 --- --- October - December 2025 Fixed Swaps 40,000 $ 3.53 --- --- January - March 2026 Fixed Swaps 35,000 $ 4.19 --- --- April - June 2026 Fixed Swaps 30,000 $ 3.77 --- --- July - September 2026 Fixed Swaps 20,000 $ 3.65 --- --- October - December 2026 Fixed Swaps 20,000 $ 3.65 --- --- CONFERENCE CALL AND WEBCAST INFORMATION Talos will host a conference call, broadcast live over the internet, on Thursday, August 7, 2025, at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call through a webcast link on the Company's website at: Talos Second Quarter 2025 Webcast. Alternatively, the conference call can be accessed by dialing (800) 836-8184 (North American toll-free) or (646) 357-8785 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference until August 14, 2025 and can be accessed by dialing (888) 660-6345 and using access code 83342#. For more information, please refer to the Second Quarter 2025 Earnings Presentation available under Presentations and Webcasts on the Investor Relations section of Talos's website. ABOUT TALOS ENERGY Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on maximizing long-term value through its Exploration & Production business in the United States Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility, and community impact. For more information, visit www.talosenergy.com. INVESTOR RELATIONS CONTACT Clay JeansonneClay.Jeansonne@talosenergy.com CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS The information in this communication includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical fact included in this communication regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "will," "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast," "may," "objective," "plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on management's current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on our current beliefs, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about: business strategy; estimated ultimate recovery (EUR), estimated gross resource potential and reserves; drilling prospects, inventories, projects and programs; our ability to replace the reserves that we produce through drilling and property acquisitions; financial strategy, borrowing base under our bank credit facility, availability of financing sources, liquidity position and capital required for our development program, acquisitions and other capital expenditures; realized oil and natural gas prices; changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements, including such changes that may be implemented by the Trump Administration, and the impact of such policies on us, our customers and suppliers, and the global economic environment; volatility in the political, legal and regulatory environments; risks related to future mergers and acquisitions and/or to realize the expected benefits of any such transaction; timing and amount of future production of oil, natural gas and NGLs; our hedging strategy and results; future drilling plans; availability of pipeline connections on economic terms; competition, government regulations, including financial assurance requirements, and legislative and political developments; our ability to obtain permits and governmental approvals; pending legal, governmental or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions and the anticipated post-acquisition performance of the Company; future leasehold or business acquisitions on desired terms; costs of developing properties; general economic conditions, including the impact of continued inflation and associated changes in monetary policy; political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage; credit markets; estimates of future income taxes; our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; our strategy with respect to our investment in the Zama asset; uncertainty regarding our future operating results and our future revenues and expenses; impact of new accounting pronouncements on earnings in future periods; and plans, objectives, expectations and intentions contained in this communication that are not historical. These forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and ongoing hostilities in Israel and the Middle East, and their impact on commodity markets; the impact of any pandemic, and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; political risks, including a global trade war; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats; elevated inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes, including the impact of financial assurance requirements; changes in U.S. trade policy, including the imposition of increased tariffs and resulting consequences; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; and the other risks discussed in "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2024 and our subsequent Quarterly Reports on Form 10-Qs, each as filed with the SEC. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this communication are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication. PRODUCTION ESTIMATES Estimates of our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, adverse weather conditions such as hurricanes, global political and macroeconomic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performance and estimated resource potential and ultimate recovery, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated. RESERVE INFORMATION Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. In addition, we use "estimated gross resource potential," "gross reserves," and "estimated ultimate recovery" (or EUR) which are not measures of "reserves" prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These types of resource estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are inherently more uncertain than estimates of proved reserves or other reserves prepared in accordance with SEC guidelines. These types of estimates are subject to a substantially greater risk of actually being realized. USE OF NON-GAAP FINANCIAL MEASURES This release includes the use of certain measures that have not been calculated in accordance with U.S. generally acceptable accounting principles (GAAP) such as, but not limited to, EBITDA, Adjusted EBITDA, LTM Adjusted EBITDA, Net Debt, Net Debt to LTM Adjusted EBITDA, Adjusted Free Cash Flow and Leverage, Adjusted EBITDA excluding hedges, Adjusted Net Income (Loss) per diluted share, Adjusted Earnings Per Share, Cash Operating Expenses and Workovers, Adjusted General & Administrative Expense and PV-10. Non-GAAP financial measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations for non-GAAP measures to GAAP measures are included at the end of this release. Talos Energy Inc. Condensed Consolidated Balance Sheets (In thousands, except share amounts) June 30, 2025 December 31, 2024 (Unaudited) ASSETS Current assets: Cash and cash equivalents $ 357,287 $ 108,172 Restricted cash 32,623 - Accounts receivable: Trade, net 209,900 236,694 Joint interest, net 96,771 133,562 Other, net 33,725 34,002 Assets from price risk management activities 61,496 33,486 Prepaid assets 64,287 77,487 Other current assets 14,556 35,980 Total current assets 870,645 659,383 Property and equipment: Proved properties 10,134,829 9,784,832 Unproved properties, not subject to amortization 542,977 587,238 Other property and equipment 35,196 35,069 Total property and equipment 10,713,002 10,407,139 Accumulated depreciation, depletion and amortization (5,966,167) (5,191,865) Total property and equipment, net 4,746,835 5,215,274 Other long-term assets: Restricted cash 75,174 106,260 Assets from price risk management activities 14,834 253 Equity method investments 112,589 111,269 Other well equipment 65,381 58,306 Notes receivable, net 18,669 17,748 Operating lease assets 10,379 11,294 Other assets 10,196 12,008 Total assets $ 5,924,702 $ 6,191,795 LIABILITIES AND STOCKHOLDERSʼ EQUITY Current liabilities: Accounts payable $ 105,355 $ 117,055 Accrued liabilities 302,604 326,913 Accrued royalties 66,300 77,672 Current portion of asset retirement obligations 127,959 97,166 Liabilities from price risk management activities 10,027 6,474 Accrued interest payable 49,016 49,084 Current portion of operating lease liabilities 3,823 3,837 Other current liabilities 47,042 44,854 Total current liabilities 712,126 723,055 Long-term liabilities: Long-term debt 1,223,736 1,221,399 Asset retirement obligations 1,093,114 1,052,569 Liabilities from price risk management activities 10,055 3,537 Operating lease liabilities 13,776 15,489 Other long-term liabilities 352,882 416,041 Total liabilities 3,405,689 3,432,090 Commitments and contingencies Stockholdersʼ equity: Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstandingas of June 30, 2025 and December 31, 2024, respectively - - Common stock; $0.01 par value; 270,000,000 shares authorized; 188,201,673 and 187,434,908 shares issued as of June 30, 2025 and December 31, 2024, respectively 1,882 1,874 Additional paid-in capital 3,284,467 3,274,626 Accumulated deficit (619,915) (424,110) Treasury stock, at cost; 13,544,328 and 7,417,385 shares as of June 30, 2025 and December 31, 2024, respectively (147,421) (92,685) Total stockholdersʼ equity 2,519,013 2,759,705 Total liabilities and stockholdersʼ equity $ 5,924,702 $ 6,191,795 Talos Energy Inc. Condensed Consolidated Statements of Operations (In thousands, except per share amounts) (Unaudited) Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Revenues: Oil $ 373,195 $ 507,408 $ 813,918 $ 900,629 Natural gas 39,415 26,060 92,150 49,758 NGL 12,111 15,697 31,712 28,710 Total revenues 424,721 549,165 937,780 979,097 Operating expenses: Lease operating expense 136,971 157,310 264,776 292,488 Production taxes 130 476 244 1,020 Depreciation, depletion and amortization 269,706 259,091 550,422 474,755 Impairment of oil and natural gas properties 223,881 - 223,881 - Accretion expense 32,046 30,732 62,940 57,635 General and administrative expense 39,430 48,247 74,045 118,088 Other operating (income) expense (3,851) (1,061) (8,387) (87,104) Total operating expenses 698,313 494,795 1,167,921 856,882 Operating income (expense) (273,592) 54,370 (230,141) 122,215 Interest expense (40,811) (48,982) (81,738) (99,827) Price risk management activities income (expense) 86,855 2,302 71,002 (84,760) Equity method investment income (expense) (186) (456) (676) (8,510) Other income (expense) 5,371 4,164 9,231 (51,732) Net income (loss) before income taxes (222,363) 11,398 (232,322) (122,614) Income tax benefit (expense) 36,426 983 36,517 22,556 Net income (loss) $ (185,937) $ 12,381 $ (195,805) $ (100,058) Net income (loss) per common share: Basic $ (1.05) $ 0.07 $ (1.10) $ (0.59) Diluted $ (1.05) $ 0.07 $ (1.10) $ (0.59) Weighted average common shares outstanding: Basic 177,404 183,564 178,791 171,027 Diluted 177,404 183,692 178,791 171,027 Talos Energy Inc. Condensed Consolidated Statements of Cash Flows (In thousands) (Unaudited) Six Months Ended June 30, 2025 2024 Cash flows from operating activities: Net income (loss) $ (195,805) $ (100,058) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion, amortization and accretion expense 613,362 532,390 Impairment of oil and natural gas properties 223,881 - Amortization of deferred financing costs and original issue discount 3,695 5,084 Equity-based compensation expense 8,544 5,544 Price risk management activities (income) expense (71,002) 84,760 Net cash received (paid) on settled derivative instruments 38,482 (21,012) Equity method investment (income) expense 676 8,510 Loss (gain) on extinguishment of debt - 60,256 Settlement of asset retirement obligations (38,249) (50,128) Loss (gain) on sale of assets (16) (2,500) Loss (gain) on sale of business - (86,940) Changes in operating assets and liabilities: Accounts receivable 63,863 3,076 Other current assets 24,361 (5,150) Accounts payable (2,451) (43,608) Other current liabilities (9,244) 17,748 Other non-current assets and liabilities, net (40,219) (22,182) Net cash provided by (used in) operating activities 619,878 385,790 Cash flows from investing activities: Exploration, development and other capital expenditures (276,149) (269,170) Payments for acquisitions, net of cash acquired (14,845) (916,045) Proceeds from (cash paid for) sale of property and equipment, net 687 - Contributions to equity method investees (1,996) (19,627) Proceeds from sales of businesses - 141,997 Net cash provided by (used in) investing activities (292,303) (1,062,845) Cash flows from financing activities: Issuance of common stock - 387,717 Issuance of senior notes - 1,250,000 Redemption of senior notes - (897,116) Proceeds from Bank Credit Facility - 770,000 Repayment of Bank Credit Facility - (745,000) Deferred financing costs - (27,386) Other deferred payments (10,172) (1,234) Payments of finance lease (9,616) (8,747) Purchase of treasury stock (54,736) (39,326) Employee stock awards tax withholdings (2,399) (5,687) Net cash provided by (used in) financing activities (76,923) 683,221 Net increase (decrease) in cash, cash equivalents and restricted cash 250,652 6,166 Cash, cash equivalents and restricted cash: Balance, beginning of period 214,432 135,999 Balance, end of period $ 465,084 $ 142,165 Supplemental non-cash transactions: Capital expenditures included in accounts payable and accrued liabilities $ 48,926 $ 79,832 Supplemental cash flow information: Interest paid, net of amounts capitalized $ 59,769 $ 64,452 SUPPLEMENTAL NON-GAAP INFORMATION Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies. Reconciliation of General and Administrative Expenses to Adjusted General and Administrative Expenses We believe the presentation of Adjusted General and Administrative Expenses provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted General & Administrative Expenses has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following: General and Administrative Expenses. General and Administrative Expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance. ($ thousands) Three Months Ended June 30, 2025 Reconciliation of General & Administrative Expenses to Adjusted General & AdministrativeExpenses: Total General and administrative expense $ 39,430 Transaction expenses (663) Non-cash equity-based compensation expense (4,403) Adjusted General & Administrative Expenses $ 34,364 Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA "EBITDA" and "Adjusted EBITDA" provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following: EBITDA. Net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion and amortization; and accretion expense. Adjusted EBITDA. EBITDA plus non-cash impairment of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in fair value of derivatives (mark-to-market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense. Adjusted EBITDA excluding hedges. We have historically provided as a supplement to-rather than in lieu of-Adjusted EBITDA including hedges, provides useful information regarding our results of operations and profitability by illustrating the operating results of our oil and natural gas properties without the benefit or detriment, as applicable, of our financial oil and natural gas hedges. By excluding our oil and natural gas hedges, we are able to convey actual operating results using realized market prices during the period, thereby providing analysts and investors with additional information they can use to evaluate the impacts of our hedging strategies over time. The following tables present a reconciliation of the GAAP financial measure of Net Income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges for each of the periods indicated (in thousands): Three Months Ended ($ thousands) June 30, 2025 March 31, 2025 December 31, 2024 September 30, 2024 Reconciliation of Net Income (Loss) to Adjusted EBITDA: Net Income (loss) $ (185,937) $ (9,868) $ (64,508) $ 88,173 Interest expense 40,811 40,927 41,536 46,275 Income tax expense (benefit) (36,426) (91) 9,448 18,111 Depreciation, depletion and amortization 269,706 280,716 274,554 274,249 Accretion expense 32,046 30,894 30,551 29,418 EBITDA 120,200 342,578 291,581 456,226 Impairment of oil and natural gas properties 223,881 - - - Transaction and other (income) expenses(1) (773) (4,579) 1,193 (17,687) Decommissioning obligations(2) 76 (157) 797 2,725 Derivative fair value (gain) loss(3) (86,855) 15,853 42,989 (126,291) Net cash received (paid) on settled derivative instruments(3) 33,315 5,167 19,651 6,071 Non-cash equity-based compensation expense 4,403 4,141 5,603 3,315 Adjusted EBITDA 294,247 363,003 361,814 324,359 Add: Net cash (received) paid on settled derivative instruments(3) (33,315) (5,167) (19,651) (6,071) Adjusted EBITDA excluding hedges $ 260,932 $ 357,836 $ 342,163 $ 318,288 Production: Boe(4) 8,494 9,080 9,081 8,878 Adjusted EBITDA and Adjusted EBITDA excluding hedges margin: Adjusted EBITDA per Boe(4) $ 34.64 $ 39.98 $ 39.84 $ 36.54 Adjusted EBITDA excluding hedges per Boe(1)(4) $ 30.72 $ 39.41 $ 37.68 $ 35.85 (1) For the three months ended September 30, 2024, transaction expenses include $4.7 million of severance costs related to the departure of the Company's former President and Chief Executive Officer on August 29, 2024. Other income (expense) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended September 30, 2024, it includes an incremental $13.5 million gain from the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC, due to the recognition of contingent consideration as well as a $7.0 million increase in fair value of a service credit acquired via the QuarterNorth Acquisition. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency and are included in "Other operating (income) expense" on our consolidated statements of operations. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. (4) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow "Adjusted Free Cash Flow" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Free Cash Flow has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following: Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals. Interest Expense. Actual interest expense per the income statement. Talos did not pay any cash income taxes in the period, therefore cash income taxes have no impact to the reported Adjusted Free Cash Flow before changes in working capital number. ($ thousands) Three Months Ended June 30, 2025 Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow (before changes in working capital): Adjusted EBITDA $ 294,247 Capital expenditures (124,061) Plugging & abandonment (28,497) Decommissioning obligations settled (350) Investment in Mexico (1,996) Interest expense (40,811) Adjusted Free Cash Flow (before changes in working capital) 98,532 ($ thousands) Three Months EndedJune 30, 2025 Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow (beforechanges in working capital): Net cash provided by operating activities(1) $ 351,637 (Increase) decrease in operating assets and liabilities (87,524) Capital expenditures(2) (124,061) Decommissioning obligations settled (350) Investment in Mexico (1,996) Transaction and other (income) expenses(3) (773) Decommissioning obligations(4) 76 Amortization of deferred financing costs and original issue discount (1,865) Income tax benefit (36,426) Other adjustments (186) Adjusted Free Cash Flow (before changes in working capital) 98,532 (1) Includes settlement of asset retirement obligations. (2) Includes accruals and excludes acquisitions. (3) Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. (4) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share "Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP. Adjusted Net Income (Loss). Net income (loss) plus impairment of oil and natural gas properties, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments, income tax expense (benefit) and non-cash equity-based compensation expense. Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares. Three Months Ended June 30, 2025 ($ thousands, except per share amounts) Basic per Share Diluted per Share Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss): Net Income (loss) $ (185,937) $ (1.05) $ (1.05) Impairment of oil and natural gas properties 223,881 $ 1.26 $ 1.26 Transaction and other (income) expenses(1) (773) $ (0.00) $ (0.00) Decommissioning obligations(2) 76 $ 0.00 $ 0.00 Derivative fair value (gain) loss(3) (86,855) $ (0.49) $ (0.49) Net cash received (paid) on settled derivative instruments(3) 33,315 $ 0.19 $ 0.19 Non-cash income tax benefit (36,426) $ (0.21) $ (0.21) Non-cash equity-based compensation expense 4,403 $ 0.02 $ 0.02 Adjusted Net Income (Loss)(4) $ (48,316) $ (0.27) $ (0.27) Weighted average common shares outstanding at June 30, 2025: Basic 177,404 Diluted 177,404 (1) Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. (2) Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. (3) The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled. (4) The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA We believe the presentation of Net Debt, LTM Adjusted EBITDA and Net Debt to LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies. Net Debt. Total Debt principal minus cash and cash equivalents. Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA. ($ thousands) June 30, 2025 Reconciliation of Net Debt: 9.000% Second-Priority Senior Secured Notes - due February 2029 $ 625,000 9.375% Second-Priority Senior Secured Notes - due February 2031 625,000 Bank Credit Facility - matures March 2027 - Total Debt 1,250,000 Less: Cash and cash equivalents (357,287) Net Debt $ 892,713 Calculation of LTM Adjusted EBITDA: Adjusted EBITDA for three months period ended September 30, 2024 $ 324,359 Adjusted EBITDA for three months period ended December 31, 2024 361,814 Adjusted EBITDA for three months period ended March 31, 2025 363,003 Adjusted EBITDA for three months period ended June 30, 2025 294,247 LTM Adjusted EBITDA $ 1,343,423 Reconciliation of Net Debt to LTM Adjusted EBITDA: Net Debt / LTM Adjusted EBITDA(1) 0.7x (1) Net Debt / LTM Adjusted EBITDA figure excludes the payments of Finance Lease. Had the Finance Lease been included, Net Debt / LTM Adjusted EBITDA would have been 0.8x. 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KLX ENERGY SERVICES HOLDINGS, INC. REPORTS SECOND QUARTER 2025 RESULTS
KLX ENERGY SERVICES HOLDINGS, INC. REPORTS SECOND QUARTER 2025 RESULTS HOUSTON, Aug. 6, 2025 /PRNewswire/ -- KLX Energy Services Holdings, Inc. (Nasdaq: KLXE) ("KLX", the "Company", "we", "us" or "our") today reported financial results for the second quarter ended June 30, 2025. Second Quarter 2025 Financial and Operational Highlights Revenue of $159 million, a 3% increase over first quarter 2025Net loss of $(20) million and diluted loss per share of $(1.04)Adjusted EBITDA of $19 million, a 34% increase over first quarter 2025Net loss margin of (13)%Adjusted EBITDA margin of 12%, a 30% increase over first quarter 2025Total liquidity of $65 million, consisting of approximately $17 million of cash and cash equivalents, and approximately $49 million of available borrowing capacity under the asset-based revolving credit facility (the "ABL Facility") borrowing base certificate, inclusive of the undrawn first-in-last-out ("FILO") capacitySee "Non-GAAP Financial Measures" at the end of this release for a discussion of Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Net Loss, Adjusted Diluted Loss per share, Unlevered and Levered Free Cash Flow, Net Working Capital, Net Debt and their reconciliations to the most directly comparable financial measure calculated and presented in accordance with U.S. generally accepted accounting principles ("GAAP"). We have not provided reconciliations of our future expectations as to Adjusted EBITDA or Adjusted EBITDA margin as such reconciliations are not available without unreasonable efforts. Chris Baker, KLX President and Chief Executive Officer, stated, "Our solid 2025 second quarter revenue and Adjusted EBITDA results grew as we forecasted. Second quarter revenue was up 3.2% and Adjusted EBITDA margin increased by 260 basis points sequentially over the 2025 first quarter, despite the US land rig count being down (7.3)% sequentially. "We continued to focus on the execution of our operational initiatives, including cost management, asset rotation, holding the line on pricing, and leaning into higher-margin work as spot activity remains soft. In the second quarter we saw significant strength and sequential improvement across our completions and production portfolios. Based on current schedules and several green shoots in our gassy basins, we expect the third quarter to be the strongest quarter of the year. We are again targeting a sequential quarterly revenue increase of low to mid-single digits on a percentage basis, with continued margin expansion. We believe KLX's strategic positioning, operational excellence, and improved financial flexibility position us to effectively manage the ongoing volatility in our markets," concluded Baker. Second Quarter 2025 Financial Results Revenue for the second quarter of 2025 totaled $159.0 million, an increase of 3.2% compared to the first quarter of 2025 revenue of $154.0 million. The increase in revenue reflects a seasonal market activity increase. On a product line basis, drilling, completion, production and intervention services contributed approximately 16%, 56%, 18% and 10%, respectively, to revenue for the second quarter of 2025. Net loss for the second quarter of 2025 was $(19.9) million, compared to the first quarter of 2025 net loss of $(27.9) million. Adjusted net loss for the second quarter of 2025 was $(17.0) million, compared to the first quarter of 2025 adjusted net loss of $(21.9) million. Adjusted EBITDA for the second quarter of 2025 was $18.5 million, compared to the first quarter of 2025 Adjusted EBITDA of $13.8 million. Adjusted EBITDA margin for the second quarter of 2025 was 11.6%, compared to the first quarter of 2025 Adjusted EBITDA margin of 9.0%. Second Quarter 2025 Segment Results The Company reports revenue, operating (loss) income and Adjusted EBITDA through three geographic business segments: Rocky Mountains, Southwest and Northeast/Mid-Con. The Company reports operating activities not attributable to an individual geographic business segment through the Corporate and other segment. Segment results are reported after inter-segment eliminations. Rocky Mountains: Revenue, operating income and Adjusted EBITDA for the Rocky Mountains segment was $54.1 million, $3.3 million and $10.4 million, respectively, for the second quarter of 2025. Second quarter revenue represents a 13.2% sequential increase over the first quarter of 2025, driven by coiled tubing, pressure pumping and tech services. Segment operating income increased sequentially and segment Adjusted EBITDA increased 55.2% sequentially. This quarter-over-quarter improvement in income and margin was a function of higher utilization in the second quarter of 2025 as compared to the first quarter of 2025.Southwest: Revenue, operating loss and Adjusted EBITDA for the Southwest segment, which includes the Permian and South Texas, was $58.8 million, $(1.7) million and $7.2 million, respectively, for the second quarter of 2025. Second quarter revenue represents a (9.8)% sequential decrease over the first quarter of 2025 largely due to lower revenue from the Permian basin. Segment operating income turned negative and Adjusted EBITDA decreased sequentially (38.5)% due to mix shift and increased white space as the Permian experienced the largest sequential activity decrease in the last seven quarters.Northeast/Mid-Con: Revenue, operating loss and Adjusted EBITDA for the Northeast/Mid-Con segment was $46.1 million, $(1.3) million and $7.2 million, respectively, for the second quarter of 2025. Second quarter revenue represents a 12.4% sequential increase over the first quarter of 2025 due to improved KLX completions utilization and increased regional gas-focused activity. Segment operating loss decreased by 84.0% and segment Adjusted EBITDA increased 166.7% as compared to the first quarter of 2025 due to improved utilization and decreased white space.Corporate and other: Operating loss and Adjusted EBITDA loss for the Corporate and other segment were $(9.0) million and $(6.3) million, respectively, for the second quarter of 2025. Segment operating loss decreased due to lower overhead and fixed costs in the current quarter.The following is a tabular summary of revenue, operating (loss) income and Adjusted EBITDA (loss) for the second quarter ended June 30, 2025, the first quarter ended March 31, 2025 and the second quarter ended June 30, 2024 ($ in millions). Three Months Ended June 30, 2025 March 31, 2025 June 30, 2024 Revenue: Rocky Mountains $ 54.1 $ 47.8 $ 61.4 Southwest 58.8 65.2 69.9 Northeast/Mid-Con 46.1 41.0 48.9 Total revenue $ 159.0 $ 154.0 $ 180.2 Three Months Ended June 30, 2025 March 31, 2025 June 30, 2024 Operating (loss) income: Rocky Mountains $ 3.3 $ (0.2) $ 10.5 Southwest (1.7) 3.0 2.6 Northeast/Mid-Con (1.3) (8.1) (2.5) Corporate and other (9.0) (12.4) (9.2) Total operating (loss) income $ (8.7) $ (17.7) $ 1.4 Three Months Ended June 30, 2025 March 31, 2025 June 30, 2024 Adjusted EBITDA (loss) Rocky Mountains $ 10.4 $ 6.7 $ 17.2 Southwest 7.2 11.7 10.4 Northeast/Mid-Con 7.2 2.7 6.4 Segment total 24.8 21.1 34.0 Corporate and other (6.3) (7.3) (7.0) Total Adjusted EBITDA(1) $ 18.5 $ 13.8 $ 27.0 (1) Excludes one-time costs, as defined in the Reconciliation of Consolidated Net Loss to Adjusted EBITDA table below, non-cash compensation expense and non-cash asset impairment expense. Balance Sheet and Liquidity As of June 30, 2025, cash and cash equivalents totaled $16.7 million and the Company had availability of $48.7 million on the ABL Facility borrowing base certificate, including availability on an undrawn FILO facility, resulting in a total liquidity position of $65.4 million. Net Working Capital as of June 30, 2025 was $45.9 million, a (23)% decrease from March 31, 2025 driven by a 19% increase in days payable outstanding and non-recurrence of the two extra payrolls that burdened the first quarter. We expect to operate with a lower cash balance than in prior periods due to the flexibility provided by the new ABL Facility, and we expect to improve our liquidity as we navigate the remainder of the year. Other Financial Information Capital expenditures were $12.7 million during the second quarter of 2025, a decrease of $2.3 million or (15)% compared to capital expenditures of $15.0 million in the first quarter of 2025. Capital expenditures net of asset sales were $11.1 million during the second quarter of 2025, an increase of $0.9 million or 9% compared to capital expenditures net of asset sales of $10.2 in the first quarter of 2025. Capital spending during the second quarter was driven primarily by maintenance capital expenditures across our segments. As of June 30, 2025, we had $2.2 million of assets held for sale related to two facilities and select equipment in the Rocky Mountains and Southwest segments. Conference Call Information KLX will conduct its second quarter 2025 conference call, which can be accessed via dial-in or webcast, on Thursday, August 7, 2025 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) by dialing 1-201-389-0867 and asking for the KLX conference call at least 10 minutes prior to the start time, or by logging onto the webcast at https://investor.klx.com/events-and-presentations/events. For those who cannot listen to the live call, a replay will be available through August 21, 2025, and may be accessed by dialing 1-201-612-7415 and using passcode 13754590#. Also, an archive of the webcast will be available shortly after the call at https://investor.klx.com/events-and-presentations/events for 90 days. Please submit any questions for management prior to the call via email to KLXE@dennardlascar.com. About KLX Energy Services Holdings, Inc. KLX is a growth-oriented provider of diversified oilfield services to leading onshore oil and natural gas exploration and production companies operating in both conventional and unconventional plays in all of the active major basins throughout the United States. The Company delivers mission critical oilfield services focused on drilling, completion, production, and intervention activities for technically demanding wells from over 60 service and support facilities located throughout the United States. KLX's complementary suite of proprietary products and specialized services is supported by technically skilled personnel and a broad portfolio of innovative in-house manufacturing, repair and maintenance capabilities. More information is available at www.klx.com. Forward-Looking Statements and Cautionary Statements The Private Securities Litigation Reform Act of 1995 provides a "safe harbor" for forward-looking statements to encourage companies to provide prospective information to investors. This news release (and any oral statements made regarding the subjects of this release, including on the conference call announced herein) includes forward-looking statements that reflect our current expectations and projections about our future results, performance and prospects. Forward-looking statements include all statements that are not historical in nature and are not current facts. When used in this news release (and any oral statements made regarding the subjects of this release, including on the conference call announced herein), the words "believe," "expect," "plan," "intend," "anticipate," "estimate," "predict," "potential," "continue," "may," "might," "should," "could," "will" or the negative of these terms or similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events with respect to, among other things: our operating cash flows; the availability of capital and our liquidity; our future revenue, income and operating performance; our ability to sustain and improve our utilization, revenue and margins; our ability to maintain acceptable pricing for our services; future capital expenditures; our ability to finance equipment, working capital and capital expenditures; our ability to execute our long-term growth strategy and to integrate our acquisitions; our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; and the timing and success of strategic initiatives and special projects. Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements are based on management's current expectations and beliefs, forecasts for our existing operations, experience, expectations and perception of historical trends, current conditions, anticipated future developments and their effect on us and other factors believed to be appropriate. Although management believes the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks associated with the following: a decline in demand for our services, including due to overcapacity and other competitive factors affecting our industry; the cyclical nature and volatility of the oil and gas industry, which impacts the level of exploration, production and development activity and spending patterns by oil and natural gas exploration and production companies; a decline in, or substantial volatility of, crude oil and gas commodity prices, which generally leads to decreased spending by our customers and negatively impacts drilling, completion and production activity; inflation; increases in interest rates; the ongoing war in Ukraine and its continuing effects on global trade; the ongoing conflict and tensions in the Middle East; supply chain issues; general economic, financial and political conditions, including market volatility and the impact of the imposition of increased, new and retaliatory tariffs; and other risks and uncertainties listed in our filings with the U.S. Securities and Exchange Commission, including our Current Reports on Form 8-K that we file from time to time, Quarterly Reports on Form 10-Q and Annual Report on Form 10-K. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as required by law. Contacts: KLX Energy Services Holdings, Inc. Keefer M. Lehner, EVP & CFO 832-930-8066 IR@klx.com Dennard Lascar Investor Relations Ken Dennard / Natalie Hairston 713-529-6600 KLXE@dennardlascar.com KLX Energy Services Holdings, Inc. Condensed Consolidated Statements of Operations (In millions of U.S. dollars and shares, except per share data) (Unaudited) Three Months Ended June 30, 2025 March 31, 2025 June 30, 2024 Revenues $ 159.0 $ 154.0 $ 180.2 Costs and expenses: Cost of sales 125.6 123.8 136.0 Depreciation and amortization 23.7 24.7 23.1 Selling, general and administrative 18.0 21.6 19.3 Research and development costs 0.4 0.4 0.3 Loss on debt extinguishment - 1.2 - Impairment and other charges - - 0.1 Operating (loss) income (8.7) (17.7) 1.4 Non-operating expense: Interest income 0.0 (0.3) (0.6) Interest expense 11.0 10.3 9.8 Net loss before income tax (19.7) (27.7) (7.8) Income tax expense 0.2 0.2 0.2 Net loss $ (19.9) $ (27.9) $ (8.0) Net loss per common share: Basic $ (1.04) $ (1.62) $ (0.49) Diluted $ (1.04) $ (1.62) $ (0.49) Weighted average common shares: Basic 19.2 17.2 16.2 Diluted 19.2 17.2 16.2 KLX Energy Services Holdings, Inc. Condensed Consolidated Balance Sheets (In millions of U.S. dollars and shares, except per share data) (Unaudited) June 30, 2025 December 31, 2024 (Unaudited) ASSETS Current assets: Cash and cash equivalents $ 16.7 $ 91.6 Restricted cash(1) 0.6 - Accounts receivable-trade, net of allowance of $4.4 and $4.2 106.0 96.9 Inventories, net 32.0 31.0 Prepaid expenses and other current assets 17.4 13.5 Total current assets 172.7 233.0 Property and equipment, net(2) 171.1 197.1 Operating lease assets 18.1 19.6 Intangible assets, net 1.3 1.5 Other assets 6.3 5.1 Total assets $ 369.5 $ 456.3 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 69.7 $ 74.4 Accrued interest 0.4 4.5 Accrued liabilities 39.8 41.3 Current portion of long-term debt 4.5 - Current portion of operating lease obligations 7.0 6.9 Current portion of finance lease obligations 17.7 13.0 Total current liabilities 139.1 140.1 Long-term debt 254.2 285.1 Long-term operating lease obligations 11.7 13.5 Long-term finance lease obligations 10.6 26.4 Other non-current liabilities 1.1 1.7 Commitments, contingencies and off-balance sheet arrangements Stockholders' equity: Common stock, $0.01 par value; 110.0 authorized; 18.3 and 17.5 issued 0.2 0.2 Additional paid-in capital 569.0 557.5 Treasury stock, at cost, 0.5 shares and 0.5 shares (6.2) (5.8) Accumulated deficit (610.2) (562.4) Total stockholders' deficit (47.2) (10.5) Total liabilities and stockholders' deficit $ 369.5 $ 456.3 (1) Restricted cash on the balance sheet is largely tied to cash collateralized letters of credit as the Company shifts to its current ABL Facility, and as of the date of this news release, $0.6 million of the restricted cash remains restricted. (2) Includes right-of-use assets - finance leases. KLX Energy Services Holdings, Inc.Additional Selected Operating Data(Unaudited) Non-GAAP Financial Measures This release includes Adjusted EBITDA, Adjusted EBITDA margin, Adjusted Net Loss, Adjusted Diluted Loss per share, Unlevered and Levered Free Cash Flow, Net Working Capital and Net Debt measures. Each of the metrics are "non-GAAP financial measures" as defined in Regulation G of the Securities Exchange Act of 1934. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA is not a measure of net earnings or cash flows as determined by GAAP. We define Adjusted EBITDA as net loss before interest, taxes, depreciation and amortization, further adjusted for (i) goodwill and/or long-lived asset impairment charges, (ii) stock-based compensation expense, (iii) restructuring charges, (iv) transaction and integration costs related to acquisitions and (v) other expenses or charges to exclude certain items that we believe are not reflective of the ongoing performance of our business. Adjusted EBITDA is used to calculate the Company's leverage ratio, consistent with the terms of the Company's ABL Facility. We believe Adjusted EBITDA is useful because it allows us to supplement the GAAP measures in order to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above 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 considered as an alternative to, or more meaningful than, net loss as determined in accordance with GAAP, or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Adjusted EBITDA margin is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Adjusted EBITDA margin is not a measure of net earnings or cash flows as determined by GAAP. Adjusted EBITDA margin is defined as the quotient of Adjusted EBITDA and total revenue. We believe Adjusted EBITDA margin is useful because it allows us to supplement the GAAP measures in order to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure, as a percentage of revenues. We define Adjusted Net Loss as consolidated net loss adjusted for (i) goodwill and/or long-lived asset impairment charges, (ii) restructuring charges, (iii) transaction and integration costs related to acquisitions and (iv) other expenses or charges to exclude certain items that we believe are not reflective of the ongoing performance of our business. We believe Adjusted Net Loss is useful because it allows us to exclude non-recurring items in evaluating our operating performance. We define Adjusted Diluted Loss per share as the quotient of Adjusted Net Loss and diluted weighted average common shares. We believe that Adjusted Diluted Loss per share provides useful information to investors because it allows us to exclude non-recurring items in evaluating our operating performance on a diluted per share basis. We define Unlevered Free Cash Flow as net cash provided by operating activities less capital expenditures and proceeds from sale of property and equipment plus cash interest expense. We define Levered Free Cash Flow as net cash provided by operating activities less capital expenditures and proceeds from sale of property and equipment. Our management uses Unlevered and Levered Free Cash Flow to assess the Company's liquidity and ability to repay maturing debt, fund operations and make additional investments. We believe that each of Unlevered and Levered Free Cash Flow provide useful information to investors because it is an important indicator of the Company's liquidity, including our ability to reduce Net Debt and make strategic investments. Net Working Capital is calculated as current assets, excluding cash, less current liabilities, excluding accrued interest and finance lease obligations. We believe that Net Working Capital provides useful information to investors because it is an important indicator of the Company's liquidity. We define Net Debt as total debt less cash and cash equivalents and restricted cash. We believe that Net Debt provides useful information to investors because it is an important indicator of the Company's indebtedness. The following tables present a reconciliation of non-GAAP financial measures to the most directly comparable GAAP financial measures for the periods indicated: KLX Energy Services Holdings, Inc. Reconciliation of Consolidated Net Loss to Adjusted EBITDA* (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Consolidated net loss $ (19.9) $ (27.9) $ (8.0) Income tax expense 0.2 0.2 0.2 Interest expense, net 11.0 10.0 9.2 Operating (loss) income (8.7) (17.7) 1.4 Impairment and other charges (1) - - 0.1 One-time net costs (1) 2.9 6.0 1.4 Adjusted operating (loss) income (5.8) (11.7) 2.9 Depreciation and amortization 23.7 24.7 23.1 Non-cash compensation 0.6 0.8 1.0 Adjusted EBITDA $ 18.5 $ 13.8 $ 27.0 *Previously announced quarterly numbers may not sum to the year-end total due to rounding. (1) The one-time costs during the second quarter of 2025 relate mainly to legal costs, operational costs and other. KLX Energy Services Holdings, Inc. Consolidated Net Loss Margin(1) (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Consolidated net loss $ (19.9) $ (27.9) $ (8.0) Revenue 159.0 154.0 180.2 Consolidated net loss margin percentage (12.5) % (18.1) % (4.4) % (1) Consolidated net loss margin is defined as the quotient of consolidated net loss and total revenue. KLX Energy Services Holdings, Inc. Consolidated Adjusted EBITDA Margin(1) (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Adjusted EBITDA $ 18.5 $ 13.8 $ 27.0 Revenue 159.0 154.0 180.2 Adjusted EBITDA Margin Percentage 11.6 % 9.0 % 15.0 % (1) Adjusted EBITDA margin is defined as the quotient of Adjusted EBITDA and total revenue. Adjusted EBITDA is net (loss) income excluding one-time costs (as defined above), depreciation and amortization expense, non-cash compensation expense and non-cash asset impairment expense. KLX Energy Services Holdings, Inc. Reconciliation of Rocky Mountains Operating Income (Loss) to Adjusted EBITDA (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Rocky Mountains operating income (loss) $ 3.3 $ (0.2) $ 10.5 One-time costs (1) 0.5 - - Adjusted operating income (loss) 3.8 (0.2) 10.5 Depreciation and amortization expense 6.5 6.8 6.7 Non-cash compensation 0.1 0.1 - Rocky Mountains Adjusted EBITDA $ 10.4 $ 6.7 $ 17.2 (1) One-time costs are defined in the Reconciliation of Consolidated Net Loss to Adjusted EBITDA table above. For purposes of segment reconciliation, one-time costs also include impairment and other charges. KLX Energy Services Holdings, Inc. Reconciliation of Southwest Operating (Loss) Income to Adjusted EBITDA (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Southwest operating (loss) income $ (1.7) $ 3.0 $ 2.6 One-time costs (1) 0.5 0.3 0.4 Adjusted operating (loss) income (1.2) 3.3 3.0 Depreciation and amortization expense 8.4 8.3 7.4 Non-cash compensation - 0.1 - Southwest Adjusted EBITDA $ 7.2 $ 11.7 $ 10.4 (1) One-time costs are defined in the Reconciliation of Consolidated Net Loss to Adjusted EBITDA table above. For purposes of segment reconciliation, one-time costs also include impairment and other charges. KLX Energy Services Holdings, Inc. Reconciliation of Northeast/Mid-Con Operating Loss to Adjusted EBITDA (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Northeast/Mid-Con operating loss $ (1.3) $ (8.1) $ (2.5) One-time costs (1) 0.1 1.8 0.2 Adjusted operating loss (1.2) (6.3) (2.3) Depreciation and amortization expense 8.4 9.0 8.6 Non-cash compensation - - 0.1 Northeast/Mid-Con Adjusted EBITDA $ 7.2 $ 2.7 $ 6.4 (1) One-time costs are defined in the Reconciliation of Consolidated Net Loss to Adjusted EBITDA table above. For purposes of segment reconciliation, one-time costs also include impairment and other charges. KLX Energy Services Holdings, Inc. Reconciliation of Corporate and Other Operating Loss to Adjusted EBITDA Loss (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Corporate and other operating loss $ (9.0) $ (12.4) $ (9.2) Impairment and other charges - - 0.1 One-time costs (1) 1.8 3.9 0.8 Adjusted operating loss (7.2) (8.5) (8.3) Depreciation and amortization expense 0.4 0.6 0.4 Non-cash compensation 0.5 0.6 0.9 Corporate and other Adjusted EBITDA loss $ (6.3) $ (7.3) $ (7.0) (1) One-time costs are defined in the Reconciliation of Consolidated Net Loss to Adjusted EBITDA table above. For purposes of segment reconciliation, one-time costs also include impairment and other charges. KLX Energy Services Holdings, Inc. Segment Operating Income (Loss) Margin(1) (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Rocky Mountains Operating income (loss) $ 3.3 $ (0.2) $ 10.5 Revenue 54.1 47.8 61.4 Segment operating income (loss) margin percentage 6.1 % (0.4) % 17.1 % Southwest Operating (loss) income (1.7) 3.0 2.6 Revenue 58.8 65.2 69.9 Segment operating (loss) income margin percentage (2.9) % 4.6 % 3.7 % Northeast/Mid-Con Operating loss (1.3) (8.1) (2.5) Revenue 46.1 41.0 48.9 Segment operating loss margin percentage (2.8) % (19.8) % (5.1) % (1) Segment operating income (loss) margin is defined as the quotient of segment operating income (loss) and segment revenue. KLX Energy Services Holdings, Inc. Segment Adjusted EBITDA Margin(1) (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Rocky Mountains Adjusted EBITDA $ 10.4 $ 6.7 $ 17.2 Revenue 54.1 47.8 61.4 Adjusted EBITDA Margin Percentage 19.2 % 14.0 % 28.0 % Southwest Adjusted EBITDA 7.2 11.7 10.4 Revenue 58.8 65.2 69.9 Adjusted EBITDA Margin Percentage 12.2 % 17.9 % 14.9 % Northeast/Mid-Con Adjusted EBITDA 7.2 2.7 6.4 Revenue 46.1 41.0 48.9 Adjusted EBITDA Margin Percentage 15.6 % 6.6 % 13.1 % (1) Segment Adjusted EBITDA margin is defined as the quotient of Segment Adjusted EBITDA and total segment revenue. Segment Adjusted EBITDA is segment operating (loss) income excluding one-time costs (as defined above), non-cash compensation expense and non-cash asset impairment expense. KLX Energy Services Holdings, Inc. Reconciliation of Consolidated Net Loss to Adjusted Net Loss and Adjusted Diluted Loss per Share (In millions of U.S. dollars and shares, except per share amounts) (Unaudited) Three Months Ended June 30,2025 March 31,2025 June 30,2024 Consolidated net loss $ (19.9) $ (27.9) $ (8.0) Impairment and other charges - - 0.1 One-time costs(1) 2.9 6.0 1.4 Adjusted Net Loss $ (17.0) $ (21.9) $ (6.5) Diluted weighted average common shares 19.2 17.2 16.2 Adjusted Diluted Loss per share(2) $ (0.88) $ (1.27) $ (0.40) *Previously announced quarterly numbers may not sum to the year-end total due to rounding. (1) The one-time costs during the second quarter of 2025 relate mainly to legal costs, operational costs and other. (2) Adjusted Diluted Loss per share is defined as the quotient of Adjusted Net Loss and diluted weighted average common shares. KLX Energy Services Holdings, Inc. Reconciliation of Net Cash Flow Provided by (Used In) Operating Activities to Free Cash Flow (In millions of U.S. dollars) (Unaudited) Three Months Ended June 30, 2025 March 31,2025 June 30, 2024 Net cash flow provided by (used in) operating activities $ 19.1 $ (37.6) $ 22.2 Capital expenditures (12.7) (15.0) (15.3) Proceeds from sale of property and equipment 1.6 4.8 3.3 Levered Free Cash Flow 8.0 (47.8) 10.2 Add: Cash interest expense, net 3.9 10.0 9.2 Unlevered Free Cash Flow $ 11.9 $ (37.8) $ 19.4 KLX Energy Services Holdings, Inc. Reconciliation of Current Assets and Current Liabilities to Net Working Capital (In millions of U.S. dollars) (Unaudited) As of June 30, 2025 March 31, 2025 December 31, 2024 Current assets $ 172.7 $ 167.9 $ 233.0 Less: Cash and cash equivalents and restricted cash 17.3 22.7 91.6 Net current assets 155.4 145.2 141.4 Current liabilities 139.1 111.3 140.1 Less: Current portion of long-term debt 4.5 4.3 - Less: Accrued interest 0.4 1.9 4.5 Less: Operating lease obligations 7.0 7.0 6.9 Less: Finance lease obligations 17.7 12.3 13.0 Net current liabilities 109.5 85.8 115.7 Net Working Capital $ 45.9 $ 59.4 $ 25.7 KLX Energy Services Holdings, Inc. Reconciliation of Net Debt(1) (In millions of U.S. dollars) (Unaudited) As of June 30, 2025 March 31, 2025 December 31, 2024 Total Debt $ 258.7 $ 261.0 $ 285.1 Cash and cash equivalents and restricted cash 17.3 22.7 91.6 Net Debt $ 241.4 $ 238.3 $ 193.5 (1) Net Debt is defined as total debt less cash and cash equivalents and restricted cash. View original content:https://www.prnewswire.com/news-releases/klx-energy-services-holdings-inc-reports-second-quarter-2025-results-302523588.html SOURCE KLX Energy Services Holdings, Inc.
Civitas Resources Reinstates Capital Return Program
Civitas Resources Reinstates Capital Return Program Board increases share repurchase authorization to $750 million; Company plans $250 million accelerated share repurchase DENVER, Aug. 06 /BusinessWire/ -- Civitas Resources, Inc. (NYSE:CIVI) ("Civitas" or the "Company") today announced that its Board of Directors has authorized reinstating a capital allocation strategy prioritizing both peer-leading return of capital to shareholders and ongoing debt reduction. Future free cash flow, after paying the Company's $2 per share annual base dividend, is expected to be allocated equally to share repurchases and debt reduction on an annual basis. In support of the capital return program, the Board increased the Company's share repurchase authorization to $750 million, which represents approximately 28% of the Company's current market capitalization. As part of the 2025 capital return, the Company plans to enter into an accelerated share repurchase ("ASR") agreement to repurchase $250 million of Civitas' equity. Inclusive of paid and planned dividends and repurchases for the year, the Company's capital return to shareholders in 2025 is estimated to be approximately 21% of its current market capitalization. Board Chair Howard A. Willard III commented, "We have taken decisive steps to strengthen Civitas, and following these important actions, we are reinstating an aggressive capital return program to take advantage of the compelling value we see in our equity today. Through the ASR program, we are targeting a rapid repurchase of a significant quantity of the Company's outstanding shares, and we are committed to returning capital to our shareholders moving forward, with an anticipated $500 million of remaining repurchase authorization following this initial ASR." Strategic steps taken to position Civitas for enhanced return of capital to shareholders include: Optimized 2025 free cash flow with a $150 million reduction in the Company's original capital expenditure plan Added 17 million barrels of oil hedges through the third quarter of 2026; Company is approximately 60% hedged on oil through the end of 2025 with a weighted average floor of $67 per barrel WTI Extended debt maturities and reduced revolving credit facility borrowings with $750 million issuance of unsecured Senior Notes due 2033 Implemented a $100 million cost optimization and efficiency project to sustainably lower capital and operating costs and improve margins, and Accelerated deleveraging with non-core DJ Basin asset divestments totaling $435 million, exceeding the Company's full-year target of $300 million With these accomplishments, net debt is anticipated to be $4.5 billion around year-end 2025, consistent with the Company's previously-communicated target. Under the ASR agreement, the Company is expected to commence repurchases promptly, with final settlement occurring within the third quarter. The Company will discuss its capital return program in more detail on its second quarter 2025 earnings webcast and conference call at 6:00 a.m. MT (8:00 a.m. ET) on Thursday, August 7, 2025. The webcast will be available on the Investor Relations section of the Company's website at www.civitasresources.com. The dial-in number for the call is 888-510-2535, with passcode 4872770. About Civitas Civitas Resources, Inc. is an independent exploration and production company focused on the acquisition, development and production of crude oil and liquids-rich natural gas from its premier assets in the Permian Basin in Texas and New Mexico and the DJ Basin in Colorado. Civitas' proven business model to maximize shareholder returns is focused on four key strategic pillars: generating significant free cash flow, maintaining a premier balance sheet, returning capital to shareholders, and demonstrating ESG leadership. Information Regarding Forward-Looking Statements Certain statements in this press release concerning Civitas' future expectations, beliefs, plans, objectives, financial conditions, assumptions, or future events or performance that are not historical facts are "forward-looking" statements based on assumptions currently believed to be valid. The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "probable," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "would," "potential," "may," "might," "anticipate," "likely," "plan," "positioned," "strategy," and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. Specific forward-looking statements included in this press release include statements regarding the Company's plans and commitments with respect to its capital return program and the ASR agreement. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve significant risks and uncertainties that could cause actual results to differ materially from those anticipated, including, but not limited to: future financial condition, results of operations, strategy and plans; declines or volatility in the prices we receive for our crude oil, natural gas, and NGLs; general economic conditions, whether internationally, nationally, or in the regional and local market areas in which we do business, including any future economic downturn, the impact of continued or further inflation, disruption in the financial markets, the imposition of tariffs or trade or other economic sanctions, political instability, and the availability of credit on acceptable terms; the effects of disruption of our operations or excess supply of crude oil and natural gas and other effects of world events, and actions taken by OPEC+ as it pertains to global supply and demand of, and prices for, crude oil, natural gas, and NGLs; political conditions in or affecting other producing countries, including conflicts or hostilities in or relating to the Middle East (including the current events involving Israel and Iran), South America, and Russia (including the current events involving Russia and Ukraine), and other sustained military campaigns or acts of terrorism or sabotage and the effects therefrom; our ability to identify, select, and consummate possible additional acquisition and disposition opportunities; the ability of our customers to meet their obligations to us; our access to capital on acceptable terms; our ability to generate sufficient cash flow from operations, borrowings, or other sources to enable us to fully develop our undeveloped acreage positions and to meet our capital allocation initiatives; the presence or recoverability of estimated crude oil and natural gas reserves and the actual future sales volume rates and associated costs; uncertainties associated with estimates of proved crude oil and natural gas reserves; changes in local, state, and federal laws, regulations or policies that may affect our business or our industry (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs); environmental, health, and safety risks; seasonal weather conditions as well as severe weather and other natural events caused by climate change; lease stipulations; drilling and operating risks, including the risks associated with the employment of horizontal drilling and completion techniques; our ability to acquire adequate supplies of water for drilling and completion operations; availability of oilfield equipment, services, and personnel; exploration and development risks; operational interruption of centralized crude oil and natural gas processing facilities; competition in the crude oil and natural gas industry; management's ability to execute our plans to meet our goals; our ability to attract and retain key members of our senior management and key technical employees; our ability to maintain effective internal controls; access to adequate gathering systems and pipeline take-away capacity; our ability to secure adequate processing capacity for natural gas we produce, to secure adequate transportation for crude oil, natural gas, and NGL we produce, and to sell the crude oil, natural gas, and NGL at market prices; costs and other risks associated with perfecting title for mineral rights in some of our properties; pandemics and other public health epidemics; and other economic, competitive, governmental, legislative, regulatory, geopolitical, and technological factors that may negatively impact our businesses, operations, or pricing. Additional information concerning other factors that could cause results to differ materially from those described above can be found under Item 1A. "Risk Factors" and "Management's Discussion and Analysis" sections in the Company's Annual Report on Form 10-K for the year ended December 31, 2024, subsequently filed Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other filings made with the Securities and Exchange Commission. All forward-looking statements speak only as of the date they are made and are based on information available at the time they were made. The Company assumes no obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. View source version on businesswire.com: https://www.businesswire.com/news/home/20250806181205/en/ back
Permian Resources Announces Strong Second Quarter 2025 Results and Increased Full Year Guidance
Permian Resources Announces Strong Second Quarter 2025 Results and Increased Full Year Guidance MIDLAND, Texas, Aug. 06 /BusinessWire/ -- Permian Resources Corporation ("Permian Resources" or the "Company") (NYSE:PR) today announced its second quarter 2025 financial and operational results and revised 2025 guidance. Recent Financial and Operational Highlights Reported total average production of 385.1 MBoe/d, including 176.5 MBbls/d of oil, 97.8 MBbls/d of NGLs and 664.7 MMcf/d of natural gas Announced cash capital expenditures of $505 million, cash provided by operating activities of $1.0 billion and adjusted free cash flow1 of $312 million Declared base dividend of $0.15 per share Increased mid-point of full year oil and total production guidance to 178.5 MBbls/d and 385.0 MBoe/d Closed the previously announced APA New Mexico bolt-on, adding ~13,000 net acres directly offset PR's core New Mexico operating areas Added ~1,300 net acres and ~80 net royalty acres through ~130 grassroots transactions for ~$10 million, demonstrating continued ground game success Maintained strong balance sheet with leverage1 of 1.0x after APA bolt-on closing Cash on hand of $451 million Undrawn revolver and total liquidity of ~$3 billion Lowered current income tax estimate, as a result of the One Big Beautiful Bill Act Expect <$5 million of current income tax in 2025 Anticipate <$50 million of cumulative current income tax in 2026 and 2027 Entered into multiple transportation and marketing agreements to improve all-in netbacks Repurchased $43 million of PR stock at an average price of $10.52 per share Received inaugural investment grade credit rating by Fitch (BBB-) Management Commentary "Our business continues to operate at a very high level, as evidenced by our second quarter results. Importantly, we continue to improve upon our low-cost leadership and high-quality asset base, making us well positioned to maximize shareholder returns in any commodity price environment," said Will Hickey, Co-CEO of Permian Resources. "During the quarter, we set new Company records for the fastest well drilled, the most feet drilled per day and the lowest completions cost per foot. These results demonstrate the efficiency gains we are achieving across both legacy and recently acquired assets." "We are excited to look back on the second quarter, which provided the first real opportunity to execute on our downturn playbook since the formation of Permian Resources. During the quarter, we executed on approximately $600 million in acquisitions and bought back shares at what we view to be attractive, below mid-cycle prices, both of which should help drive outsized returns for shareholders going forward," said James Walter, Co-CEO of Permian Resources. "Importantly, our rock-solid balance sheet and maximum liquidity will allow us to continue to play offense in the future should further volatility or macro uncertainty occur." Financial and Operational Results During the second quarter, average daily crude oil production was 176,533 barrels of oil per day ("Bbls/d"), a 1% increase compared to the prior quarter. Reported NGL and natural gas volumes were 97,804 Bbls/d and 664,686 Mcf/d, respectively. Total production was 385,118 barrels of oil equivalent per day ("Boe/d"). Production outperformance was driven by continued strong well results and closing of the APA bolt-on. Total cash capital expenditures ("capex") for the second quarter were $505 million. Realized prices for the quarter were $62.71 per barrel of oil, $17.75 per barrel of NGL and $0.53 per Mcf of natural gas. During the quarter, total controllable cash costs (LOE, GP&T and cash G&A) were $7.82 per Boe, in-line with the Company's full year guidance. Second quarter LOE was $5.36 per Boe, GP&T was $1.59 per Boe and cash G&A was $0.87 per Boe. For the second quarter, Permian Resources generated net cash provided by operating activities of $1.0 billion, adjusted operating cash flow1 of $817 million and adjusted free cash flow1 of $312 million. Adjusted diluted shares1 outstanding were 845.1 million for the three months ended June 30, 2025. Permian Resources' operations team continues to realize new benchmarks in the field. The Company's drilling team drilled five of the ten fastest wells in Company history during the second quarter, including its fastest Delaware Basin well to-date which achieved spud-to-TD in approximately six days on a 10,000-foot lateral. Permian Resources' completions team realized the lowest cost per foot in Company history, through maintaining high pump hours per day and optimizing the use of simul-fracs. Additionally, the Company's lease operating expense remained low during the second quarter, primarily driven by chemical and power optimization. Permian Resources continues to maintain a strong financial position and low leverage profile upon closing the APA bolt-on. At June 30, 2025, the Company had $451 million in cash on hand and no amounts drawn under its revolving credit facility. Total liquidity was approximately $3 billion. Net debt-to-LQA EBITDAX1 at June 30, 2025 was 1.0x. Subsequent to quarter-end, Permian Resources achieved its inaugural investment grade credit rating from Fitch Ratings, which upgraded the Company to BBB- with a stable outlook. "We are extremely proud to receive our inaugural investment grade credit rating. Maintaining a strong balance sheet and financial flexibility have played an integral role in the Company's success to-date and will continue to be a key focus going forward. We have comparable attributes to many of our investment grade peers and intend to achieve investment grade ratings from S&P and Moody's in the near-term," said Guy Oliphint, Chief Financial Officer. Executing on PR's Downturn Playbook Permian Resources has long held the belief that the thoughtful deployment of capital during periods of lower commodity prices can lead to outsized returns in this industry. Given its strong balance sheet and liquidity position, Permian Resources was able to immediately take advantage of the pricing dislocations during the second quarter. In April, the Company executed on its share repurchase program during market lows, buying back 4.1 million shares at a weighted average price of $10.52 per share, which represents a 23% discount to the Company's current share price as of August 5, 2025. The Company currently has a $1 billion share repurchase authorization in-place, with $957 million remaining. In early May, the Company announced the acquisition of APA Corporation's New Mexico assets, consisting of low breakeven inventory and low decline production within Permian Resources' core New Mexico operating areas. The Company closed the bolt-on acquisition on June 16, and integration is now complete. Additionally, Permian Resources continued to execute upon its ground game during the second quarter, adding approximately 1,300 net acres and 80 net royalty acres through approximately 130 grassroots leasing and working interest acquisitions. Importantly, the Company's balance sheet remains strong post-closing the APA bolt-on, making it well positioned to continue executing upon its downturn playbook, should future dislocations occur. The Company expects its year-end 2025 net debt-to-EBITDAX1 to be approximately 0.8x while having over $3 billion of liquidity, assuming $60 per barrel WTI for the remainder of the year. 2025 Operational Plan and Tax Update Permian Resources increased its 2025 oil production target by 6.0 MBbls/d to 178.5 MBbls/d and raised its total production target by 15.0 MBoe/d to 385.0 MBoe/d, each based on the mid-point of guidance. The increase in full year production guidance is driven by continued strong well results and the recently closed APA bolt-on acquisition. The Company is also adjusting its cash capital expenditures range to $1,920 - $2,020 million, as a result of the $20 million of incremental capex associated with the APA bolt-on during the second half of 2025, consistent with its previous disclosure. As a result of the recent passage of the One Big Beautiful Bill Act, Permian Resources has lowered its full year 2025 current income tax estimate to less than $5 million, compared to less than $10 million previously. In addition, the Company expects less than $50 million of cumulative current income tax in 2026 and 2027, assuming current strip pricing. (For a detailed table summarizing Permian Resources' revised 2025 operational and financial guidance, please see the Appendix of this press release.) Natural Gas and Crude Oil Marketing Update Permian Resources recently signed multiple transportation and marketing agreements to improve all-in netbacks and significantly increase the amount of natural gas and crude oil sold at key demand hubs. The Company entered into multiple firm natural gas transportation agreements, accessing markets in the Gulf Coast and Central / East Texas regions. As a result, Permian Resources expects its natural gas realizations in 2026 to increase by over $0.10 per Mcf, compared to 2024. The Company also entered into multiple crude oil purchase agreements. These agreements provide Permian Resources with increasing exposure to markets along the Gulf Coast, such as Houston WTI. These arrangements are expected to increase crude oil realizations by over $0.50 per Bbl in 2026, compared to 2024. "These recent agreements are consistent with our strategy of enhancing all-in netbacks, while maintaining a diversified marketing portfolio. Combined, we expect these announcements to provide an incremental $50 million of free cash flow in 2026 compared to 2024," said James Walter, Co-CEO. Hedge Position Update Permian Resources took advantage of higher prices in June to add incremental oil hedges at attractive prices. For the second half of 2025, the Company entered into 12,000 Bbls/d of incremental oil swaps at a weighted average fixed price of $70.18 per barrel. As a result, Permian Resources now has approximately 32% of its expected crude oil production hedged for the remainder of 2025 (using the mid-point of guidance) at a weighted average fixed price of $71.71 per Bbl. Permian Resources also added an incremental 12,000 Bbls/d of oil hedges during the full year 2026 at a weighted average fixed price of $66.12 per Bbl. Giving effect to these new hedges, Permian Resources has 29.5 MBbls/d of oil hedged for the full year 2026. In addition to the hedge positions discussed above, Permian Resources has certain other natural gas hedges, crude oil and natural gas basis swaps and crude oil roll differential swaps in-place. (For a summary table of the Company's derivative contracts as of July 31, 2025, please see the Appendix to this press release.) Shareholder Returns Permian Resources announced today that its Board of Directors declared the Company's third quarter 2025 base dividend of $0.15 per share of Class A common stock, or $0.60 per share on an annualized basis. The base dividend is payable on September 30, 2025 to shareholders of record as of September 16, 2025. The Company's base dividend represents an annualized yield of 4.4% as of August 5, 2025. Also during the quarter, the Company repurchased 4.1 million shares for $43 million at a weighted average price of $10.52 per share. Quarterly Report on Form 10-Q Permian Resources' financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, which is expected to be filed with the Securities and Exchange Commission ("SEC") on August 7, 2025. Conference Call and Webcast Permian Resources will host an investor conference call on Thursday, August 7, 2025 at 9:00 a.m. Central (10:00 a.m. Eastern) to discuss second quarter 2025 operating and financial results. Interested parties may join the call by visiting Permian Resources' website at www.permianres.com and clicking on the webcast link or by dialing (800) 549-8228 (Conference ID: 92721) at least 15 minutes prior to the start of the call. A replay of the call will be available on the Company's website or by phone at (888) 660-6264 (Passcode: 92721) for a 14-day period following the call. About Permian Resources Headquartered in Midland, Texas, Permian Resources is an independent oil and natural gas company focused on driving peer-leading returns through the acquisition, optimization and development of high-return oil and natural gas properties. The Company's assets are located in the Permian Basin, with a concentration in the core of the Delaware Basin. Through its position of approximately 470,000 net acres in West Texas and Southeast New Mexico, Permian Resources is the second largest Permian Basin pure-play E&P. For more information, please visit www.permianres.com. Cautionary Note Regarding Forward-Looking Statements The information in 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. All statements, other than statements of historical fact included in this press release, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "goal," "plan," "target" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Forward-looking statements may include statements about: volatility of oil, NGL and natural gas prices or a prolonged period of low oil, NGL or natural gas prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries ("OPEC"), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil, NGLs and natural gas; political and economic conditions and events in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America; our business strategy and future drilling plans; our reserves and our ability to replace the reserves we produce through drilling and property acquisitions; our drilling prospects, inventories, projects and programs; our financial strategy, return of capital program, leverage, liquidity and capital required for our development program; our realized oil, NGL and natural gas prices; the timing and amount of our future production of oil, NGLs and natural gas; our ability to identify, complete and effectively integrate acquisitions of properties, or businesses; our hedging strategy and results; our competition; our ability to obtain permits and governmental approvals; our compliance with government regulations, including those related to environmental, health and safety regulations and liabilities thereunder; our pending legal matters; the marketing and transportation of our oil, NGLs and natural gas; our leasehold or business acquisitions; cost of developing or operating our properties; our anticipated rate of return; general economic conditions; weather conditions in the areas where we operate; credit markets; our ability to make dividends, distributions and share repurchases; uncertainty regarding our future operating results; our plans, objectives, expectations and intentions contained in this press release that are not historical; and the other factors described in our most recent Annual Report on Form 10-K, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, NGLs and natural gas. Factors which could cause our actual results to differ materially from the results contemplated by forward-looking statements include, but are not limited to: commodity price volatility (including regional basis differentials); uncertainty inherent in estimating oil, NGL and natural gas reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production; geographic concentration of our operations; changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements; lack of availability of drilling and production equipment and services; lack of transportation and storage capacity as a result of oversupply, government regulations or other factors; risks related to acquisitions we may make from time to time, including the risk that we may fail to integrate such acquisitions on the terms and timing contemplated, or at all, and/or to realize our strategy and plans to achieve the expected benefits of such acquisitions; competition in the oil and natural gas industry for assets, materials, qualified personnel and capital; drilling and other operating risks; environmental and climate related risks, including seasonal weather conditions; changes to tax laws or interpretations thereof and the impact of such changes on us, including the One Big Beautiful Bill Act ("OBBBA"); regulatory changes, including those that may impact environmental, energy, and natural resources regulation; the possibility that the industry in which we operate may be subject to new or volatile local, state, and federal laws, regulations or policies that may affect our business (including additional taxes and changes in regulations and policies related to environmental, health, and safety, climate change, trade policy and tariffs) as a result of existing or developing political, environmental and social movements; restrictions on the use of water, including limits on the use of produced water and potential restrictions on the availability of water disposal facilities; availability of cash flow and access to capital; inflation; changes in our credit ratings or adverse changes in interest rates and associated changes in monetary policy; changes in the financial strength of counterparties to our credit agreement and hedging contracts; the timing of development expenditures; political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, including the conflict in Israel, Iran and their surrounding areas, the war in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage and the effects therefrom; changes in local, regional, national, and international economic conditions; security threats, including evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, third-party service provider failures, malicious software, data privacy breaches by employees, insiders or other with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and other risks described in our filings with the SEC. Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. Should one or more of the risks or uncertainties described in this press release occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this press release are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release. 1) Adjusted Operating Cash Flow, Adjusted Free Cash Flow, Adjusted Diluted Weighted Average Shares Outstanding and Net Debt-to-LQA EBITDAX (also referred to as "leverage" in this press release) are non-GAAP financial measures. See "Non-GAAP Financial Measures" included within the Appendix of this press release for related disclosures and reconciliations to the most directly comparable financial measures calculated and presented in accordance with GAAP. The Company does not provide guidance on the items used to reconcile between forecasted Net Debt-to-EBITDAX to forecasted long-term debt, net or forecasted net income due to the uncertainty regarding timing and estimates of certain items. Therefore, we cannot reconcile forecasted Net Debt-to-EBITDAX to long-term debt, net, or net income without unreasonable effort. Details of our revised 2025 operational and financial guidance are presented below: Reconciliation of cash, cash equivalents and restricted cash presented on the Consolidated Statements of Cash Flows for the periods presented: Non-GAAP Financial Measures In addition to disclosing financial results calculated in accordance with U.S. generally accepted accounting principles ("GAAP"), our earnings release contains non-GAAP financial measures as described below. Adjusted EBITDAX Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income attributable to Class A Common Stock before net income attributable to noncontrolling interest, interest expense, income taxes, depreciation, depletion and amortization, impairment and abandonment expense, non-cash gains or losses on derivatives, stock-based compensation, exploration and other expenses, merger and integration expense, gain/loss from the sale of long-lived assets and other non-recurring items. Adjusted EBITDAX is not a measure of net income as determined by GAAP. Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare 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 in arriving at Adjusted EBITDAX 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 EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. The following table presents a reconciliation of Adjusted EBITDAX to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP: Net Debt-to-LQA EBITDAX Net debt-to-LQA EBITDAX, also referred to as leverage, is a non-GAAP financial measure. We define net debt as total debt, net, plus unamortized debt discount, premium and debt issuance costs on our senior notes minus cash and cash equivalents. We define net debt-to-LQA EBITDAX as net debt (defined above) divided by Adjusted EBITDAX (defined and reconciled in the section above) for the three months ended June 30, 2025, on an annualized basis. We refer to this metric to show trends that investors may find useful in understanding our ability to service our debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry. The following table presents a reconciliation of net debt to total debt, net and the calculation of net debt-to-LQA EBITDAX for the period presented: Adjusted Shares Adjusted basic and diluted weighted average shares outstanding ("Adjusted Basic and Diluted Shares") are non-GAAP financial measures defined as basic and diluted weighted average shares outstanding adjusted to reflect the weighted average shares of our Class C Common Stock outstanding during the period. Our Adjusted Basic and Diluted Shares provide a comparable per share measurement when presenting results such as adjusted free cash flow and adjusted net income that include the interests of both net income attributable to Class A Common Stock and the net income attributable to our noncontrolling interest. Adjusted Basic and Diluted Shares are used in calculating several metrics that we use as supplemental financial measurements in the evaluation of our business. The following table presents a reconciliation of Adjusted Basic and Diluted Shares to basic and diluted weighted average shares outstanding, which are the most directly comparable financial measure calculated and presented in accordance with GAAP: Adjusted Operating Cash Flow and Adjusted Free Cash Flow Adjusted operating cash flow and adjusted free cash flow are supplemental non-GAAP financial measures used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted operating cash flow as net cash provided by operating activities adjusted to remove changes in working capital, merger and integration and other non-recurring charges, and estimated tax distributions to our non-controlling interest owners. Adjusted operating cash flows is reduced by total cash capital expenditures to arrive at adjusted free cash flows. Our management believes adjusted operating cash flow and adjusted free cash flow are useful indicators of the Company's ability to internally fund its future exploration and development activities, to service its existing level of indebtedness or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities, its merger and integration and other non-recurring costs or estimated tax distributions to noncontrolling interest owners after funding its capital expenditures paid for the period. The Company believes that these measures, as so adjusted, present meaningful indicators of the Company's actual sources and uses of capital associated with its operations conducted during the applicable period. Our computation of adjusted operating cash flow and adjusted free cash flow may not be comparable to other similarly titled measures of other companies. Adjusted operating cash flow and adjusted free cash flow should not be considered as alternatives to, or more meaningful than, net cash provided by operating activities as determined in accordance with GAAP or as indicators of our operating performance or liquidity. Adjusted operating cash flow and adjusted free cash flow are not financial measures that are determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of adjusted operating cash flow and adjusted free cash flow to net cash provided by operating activities, which is the most directly comparable financial measure calculated and presented in accordance with GAAP: Adjusted Net Income Adjusted net income is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted net income as net income attributable to Class A Common Stock plus net income attributable to noncontrolling interest adjusted for non-cash gains or losses on derivatives, merger and integration expense, other nonrecurring charges, impairment and abandonment expense, gain/loss from the sale of long-lived assets and the related income tax adjustments for these items. Adjusted net income is not a measure of net income as determined by GAAP. Our management believes adjusted net income is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers by excluding certain non-cash items that can vary significantly. Adjusted net income should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Our presentation of adjusted net income should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. Our computations of adjusted net income may not be comparable to other similarly titled measures of other companies. Adjusted net income is not a financial measure that is determined in accordance with GAAP. Accordingly, the following table presents a reconciliation of adjusted net income to net income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP: The following table summarizes the approximate volumes and average contract prices of the hedge contracts the Company had in place as of July 31, 2025: View source version on businesswire.com: https://www.businesswire.com/news/home/20250806751812/en/ back
Energy Transfer Reports Second Quarter 2025 Results
Energy Transfer Reports Second Quarter 2025 Results DALLAS, Aug. 06 /BusinessWire/ -- Energy Transfer LP (NYSE:ET) ("Energy Transfer" or the "Partnership") today reported financial results for the quarter ended June 30, 2025. Energy Transfer reported net income attributable to partners for the three months ended June 30, 2025 of $1.16 billion compared to $1.31 billion for the three months ended June 30, 2024. For the three months ended June 30, 2025, net income per common unit (basic) was $0.32. Adjusted EBITDA for the three months ended June 30, 2025 was $3.87 billion compared to $3.76 billion for the three months ended June 30, 2024. Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2025 was $1.96 billion compared to $2.04 billion for the three months ended June 30, 2024. Growth capital expenditures in the second quarter of 2025 were $1.04 billion, while maintenance capital expenditures were $253 million. Operational Highlights Energy Transfer's volumes continued to grow during the second quarter of 2025 compared to the second quarter of 2024. Interstate natural gas transportation volumes were up 11%. Midstream gathered volumes were up 10%, setting a new Partnership record. Crude oil transportation volumes were up 9%, setting a new Partnership record. Intrastate natural gas transportation volumes were up 8%. NGL transportation volumes were up 4%, setting a new Partnership record. NGL and refined products terminal volumes were up 3%, setting a new Partnership record. NGL fractionated volumes were up 5%. NGL exports were up 5%, setting a new Partnership record. In the second quarter of 2025, Energy Transfer placed its 200 MMcf/d Lenorah II Processing plant in the Midland Basin into service; the plant is currently running at full capacity. Energy Transfer recently placed its Nederland Flexport NGL Export Expansion Project into ethane and propane service and expects to begin ethylene service in the fourth quarter of this year. The project is expected to add up to 250,000 Bbls/d of total NGL export capacity at the Partnership's Nederland terminal. Energy Transfer also recently placed the 200 MMcf/d Badger Processing Plant into service. This project involved the relocation of a previously idle plant to the Delaware Basin. Energy Transfer also recently commissioned the second of eight, 10-megawatt natural gas-fired electric generation facilities in West Texas. Two more of these facilities are expected to be placed into service in 2025, with the remainder expected in service in 2026. Strategic Highlights Energy Transfer announced today a 1.5 Bcf/d expansion of its Transwestern Pipeline. Transwestern's Desert Southwest Pipeline expansion will include a 516-mile, 42-inch natural gas pipeline that will connect the Permian Basin with markets in Arizona, New Mexico, and Texas, and is expected to be in service by the fourth quarter of 2029. The project is expected to cost approximately $5.3 billion, including $0.6 billion of Allowance for Funds Used During Construction ("AFUDC"), and is supported by significant, long-term commitments with investment grade counterparties. Energy Transfer recently reached FID on Phase II of its Hugh Brinson Pipeline, which will include the addition of compression. Upon completion, this bi-directional pipeline will have the ability to transport approximately 2.2 Bcf/d from west to east and also transport approximately 1 Bcf/d from east to west. Energy Transfer also recently reached FID on the construction of a new storage cavern at its Bethel natural gas storage facility. This project will double Energy Transfer's natural gas working storage capacity at the facility to over 12 Bcf. Southeast Supply Header, LLC recently approved an expansion to its SESH pipeline to serve growing power generation needs. In June 2025, Energy Transfer signed an incremental Sale and Purchase Agreement ("SPA") with Chevron U.S.A. Inc. ("Chevron") for additional LNG supply from its proposed Lake Charles LNG export facility. The 20-year agreement for 1.0 million tonnes per annum ("mtpa") increases Chevron's total contracted volume from Energy Transfer LNG to 3.0 mtpa, following the initial 2.0 mtpa agreement signed in December 2024. In May 2025, Energy Transfer entered into a 20-year LNG SPA with Kyushu Electric Power Company, Inc. related to the Lake Charles LNG project, to supply 1.0 mtpa of LNG. In April 2025, Energy Transfer entered into a Heads of Agreement with MidOcean Energy ("MidOcean") for the joint development of the Lake Charles LNG project, under which MidOcean would commit to fund 30% of the construction costs and be entitled to 30% of the LNG production. Financial Highlights In July 2025, Energy Transfer announced a quarterly cash distribution of $0.33 per common unit ($1.32 annualized) for the quarter ended June 30, 2025, which is an increase of more than 3% compared to the second quarter of 2024. In May 2025, the Partnership redeemed $500 million aggregate principal amount of 6.75% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units using cash on hand and commercial paper borrowings. As of June 30, 2025, the Partnership's revolving credit facility had an aggregate $2.51 billion of available borrowing capacity. The Partnership now expects to be at or slightly below the lower end of its previously stated Adjusted EBITDA guidance range of $16.1 billion to $16.5 billion. The Partnership continues to expect its 2025 growth capital expenditures to be approximately $5 billion. Energy Transfer benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership's multiple segments generate high-quality, balanced earnings with no single business segment contributing more than one-third of the Partnership's consolidated Adjusted EBITDA for the three months ended June 30, 2025. In addition, Energy Transfer generates approximately 40% of its Adjusted EBITDA from natural gas-related assets. The vast majority of the Partnership's segment margins are fee-based and therefore have limited commodity price sensitivity. Conference call information: The Partnership has scheduled a conference call for 3:30 p.m. Central Time/4:30 p.m. Eastern Time on Wednesday, August 6, 2025 to discuss its second quarter 2025 results and provide an update on the Partnership. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfercom and will also be available for replay on the Partnership's website for a limited time. 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. Sunoco LP (NYSE:SUN) is a leading energy infrastructure and fuel distribution master limited partnership operating in over 40 U.S. states, Puerto Rico, Europe, and Mexico. SUN's midstream operations include an extensive network of approximately 14,000 miles of pipeline and over 100 terminals. This critical infrastructure complements SUN's fuel distribution operations, which serve approximately 7,400 Sunoco and partner branded locations and additional independent dealers and commercial customers. SUN's general partner is owned by Energy Transfer LP (NYSE:ET). For more information, visit the Sunoco LP website at www.sunocolp.com. USA Compression Partners, LP (NYSE:USAC) is one of the nation's largest independent providers of natural gas compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers, and transporters of natural gas and crude oil. USAC focuses on providing midstream natural gas compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities, and transportation applications. For more information, visit the USAC website at www.usacompression.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 Adjusted EBITDA, and impact current projections, including capital expenditures, 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. The information contained in this press release is available on our website at www.energytransfer.com. The following analysis of segment operating results includes a measure of segment margin. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented. Transported volumes of gas on our Texas intrastate pipelines increased primarily due to more third-party transportation. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines' own accounts and the optimization of any unused capacity. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impact of the following: a decrease of $45 million in realized natural gas sales and other primarily due to lower optimization volumes with shifts to long-term third-party contracts from the Permian and narrower price spreads; a decrease of $11 million in transportation fees primarily due to the recovery in the prior period of certain disputed fees on our Texas system; and a decrease of $2 million in storage margin primarily due to lower storage optimization; partially offset by a decrease of $5 million in operating expenses primarily due to a decrease in maintenance projects costs; and an increase of $4 million in retained fuel margin primarily due to higher gas prices. Transported volumes increased primarily due to more capacity sold and higher utilization on several of our major pipeline systems due to increased demand. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impact of the following: an increase of $70 million in segment margin primarily due to a $35 million negative impact in the prior period related to the conclusion of a rate case on our Panhandle system, a $33 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and a $4 million increase due to higher storage and liquids revenue; and an increase of $12 million in Adjusted EBITDA related to unconsolidated affiliates due to a $6 million increase from our Citrus joint venture, a $4 million increase from our Midcontinent Express Pipeline joint venture and a $2 million increase from our Southeast Supply Header pipeline joint venture; partially offset by an increase of $11 million in operating expenses primarily due to an increase in volume-driven expenses. Gathered volumes increased primarily due to newly acquired assets, as well as additional and upgraded plants in the Permian region, partially offset by lower dry gas gathering in the Northeast and Ark-La-Tex regions. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following: an increase of $176 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region; and an increase of $11 million in segment margin due to higher natural gas prices of $38 million, partially offset by lower NGL prices of $27 million; partially offset by a decrease of $13 million in segment margin due to lower dry gas volumes in the Northeast and Ark-La-Tex regions; an increase of $95 million in operating expenses primarily due to recently acquired assets and assets placed in service as well as higher employee costs; and an increase of $4 million in selling, general and administrative expenses due to an adjustment to the workers' compensation reserve in the prior period and higher corporate allocations. NGL transportation volumes increased primarily due to higher volumes from the Permian region. The increase in transportation volumes also led to higher fractionated volumes at our Mont Belvieu NGL Complex. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impact of the following: a decrease of $78 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to lower gains from the optimization of hedged NGL and refined product inventories; and an increase of $7 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets; partially offset by an increase of $33 million in transportation margin primarily due to higher throughput and contractual rate escalations on our Mariner East and our Gulf Coast pipeline systems; and an increase of $12 million in fractionators and refinery services margin primarily due to higher throughput. Crude oil transportation volumes were higher due to continued growth on our gathering systems and from assets contributed upon the recent formation of the ET-S Permian joint venture with Sunoco LP, partially offset by lower volumes on our Bakken Pipeline. Crude terminal volumes were lower primarily due to lower volumes received from our Bakken Pipeline system. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impact of the following: a decrease of $46 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) due to decreased transportation revenue, primarily from our Bakken Pipeline system, partially offset by increases from assets contributed upon the formation of the ET-S Permian joint venture; an increase of $21 million in operating expenses primarily due to a $10 million increase from assets contributed upon the formation of the ET-S Permian joint venture, a $6 million increase in employee costs and a $5 million increase in expense projects; and an increase of $2 million in selling, general and administrative expenses primarily due to costs associated with the ET-S Permian joint venture. The investment in Sunoco LP segment reflects the consolidated results of Sunoco LP. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impact of the following: an increase of $12 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to the acquisition of NuStar, which was acquired in May 2024 and therefore is only reflected for two months in the prior period. This increase was partially offset by a decrease of $50 million from Sunoco LP's deconsolidation of certain of NuStar's assets in connection with the formation of ET-S Permian effective July 1, 2024, as well as a $29 million decrease in fuel profit due to lower profit per gallon; an increase of $48 million in Adjusted EBITDA related to unconsolidated affiliates due to the formation of ET-S Permian; and a decrease of $85 million in selling, general and administrative expenses, excluding non-cash compensation expense, primarily related to one-time NuStar acquisition costs in 2024; partially offset by an increase of $13 million in operating expenses due to increased costs from the acquisition of NuStar, which was acquired in May 2024 and therefore is only reflected for two months in the prior period. This increase was partially offset by a decrease of $6 million from Sunoco LP's deconsolidation of certain of NuStar's assets in connection with the formation of ET-S Permian effective July 1, 2024. The investment in USAC segment reflects the consolidated results of USAC. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impact of the following: an increase of $10 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression services and higher market-based rates on newly deployed and redeployed compression units; partially offset by an increase of $4 million in operating expenses primarily due to an increase in employee costs associated with increased revenue-generating horsepower. Segment Adjusted EBITDA. For the three months ended June 30, 2025 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impact of the following: a decrease of $48 million due to the intersegment elimination of Sunoco LP's 32.5% share of ET-S Permian, which is consolidated in our crude oil transportation and services segment and also reflected as an unconsolidated affiliate in our investment in Sunoco LP segment; partially offset by an increase of $9 million in our natural gas marketing business; and an increase of $4 million from our compressor packaging business. View source version on businesswire.com: https://www.businesswire.com/news/home/20250806086773/en/ back
Amplify Energy Announces Strategic Initiatives Update, Second Quarter 2025 Results, and Updated Full-Year 2025 Guidance
Amplify Energy Announces Strategic Initiatives Update, Second Quarter 2025 Results, and Updated Full-Year 2025 Guidance HOUSTON, Aug. 06, 2025 (GLOBE NEWSWIRE) -- Amplify Energy Corp. (NYSE: AMPY) ("Amplify," the "Company," "us," or "our") announced today an update on its strategic initiatives, operating and financial results for the second quarter of 2025, and updated full-year 2025 guidance. Strategic Initiatives Update As previously announced, Amplify remains committed to simplifying its portfolio, focusing capital and management resources on the Company's most attractive investment opportunities and creating value for shareholders. Consistent with this strategic shift, Amplify intends to become more oil-weighted, reduce debt, lower operating costs, and streamline the organization. To accomplish these objectives, the Company has undertaken several initiatives, including: Engaged TenOaks Energy Advisors to explore market interest for the complete divestiture of Amplify's assets in East Texas and Oklahoma. TenOaks has opened a data room and plans to solicit offers for the assets later in the third quarter.Divested its non-operated assets in the Eagle Ford for $23 million, subject to post-closing adjustments. The transaction closed on July 1, 2025, with an effective date of June 15, 2025.Implemented changes to the Board of Directors and senior management: Appointed Clint Coghill, Amplify's largest shareholder, to its Board of Directors on May 16, 2025Reduced the size of the Board from eight to five directors at the annual meeting held on June 13, 2025Promoted Dan Furbee to Chief Executive Officer and Jim Frew to President and Chief Financial Officer, effective July 22, 2025 Dan Furbee, the Company's Chief Executive Officer, stated, "We are off to a strong start implementing various strategic initiatives, and we are optimistic that these initiatives will yield positive results for our stakeholders. While substantial efforts lie ahead, we believe that monetizing assets to reduce our operating footprint, paying down debt, focusing our resources on Beta and Bairoil, and streamlining the organization, best position the Company to generate significant value for our shareholders." Key Highlights During the second quarter of 2025, the Company: Achieved average total production of 19.1 MBoepd, an increase of approximately 7% compared to the prior quarterGenerated net cash provided by operating activities of $23.7 million and net income of $6.4 millionDelivered Adjusted EBITDA of $19.0 million and an Adjusted Net Loss of $2.3 millionAt Beta, completed the C54 well and brought it online in late-April The C54 has cumulative gross production of 90,000 barrels of oil (an average gross production of approximately 920 Bopd), and the well is currently producing approximately 850 gross Bopd. At current pricing, Amplify expects the well to pay out in approximately eight months with an IRR greater than 100%. In East Texas: Completed and brought online four gross (one net) non-operated wells (i.e., two Haynesville completions and two Cotton Valley completions). The four wells are currently producing 13 Mmcfe/d net to Amplify's interest. At current gas prices, Amplify expects these wells to pay out in less than 18 months with IRR's greater than 45%.Sold additional undeveloped Haynesville interests, generating $1.5 million in proceeds, in May 2025. Over the course of the last seven months, Amplify has generated proceeds of $9.2 million related to Haynesville acreage transactions, while retaining a 10% working interest in two newly created areas of mutual interest ("AMI") in the Haynesville play of East Texas. Generated $1.1 million of Adjusted EBITDA at Magnify Energy Services, Amplify's wholly owned subsidiary ("Magnify")On May 29, 2025, the Company completed its semi-annual borrowing base redetermination1 As of June 30, 2025, Amplify had $130.0 million outstanding under the revolving credit facility. Net debt to Last Twelve Months ("LTM") Adjusted EBITDA of 1.5x2. (1) On May 29, 2025, semi-annual redetermination was affirmed at $145 million borrowing base. Subsequent to the Eagle Ford divesture, the borrowing base was reduced to $135 million. (2) Net debt as of June 30, 2025, consisting of $130 MM outstanding under its revolving credit facility with ~$0 MM of cash and cash equivalents, and LTM Adjusted EBITDA as of the second quarter of 2025. Mr. Furbee commented, "Despite a lower commodity price environment, Amplify was able to generate strong second quarter operating and financial results. Recently drilled wells at Beta and East Texas came on-line in the second quarter and early third quarter respectively, and we are very pleased with the results thus far. The C54 well, drilled from the Eureka platform, has the highest initial production rates of the four wells we have brought on-line since we started the Beta development program early last year. The non-operated wells in East Texas, drilled by our partners, are exceeding our forecasts. These capital investments will generate attractive returns for our investors and give us confidence in our future development programs." Mr. Furbee continued, "Over the past few quarters, Amplify has closed several transactions in East Texas and the Eagle Ford. The proceeds from those sales have allowed us to pay down debt and have given us the flexibility to ramp up development at Beta. Successfully monetizing our East Texas and Oklahoma assets would allow us to further accelerate this plan." Key Financial Results During the second quarter of 2025, the Company reported net income of approximately $6.4 million compared to a net loss of $5.9 million in the prior quarter. The increase was primarily attributable to a gain on commodity derivatives. Excluding the impact of the derivatives gain, and additional other one-time impacts, Amplify generated an Adjusted Net Loss of $2.3 million in the second quarter of 2025. Second quarter 2025 Adjusted EBITDA was $19.0 million, which was comparable to the prior quarter despite significantly lower commodity prices. Free cash flow was negative $10.1 million for the second quarter, which was in-line with expectations, due to higher capital investments in the first half of the year. Amplify intends to invest approximately 95% of its 2025 capital in the first three quarters of the year. Revolving Credit Facility and Liquidity Update On May 29, 2025, the Company completed its semi-annual borrowing base redetermination, which was reaffirmed at $145.0 million. Following the Eagle Ford divestiture, which was announced on July 1, the borrowing base was reduced to $135.0 million. As of June 30, 2025, Amplify had total debt of $130.0 million outstanding under its revolving credit facility. Net debt to LTM Adjusted EBITDA was 1.5x (net debt as of June 30, 2025 and 2Q25 LTM Adjusted EBITDA). The next borrowing base redetermination is expected in the fourth quarter of 2025. Corporate Production and Pricing During the second quarter of 2025, average daily production was approximately 19.1 Mboepd, an increase of 1.2 Mboepd from the prior quarter. All five assets increased production compared to the prior quarter including at East Texas where our new non-operated wells were delayed coming online approximately six weeks. Despite a June 15th effective date for the sale of our Eagle Ford assets (i.e. prior to the end of the second quarter), production was up compared to the prior quarter due to new wells coming on-line. At Bairoil, production increased slightly even though the field was shut-in for seven days for our planned plant turnaround. At Beta, production increased as previously shut-in wells were returned to production and the recently drilled C54 well was brought online in late-April. The Company's product mix for the quarter was 48% crude oil, 16% NGLs, and 36% natural gas. Amplify has steadily increased its oil weighting consistent with our strategy. In the second quarter of 2024, crude oil production, as a percentage of total production, was 41% compared to 48% in the second quarter of 2025. Total oil, natural gas and NGL revenues for the second quarter of 2025 were approximately $66.8 million, before the impact of derivatives. Crude oil, NGL and natural gas prices were all lower in the second quarter compared to the first quarter. The Company realized a net gain on commodity derivatives of $4.8 million during the second quarter. The following table sets forth information regarding average realized sales prices for the periods indicated: Costs and Expenses Lease operating expenses in the second quarter of 2025 were approximately $38.6 million, a $1.2 million increase compared to the prior quarter and in-line with internal projections. Lease operating expenses were $22.20 per Boe, a decrease of approximately 5%, compared to $23.28 per Boe in the prior quarter. Lease operating expenses are expected to decrease in the second half of 2025 after cost savings projects are completed at Bairoil, and fewer expense workovers are conducted later in the year. With the sale of the Eagle Ford assets and the planned reduction in expenditures in the second half of 2025, we are guiding lease operating expenses to a midpoint of approximately $137 million. Lease operating expenses do not reflect $1.1 million of Adjusted EBITDA generated by Magnify in the second quarter. Severance and ad valorem taxes in the second quarter were approximately $4.3 million, a decrease of $0.1 million compared to $4.4 million in the prior quarter. Severance and ad valorem taxes as a percentage of revenue were approximately 6.4% in the second quarter. The Company anticipates that taxes as a percentage of revenue will remain within its previously announced guidance range for 2025. Amplify incurred $4.7 million, or $2.71 per Boe, of gathering, processing and transportation expenses in the second quarter, compared to $4.3 million, or $2.67 per Boe, in the prior quarter. Cash G&A expenses in the second quarter were $6.8 million, down 7% compared to the first quarter of 2025, and in-line with expectations. Depreciation, depletion, and amortization expense in the second quarter totaled $9.8 million, or $5.61 per Boe, compared to $8.5 million, or $5.29 per Boe, in the prior quarter. Net interest expense was $3.6 million in the second quarter, an increase of $0.1 million compared to $3.5 million in the prior quarter. Amplify recorded a $0.5 million current income tax expense for the second quarter of 2025. Capital Investment Update Cash capital investment during the second quarter of 2025 was approximately $25.5 million. During the second quarter, the Company's capital allocation was approximately 52% for development drilling, recompletions and facility projects at Beta, and approximately 25% for non-operated development projects in East Texas and the Eagle Ford, with the remainder distributed across the Company's other assets. As previously stated, Amplify intends to invest approximately 95% of its 2025 capital by the end of third quarter 2025. Capital investments in the second half of 2025 (estimated between $21 million to $31 million) are forecasted to drop significantly compared to total capital investments of $48.6 million in the first half of 2025. The decrease is due to the completion of non-operated development drilling investments in East Texas and Eagle Ford, the front loading of investments in the Beta facility projects, and the Bairoil plant turnaround upgrades already completed. The following table details Amplify's capital invested during the second quarter of 2025: 2025 Operations & Development Plan The sale of our Eagle Ford assets and the continued outperformance of the three Beta D-Sand wells completed over the past 12 months have generated additional liquidity. Consequently, we are revising guidance to reflect increased Beta development resulting from the drilling and completion of at least two wells in the second half of 2025. Amplify is currently drilling the C08 well from the Eureka platform, and we anticipate completing the well in late August. The C08 well is a direct offset to the C54 and C59 wells, which have both significantly outperformed the Beta type curve. The C59 well has been online for approximately 10 months and has cumulative production of 130 Mbo and is currently producing approximately 550 gross Bopd. The C54 well has been online for approximately 100 days, has cumulative production of 90 Mbo and is currently producing approximately 850 gross Bopd. Both wells are projected to generate greater than 100% IRRs. Aside from drilling capital at Beta, Amplify has been investing in facility and equipment upgrades needed for the potential acceleration of the Beta development program. The projects include pipeline and pump upgrades to handle additional produced oil and water volumes, drilling rig upgrades for increased drilling activity, and power upgrades for future power demands. In the first half of 2025, Amplify invested approximately $6.2 million in East Texas. The majority of this investment was focused on non-operated development drilling. Early in the third quarter, Amplify's partners brought online two Haynesville and two Cotton Valley completions which are currently producing 13 Mmcfe/d net to Amplify's interest. At current gas prices, Amplify expects these four wells to pay out in less than 18 months with IRR's greater than 45%. Furthermore, the Company now maintains several AMIs with counterparties in the East Texas region that provide the opportunity for participation in additional Haynesville and Cotton Valley development. Operators in the area are taking advantage of strong natural gas prices and favorable economics, and the Company anticipates more activity in this area. At Bairoil, in addition to enhancing our water-alternating-gas injection performance, the Company has been investing in facility projects at our CO2 gas plant intended to significantly reduce power usage and costs (the largest component of our lease operating expenses at Bairoil). The cost reductions are projected to take effect later in the third quarter and will help offset the power cost increases resulting from higher electric utility rates in Wyoming. Additionally, at Bairoil, the Company obtained certification under the EOR Operations Management Plan in accordance with the CSA ANSI/ISO Standard. This certification allows portions of CO2 utilized in the field to qualify for Section 45Q tax credits and could enable Amplify to create additional value from the asset through numerous opportunities that the Company is currently evaluating. Updated Full-Year 2025 Guidance Based on the recently announced sale of the Eagle Ford assets and the additional development at Beta late in the year, Amplify is providing updated guidance for 2025. The following guidance is subject to the cautionary statements and limitations described under the "Forward-Looking Statements" caption at the end of this press release. Amplify's updated 2025 guidance is based on its current expectations regarding capital investment and full-year 2025 commodity prices for crude oil of approximately $65.00/Bbl (WTI) and natural gas of $3.50/MMBtu (Henry Hub), and on the assumption that market demand and prices for oil and natural gas will continue at levels that allow for economic production of these products. A summary of the guidance is presented below: (1) Includes production, ad valorem and franchise taxes(2) Refer to "Use of Non-GAAP Financial Measures" for Amplify's definition and use of cash G&A, Adjusted EBITDA and free cash flow, non-GAAP measures (cash income taxes, which are not included in free cash flow, are expected to range between $0 - $1 million for the year)(3) Amplify believes that a quantitative reconciliation of such forward-looking information to the most comparable financial measure calculated and presented in accordance with GAAP cannot be made available without unreasonable efforts. A reconciliation of these non-GAAP financial measures would require Amplify to predict the timing and likelihood of future transactions and other items that are difficult to accurately predict. Neither of these forward-looking measures, nor their probable significance, can be quantified with a reasonable degree of accuracy. Accordingly, a reconciliation of the most directly comparable forward-looking GAAP measures is not provided. Hedging Amplify maintains a robust hedge book to support its cash flow profile and provide downside protection in weak commodity price environments. Recently, the Company added to its hedge position, further protecting future cash flows. Amplify executed crude oil swaps covering portions of 2026 and 2027 at a weighted average price of $62.79. The Company also added natural gas swaps covering the portions of 2027 and 2028 at an average price of $3.86 per MMBtu, and costless collars for portions of 2027 and 2028 with weighted average floors of $3.50 per MMBtu and weighted average ceilings of $4.52 per MMBtu. The following table reflects the hedged volumes under Amplify's commodity derivative contracts and the average fixed floor and ceiling prices at which production is hedged for July 2025 through December 2028, as of August 6, 2025: Amplify has posted an updated investor presentation containing additional hedging information on its website, www.amplifyenergy.com, under the Investor Relations section. Quarterly Report on Form 10-Q Amplify's financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the quarter ended June 30, 2025, which Amplify expects to file with the SEC on August 6, 2025. About Amplify Energy Amplify Energy Corp. is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Amplify's operations are focused in Oklahoma, the Rockies (Bairoil), federal waters offshore Southern California (Beta), and East Texas / North Louisiana. For more information, visit www.amplifyenergy.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. All statements, other than statements of historical fact, included in this press release that address activities, events or developments that the Company expects, believes, or anticipates will or may occur in the future are forward-looking statements. Terminology such as "may," "will," "would," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "outlook," "continue," the negative of such terms or other comparable terminology are intended to identify forward-looking statements. These statements include, but are not limited to, statements about the anticipated divestiture of Amplify's assets in East Texas and Oklahoma, the impact of these potential sales of assets on the Company's business and future financial and operating results, the expected use of proceeds of these potential sales of assets, and the Company's expectations of plans, goals, strategies (including measures to implement strategies), objectives and anticipated results with respect thereto. These statements address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as projections of results of operations, plans for growth, goals, future capital expenditures, competitive strengths, references to future intentions and other such references. These forward-looking statements involve risks and uncertainties and other factors that could cause the Company's actual results or financial condition to differ materially from those expressed or implied by forward-looking statements. These include risks and uncertainties relating to, among other things: the ability to complete the potential sale of the Company's assets in East Texas and Oklahoma on favorable terms, or at all; the Company's evaluation and implementation of strategic alternatives; risks related to the redetermination of the borrowing base under the Company's revolving credit facility; the Company's ability to satisfy debt obligations; the Company's need to make accretive acquisitions or substantial capital expenditures to maintain its declining asset base, including the existence of unanticipated liabilities or problems relating to acquired or divested business or properties; volatility in the prices for oil, natural gas and NGLs; the Company's ability to access funds on acceptable terms, if at all, because of the terms and conditions governing the Company's indebtedness, including financial covenants; general political and economic conditions, globally and in the jurisdictions in which we operate, including the Russian invasion of Ukraine, and ongoing conflicts in the Middle East, trade wars and the potential destabilizing effect such conflicts may pose for the global oil and natural gas markets; expectations regarding general economic conditions, including inflation; and the impact of local, state and federal governmental regulations, including those related to climate change and hydraulic fracturing, and potential changes in these regulations. Please read the Company's filings with the SEC, including "Risk Factors" in the Company's Annual Report on Form 10-K, and if applicable, the Company's Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, which are available on the Company's Investor Relations website at https://www.amplifyenergy.com/investor-relations/sec-filings/default.aspx or on the SEC's website at http://www.sec.gov, for a discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements. 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 in this press release are qualified in their entirety by these cautionary statements. Except as required by law, the Company undertakes no obligation and does not intend to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise. Use of Non-GAAP Financial Measures This press release and accompanying schedules include the non-GAAP financial measures of Adjusted EBITDA, Adjusted Net Income (Loss), free cash flow, net debt, and cash G&A. The accompanying schedules provide a reconciliation of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP. Amplify's non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities, standardized measure of discounted future net cash flows, or any other measure of financial performance calculated and presented in accordance with GAAP. Amplify's non-GAAP financial measures may not be comparable to similarly titled measures of other companies because they may not calculate such measures in the same manner as Amplify does. Adjusted EBITDA. Amplify defines Adjusted EBITDA as net income (loss) plus Interest expense, net; Income tax expense (benefit); DD&A; Accretion of AROs; Loss or (gain) on commodity derivative instruments; Cash settlements received or (paid) on expired commodity derivative instruments; Amortization of gain associated with terminated commodity derivatives; Losses or (gains) on sale of properties; Share-based compensation expenses; Exploration costs; Acquisition and divestiture related costs; Loss on settlement of AROs; Bad debt expense; and Pipeline incident loss. Adjusted EBITDA is commonly used as a supplemental financial measure by management and external users of Amplify's financial statements, such as investors, research analysts and rating agencies, to assess: (1) its operating performance as compared to other companies in Amplify's industry without regard to financing methods, capital structures or historical cost basis; (2) the ability of its assets to generate cash sufficient to pay interest and support Amplify's indebtedness; and (3) the viability of projects and the overall rates of return on alternative investment opportunities. Since Adjusted EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Adjusted EBITDA data presented in this press release may not be comparable to similarly titled measures of other companies. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted Net Income (Loss). Amplify defines Adjusted Net Income (Loss) as net income (loss) adjusted for unrealized loss (gain) on commodity derivative instruments, acquisition and divestiture-related expenses, impairment expense, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our federal statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that vary widely and unpredictably. This measure is not meant to disassociate these items from management's performance but rather is intended to provide helpful information to investors interested in comparing our performance between periods. Adjusted Net Income (Loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. Free cash flow. Amplify defines free cash flow as Adjusted EBITDA, less cash interest expense and capital expenditures. Free cash flow is an important non-GAAP financial measure for Amplify's investors since it serves as an indicator of the Company's success in providing a cash return on investment. The GAAP measures most directly comparable to free cash flow are net income and net cash provided by operating activities. Net debt. Amplify defines net debt as the total principal amount drawn on the revolving credit facility less cash and cash equivalents. The Company uses net debt as a measure of financial position and believes this measure provides useful additional information to investors to evaluate the Company's capital structure and financial leverage. Cash G&A. Amplify defines cash G&A as general and administrative expense, less share-based compensation expense; acquisition and divestiture costs; bad debt expense; and severance payments. Cash G&A is an important non-GAAP financial measure for Amplify's investors since it allows for analysis of G&A spend without regard to share-based compensation and other non-recurring expenses which can vary substantially from company to company. The GAAP measures most directly comparable to cash G&A is total G&A expenses. Contacts Jim Frew -- President and Chief Financial Officer(832) 219-9044jim.frew@amplifyenergy.com Michael Jordan -- Director, Finance and Treasurer(832) 219-9051michael.jordan@amplifyenergy.com Selected Operating and Financial Data (Tables)
Chord Energy Reports Second Quarter 2025 Financial and Operating Results, Declares Base Dividend and Issues Updated Outlook
Chord Energy Reports Second Quarter 2025 Financial and Operating Results, Declares Base Dividend and Issues Updated Outlook HOUSTON, Aug. 6, 2025 /PRNewswire/ -- Chord Energy Corporation (NASDAQ: CHRD) ("Chord", "Chord Energy" or the "Company") today reported financial and operating results for the second quarter 2025. Key Takeaways and Updates: Operational Excellence: Delivered net cash provided by operating activities and Adjusted Free Cash Flow ("Adjusted FCF")(1) above expectations, driven by efficient execution and strong asset performance;Shareholder Returns: Returned over 90% of Adjusted FCF(1) to shareholders through the base dividend of $1.30 per share and share repurchases;Share Repurchases: Repurchased $55.0MM of common stock in 2Q25 at an average price of $90.80/share; repurchased $45.2MM subsequent to 2Q25 through August 1, 2025. Reduced share count -10% on a fully-diluted basis since the Enerplus closing;Operational Execution: Drilled four 4-mile laterals to date with costs below budget; accelerating 4-mile activity and now on track to turn-in-line ("TIL") seven 4-mile laterals in FY25;Updated Outlook: Raised FY25 oil production guidance +500 Bopd and reduced capital -$20MM at the midpoint of guidance; on schedule to return a second completions crew in 4Q25; andEnhancing Adjusted FCF: Updated FY25 guidance implies a ~20% improvement in Adjusted FCF and ~25% improvement in Adjusted FCF per share vs. the February outlook (normalized for commodity pricing).2Q25 Operational and Financial Highlights: Production: Volumes of 156.7 MBopd (281.9 MBoepd) exceeded the high-end of guidance;CapEx: E&P and other CapEx of $355.6MM was at the low-end of guidance;Cash Flow: Net cash provided by operating activities was $419.8MM, with a net loss of $389.9MM ($6.77/diluted share); andAdjusted EBITDA, Adjusted FCF and Adjusted Net Income: Adjusted EBITDA(1) was $547.2MM, Adjusted FCF(1) was $140.8MM and Adjusted Net Income(1) was $103.2MM ($1.79/diluted share).(1) Non-GAAP financial measure. See "Non-GAAP Financial Measures" below for a reconciliation to the most directly comparable financial measures under United States generally accepted accounting principles ("GAAP"). "Chord Energy delivered another outstanding quarter driven by continued operational excellence," said Danny Brown, Chord Energy's President and Chief Executive Officer. "Free cash flow was above expectations, supporting continued high shareholder payouts. The Chord team demonstrated strong execution with better downtime, greater efficiency and solid well performance leading to an increase in our full-year production guidance and reduction in capital. Our premier Williston Basin position, built with a focus on disciplined capital allocation, early adoption of new technologies, and strategic M&A, puts Chord in a strong position to drive continuous improvement amidst persistent commodity volatility. We remain focused on optimizing capital allocation while operating in a safe and sustainable manner." 2Q25 Operational and Financial Update: The following table presents select 2Q25 operational and financial data compared to guidance released on May 6, 2025: Metric 2Q25 Actual 2Q25 Guidance Oil Volumes (MBopd) 156.7 153.0 - 156.0 NGL Volumes (MBblpd) 54.1 47.3 - 48.8 Natural Gas Volumes (MMcfpd) 425.9 408.5 - 421.5 Total Volumes (MBoepd) 281.9 268.3 - 275.0 E&P & Other CapEx ($MM) $355.6 $355 - $385 Oil Discount to WTI ($/Bbl) $(2.15) $(3.05) - $(1.05) NGL Realization (% of WTI) 9 % 5% - 15% Natural Gas Realization (% of Henry Hub) 32 % 25% - 35% LOE ($/Boe) $10.02 $9.25 - $10.25 Cash GPT ($/Boe)(1) $2.80 $2.65 - $3.15 Cash G&A ($MM)(1) $21.7 $26.0 - $28.0 Production Taxes (% of Oil, NGL and Natural Gas Sales)(2) 7.3 % 8.3% - 8.8% Cash Interest ($MM)(1) $18.6 $16.5 - $18.5 Cash Tax (% of Adjusted EBITDA)(3) 5.9 % 2% - 9% ___________________ (1) Non-GAAP financial measure. See "Non-GAAP Financial Measures" below for a reconciliation to the most directly comparable financial measures under GAAP. (2) 2Q25 includes non-recurring reimbursements of $8.5MM. (3) Cash taxes paid during the three months ended June 30, 2025 were $32.1MM, or 5.9% of Adjusted EBITDA. Guidance range based on NYMEX WTI between $55/Bbl - $75/Bbl. Chord had 37 gross (29.3 net) operated TILs in 2Q25. Return of Capital: Chord declared a base dividend of $1.30 per share of common stock. The dividend will be payable on September 8, 2025 to shareholders of record as of August 21, 2025. Details regarding the Return of Capital calculation can be found in the Company's most recent investor presentation located on its website at https://ir.chordenergy.com/presentations. The Company repurchased 605,621 shares of common stock at a weighted average price of $90.80 per share totaling $55.0MM in 2Q25, representing 100% of shareholder returns after the base dividend. Subsequent to 2Q25, the Company repurchased 423,902 shares of common stock totaling $45.2MM through August 1, 2025. Shares issued and outstanding as of August 1, 2025 were 57.3MM (57.7MM on a fully-diluted basis), compared to 57.6MM (58.1MM on a fully-diluted basis) as of June 30, 2025. Chord's Board of Directors has authorized a new share repurchase program totaling $1B, which replaces the existing program. 2025 Outlook Update: Chord is updating its FY25 guidance to reflect 1H25 performance and its latest projections. Chord remains on track to return a second completions crew to operations in 4Q25, given current oil prices. Chord has delivered production volumes and capital better than expectations in the first half of the year, reflecting solid execution, operational efficiencies, lower downtime and strong asset performance. Chord expects to generate Adjusted EBITDA of approximately $2.4B and Adjusted FCF of approximately $850MM at the midpoint of guidance (2H25 $65/Bbl WTI and $3.75/MMBtu Henry Hub). Chord plans to TIL115 - 135 gross operated wells (~80% working interest), with 30 - 40 gross operated TILs planned for 3Q25 (~70% working interest). Highlights of Chord's updated FY25 guidance include: Oil Volumes: Raised +500 Bopd to 153.0 MBopd at midpoint, driven by strong well performance and improved uptime;E&P and Other CapEx: Lowered -$20MM to $1.35B at midpoint; now -$50MM below original plan;LOE: Maintained at $9.60/Boe midpoint; -$0.30/Boe below original plan;Oil Differentials: Narrowed by $0.30/Bbl to reflect improved 2H25 market conditions;Cash Taxes: Lowered FY25 cash tax range to 3.5% - 6.5%% of Adjusted EBITDA (reflects 1H25 cash tax payments and 2H25 at $60/Bbl - $80/BBl WTI) reflecting our latest forecasts (previous guidance was 4% - 9% of Adjusted EBITDA); andAdjusted FCF: FY25 Adjusted FCF increasing ~$120MM (~20%) from original plan, driven by improved capital efficiency and lower operating costs (normalized $65/Bbl WTI and $3.75/MMBtu Henry Hub for both periods). See Chord's most recent investor presentation located on its website at https://ir.chordenergy.com/presentations for additional information.The following table presents select operational and financial guidance for the periods presented: Metric 3Q25 Guidance 4Q25 Guidance FY25 Guidance Oil Volumes (MBopd) 153.5 - 157.5 143.5 - 148.5 151.8 - 154.1 NGL Volumes (MBblpd) 50.5 - 54.5 48.0 - 53.0 50.2 - 52.5 Natural Gas Volumes (MMcfpd) 430.0 - 442.0 422.0 - 440.0 423.1 - 430.7 Total Volumes (MBoepd) 275.7 - 285.7 261.8 - 274.8 272.5 - 278.3 E&P & Other CapEx ($MM) $315 - $345 $295 - $325 $1,320 - $1,380 Oil Discount to WTI ($/Bbl) $(1.75) - $0.25 $(2.40) - $(0.40) $(2.15) - $(1.15) NGL Realization (% of WTI) 5% - 15% 10% - 20% 11% - 16% Natural Gas Realization (% of Henry Hub) 20% - 30% 30% - 40% 36% - 41% LOE ($/Boe) $8.70 - $9.70 $9.15 - $10.15 $9.35 - $9.85 Cash GPT ($/Boe)(1) $2.65 - $3.15 $2.65 - $3.15 $2.80 - $3.05 Cash G&A ($MM)(1) $20 - $25 $20 - $25 $90 - $100 Production Taxes (% of Oil, NGL and Natural Gas Sales) 8.3% - 8.8% 8.3% - 8.8% 7.6% - 7.8% Cash Interest ($MM)(1) $17 - $19 $17 - $19 $68 - $72 Cash Tax (% of Adjusted EBITDA)(2) 0% - 6% 3% - 10% 3.5% - 6.5% ___________________ (1) Non-GAAP financial measure. See "Non-GAAP Financial Measures" below for more information. (2) Cash Tax guidance reflects 2H25 WTI prices between $60/Bbl - $80/Bbl. Select Operational and Financial Data: The following table presents select operational and financial data for the periods presented: 2Q25 1Q25 2Q24 Production data: Crude oil (MBopd) 156.7 153.7 118.1 NGLs (MBblpd) 54.1 48.1 40.5 Natural gas (MMcfpd)(2) 425.9 414.5 291.5 Total production (MBoepd) 281.9 270.9 207.2 Percent crude oil 55.6 % 56.7 % 57.0 % Average sales prices: Crude oil, without realized derivatives ($/Bbl) $ 61.62 $ 69.11 $ 78.89 Differential to NYMEX WTI ($/Bbl) (2.15) (2.30) (1.71) Crude oil, with realized derivatives ($/Bbl) 62.58 69.08 78.53 Crude oil realized derivatives (gain) loss ($MM) (13.7) 0.4 (3.9) NGL, without realized derivatives ($/Bbl) 5.80 14.18 9.99 NGL, with realized derivatives ($/Bbl) 5.80 14.18 9.99 Natural gas, without realized derivatives ($/Mcf)(2) 1.10 2.30 0.67 Natural gas, with realized derivatives ($/Mcf) 1.11 2.31 0.67 Natural gas realized derivatives (gain) loss ($MM) (0.4) (0.1) - Selected financial data ($MM): Revenues: Crude oil revenues $ 878.9 $ 956.1 $ 848.1 NGL revenues 28.6 61.3 36.8 Natural gas revenues 42.8 85.9 17.8 Total oil, NGL and natural gas revenues $ 950.3 $ 1,103.3 $ 902.7 Cash flows: Net cash provided by operating activities: $ 1,076.7 $ 656.9 $ 460.9 Non-GAAP financial measures(1): Adjusted EBITDA $ 547.2 $ 695.5 $ 567.9 Adjusted FCF 140.8 290.5 216.1 Adjusted Net Income Attributable to Common Stockholders 103.2 240.9 234.9 Select operating expenses: LOE $ 257.0 $ 233.1 $ 176.6 Gathering, processing and transportation expenses ("GPT") 74.1 73.3 63.1 Production taxes 69.0 74.6 79.5 Depreciation, depletion and amortization 377.0 349.8 227.9 Total select operating expenses $ 777.1 $ 730.8 $ 547.1 Earnings (loss) per share: Basic earnings (loss) per share $ (6.71) $ 3.67 $ 4.36 Diluted earnings (loss) per share (6.77) 3.66 4.25 Adjusted diluted earnings per share (Non-GAAP)(1) 1.79 4.04 4.69 ___________________ (1) Non-GAAP financial measure. See "Non-GAAP Financial Measures" below for a reconciliation to the most directly comparable financial measures under GAAP. (2) Marcellus natural gas volumes and realized natural gas price were 129.9 MMcfpd and $2.49/Mcf, respectively, in 2Q25. Goodwill Impairment: At June 30, 2025, the Company assessed its goodwill balance for impairment as a result of the decline in its market capitalization during the second quarter, which was impacted by a decline in crude oil and natural gas prices. As a result of this assessment, the Company recognized a non-cash impairment charge of $539.3 million within impairment and exploration expenses on the Condensed Consolidated Statements of Operations during the three and six months ended June 30, 2025 to reduce the carrying value of its goodwill to zero as of June 30, 2025. Capital Expenditures: The following table presents the Company's capital expenditures ("CapEx") by category for the periods presented (in millions): 1Q25 2Q25 1H25 CapEx: E&P $ 354.8 $ 354.5 $ 709.3 Other 0.6 1.1 1.7 Total E&P and other CapEx 355.4 355.6 711.0 Capitalized interest 1.1 1.1 2.2 Acquisitions 17.9 8.3 26.2 Total CapEx $ 374.4 $ 365.0 $ 739.4 Balance Sheet and Liquidity: The following table presents key balance sheet data and liquidity metrics as of June 30, 2025 (in millions): June 30, 2025 Revolving credit facility(1) $ 2,000.0 Revolver borrowings $ 180.0 Senior notes 750.0 Total debt $ 930.0 Cash and cash equivalents $ 40.5 Letters of credit 29.9 Liquidity $ 1,830.6 ___________________ (1) $2.75B borrowing base and $2.0B of elected commitments. Contact: Chord Energy Corporation Bob Bakanauskas, VP, Investor Relations(281) 404-9600ir@chordenergy.com Conference Call Information Investors, analysts and other interested parties are invited to listen to the webcast: Date: Thursday, August 7, 2025 Time: 10:00 a.m. Central Live Webcast: https://app.webinar.net/Q1jBz3bLb7k To join the conference call by phone without operator assistance (including sell-side analysts wishing to ask a question), you may register and enter your phone number at https://emportal.ink/4k0K0dL to receive an instant automated call back and be immediately placed into the call. You may also use the following dial-in information to join the conference call by phone with operator assistance: Dial-in: 1-800-836-8184 Intl. Dial-in: 1-646-357-8785 Conference ID: 82050 A recording of the conference call will be available beginning at 1:00 p.m. Central on the day of the call and will be available until Thursday, August 14, 2025 by dialing: Replay dial-in: 1-888-660-6345 Intl. replay: 1-646-517-4150 Replay access: 82050 # The call will also be available for replay for approximately 30 days at https://www.chordenergy.com Forward-Looking Statements and Cautionary Statements Certain statements in this press release, other than statements of historical facts, that address activities, events or developments that Chord expects, believes or anticipates will or may occur in the future, including any statements regarding the benefits and synergies of the Enerplus combination, future opportunities for Chord, future financial performance and condition, guidance and statements regarding Chord's expectations, beliefs, plans, financial condition, objectives, assumptions or future events or performance are forward-looking statements based on assumptions currently believed to be valid. Forward-looking statements are all statements other than statements of historical facts. The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "probable," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "would," "potential," "may," "might," "anticipate," "likely," "plan," "positioned," "strategy" and similar expressions or other words of similar meaning, and the negatives thereof, are intended to identify forward-looking statements. Specific forward-looking statements include statements regarding Chord's plans and expectations with respect to the return of capital plan, production levels and reinvestment rates, anticipated financial and operating results and other guidance and the effects, benefits and synergies of the Enerplus combination. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. These statements are based on certain assumptions made by Chord based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of Chord, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in crude oil, NGL and natural gas prices, uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas, the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations, changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas and other similar measures, as well as the potential impact of retaliatory tariffs and other actions, war between Russia and Ukraine, military conflicts in the Red Sea Region and war between Israel and Hamas and the potential for escalation of hostilities across the surrounding countries in the Middle East and their effect on commodity prices, changes in general economic and geopolitical conditions, including as a result of the change in administration in the federal government of the United States, inflation rates and the impact of associated monetary policy responses, including increased interest rates, the ultimate results of integrating the operations of Chord, the effects of the Enerplus combination on Chord, including Chord's future financial condition, results of operations, strategy and plans, the ability of Chord to realize the anticipated benefits or synergies of the Enerplus combination in the timeframe expected or at all, developments in the global economy, as well as any public health crisis and resulting demand and supply for crude oil, NGLs and natural gas, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as Chord's ability to access them, the proximity to and capacity of transportation facilities, the availability of midstream service providers, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting Chord's business and other important factors that could cause actual results to differ materially from those projected as described in Chord's reports filed with the U.S. Securities and Exchange Commission (the "SEC"). Any forward-looking statement speaks only as of the date on which such statement is made and Chord 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. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements. Additional information concerning other risk factors is also contained in Chord's most recently filed Annual Report on Form 10-K for the year ended December 31, 2024, subsequent Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other SEC filings. About Chord Energy Chord Energy Corporation is an independent exploration and production company with quality and sustainable long-lived assets primarily in the Williston Basin. The Company is uniquely positioned with a best-in-class balance sheet and is focused on rigorous capital discipline and generating free cash flow by operating efficiently, safely and responsibly to develop its unconventional onshore oil-rich resources in the continental United States. For more information, please visit the Company's website at www.chordenergy.com. Comparability of Financial Statements The results reported for the three and six months ended June 30, 2025 reflect the consolidated results of Chord, including combined operations with Enerplus Corporation ("Enerplus"), while the results reported for the three and six months ended June 30, 2024 reflect the consolidated results of Chord, including the combined operations with Enerplus beginning on May 31, 2024, unless otherwise noted. Chord Energy CorporationCondensed Consolidated Balance Sheets (Unaudited)(In thousands, except share data) June 30, 2025 December 31, 2024 ASSETS Current assets Cash and cash equivalents $ 40,487 $ 36,950 Accounts receivable, net 1,279,056 1,298,973 Inventory 102,031 94,299 Prepaid expenses 17,874 30,875 Derivative instruments 82,069 35,944 Other current assets 2,168 82,077 Total current assets 1,523,685 1,579,118 Property, plant and equipment Oil and gas properties (successful efforts method) 13,602,081 12,770,786 Other property and equipment 59,938 58,158 Less: accumulated depreciation, depletion and amortization (2,851,535) (2,142,775) Total property, plant and equipment, net 10,810,484 10,686,169 Derivative instruments 7,962 5,629 Investment in unconsolidated affiliate 131,603 142,201 Long-term inventory 26,403 25,973 Operating right-of-use assets 23,846 38,004 Goodwill - 530,616 Other assets 22,613 24,297 Total assets $ 12,546,596 $ 13,032,007 LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 74,043 $ 68,751 Revenues and production taxes payable 681,508 752,742 Accrued liabilities 760,652 732,296 Accrued interest payable 18,586 4,693 Derivative instruments 342 1,230 Advances from joint interest partners 2,715 2,434 Current operating lease liabilities 29,351 37,629 Other current liabilities 9,438 84,203 Total current liabilities 1,576,635 1,683,978 Long-term debt 918,901 842,600 Deferred tax liabilities 1,545,492 1,496,442 Asset retirement obligations 392,742 282,369 Derivative instruments 2,500 1,016 Operating lease liabilities 8,234 15,190 Other liabilities 5,868 8,150 Total liabilities 4,450,372 4,329,745 Commitments and contingencies Stockholders' equity Common stock, $0.01 par value: 240,000,000 shares authorized, 67,146,139 sharesissued and 57,649,136 shares outstanding at June 30, 2025; and 240,000,000 sharesauthorized, 66,967,779 shares issued and 60,070,893 shares outstanding at December 31, 2024 675 673 Treasury stock, at cost: 9,497,003 shares at June 30, 2025 and 6,896,886 shares at December 31, 2024 (1,210,171) (936,157) Additional paid-in capital 7,327,295 7,336,091 Retained earnings 1,978,425 2,301,655 Total stockholders' equity 8,096,224 8,702,262 Total liabilities and stockholders' equity $ 12,546,596 $ 13,032,007 Chord Energy CorporationCondensed Consolidated Statements of Operations (Unaudited)(In thousands, except per share data) Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Revenues Oil, NGL and gas revenues $ 950,266 $ 902,667 $ 2,053,690 $ 1,650,829 Purchased oil and gas sales 230,294 358,013 341,916 695,111 Total revenues 1,180,560 1,260,680 2,395,606 2,345,940 Operating expenses Lease operating expenses 256,966 176,647 490,040 335,853 Gathering, processing and transportation expenses 74,100 63,130 147,415 117,114 Purchased oil and gas expenses 231,745 356,356 343,113 692,118 Production taxes 68,965 79,522 143,607 143,433 Depreciation, depletion and amortization 376,997 227,928 726,806 396,822 General and administrative expenses 32,540 82,077 70,917 107,789 Impairment and exploration 541,940 1,485 543,923 7,639 Total operating expenses 1,583,253 987,145 2,465,821 1,800,768 Gain (loss) on sale of assets, net (522) 15,486 4,993 16,788 Operating income (loss) (403,215) 289,021 (65,222) 561,960 Other income (expense) Net gain (loss) on derivative instruments 82,231 4,608 61,950 (22,969) Net gain (loss) from investment in unconsolidated affiliate (962) 5,862 (5,862) 22,158 Interest expense, net of capitalized interest (18,788) (12,208) (34,606) (19,800) Loss on debt extinguishment - - (3,494) - Other income 5,045 4,081 4,546 6,907 Total other income (expense), net 67,526 2,343 22,534 (13,704) Income (loss) before income taxes (335,689) 291,364 (42,688) 548,256 Income tax expense (54,216) (78,003) (127,380) (135,541) Net income (loss) $ (389,905) $ 213,361 $ (170,068) $ 412,715 Earnings (loss) per share: Basic $ (6.71) $ 4.36 $ (2.89) $ 9.12 Diluted $ (6.77) $ 4.25 $ (2.93) $ 8.87 Weighted average shares outstanding: Basic 57,786 48,665 58,420 45,048 Diluted 57,786 49,916 58,501 46,313 Chord Energy CorporationCondensed Consolidated Statements of Cash Flows (Unaudited)(In thousands) Six Months Ended June 30, 2025 2024 Cash flows from operating activities: Net income (loss) $ (170,068) $ 412,715 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 726,806 396,822 Loss on debt extinguishment 3,494 - Gain on sale of assets (4,993) (16,788) Impairment 539,318 3,919 Deferred income taxes 49,050 70,699 Net (gain) loss from investment in unconsolidated affiliate 5,862 (22,158) Net (gain) loss on derivative instruments (61,950) 22,969 Equity-based compensation expenses 12,997 10,130 Deferred financing costs amortization and other (11,297) 7,343 Working capital and other changes: Change in accounts receivable, net 4,479 (69,496) Change in inventory (5,738) (5,557) Change in prepaid expenses 5,463 17,262 Change in accounts payable, interest payable and accrued liabilities (20,031) 3,065 Change in other assets and liabilities, net 3,311 36,649 Net cash provided by operating activities 1,076,703 867,574 Cash flows from investing activities: Capital expenditures (704,388) (538,733) Acquisitions (26,191) (645,971) Proceeds from divestitures 6,921 20,876 Derivative settlements 14,090 (16,339) Contingent consideration received 25,000 25,000 Distributions from investment in unconsolidated affiliate 6,786 4,591 Net cash used in investing activities (677,782) (1,150,576) Cash flows from financing activities: Proceeds from revolving credit facility 2,435,000 825,000 Principal payments on revolving credit facility (2,700,000) (250,000) Repayment and discharge of senior notes (401,432) - Issuance of senior notes 750,000 - Deferred financing costs (13,443) - Repurchases of common stock (274,014) (93,745) Tax withholding on vesting of equity-based awards (21,793) (57,357) Dividends paid (168,846) (281,681) Payments on finance lease liabilities (856) (834) Proceeds from warrants exercised - 21,010 Net cash provided by (used in) financing activities (395,384) 162,393 Increase (decrease) in cash and cash equivalents 3,537 (120,609) Cash and cash equivalents: Beginning of period 36,950 317,998 End of period $ 40,487 $ 197,389 Supplemental non-cash transactions: Change in accrued capital expenditures $ (3,950) $ 24,389 Change in asset retirement obligations 100,632 3,476 Non-cash consideration exchanged in Merger - 3,732,137 Dividends payable 973 19,502 Non-GAAP Financial Measures The following are non-GAAP financial measures not prepared in accordance with GAAP that are used by management and external users of the Company's financial statements, such as industry analysts, investors, lenders and rating agencies. The Company believes that the foregoing are useful supplemental measures that provide an indication of the results generated by the Company's principal business activities. However, these measures are not recognized by GAAP and do not have a standardized meaning prescribed by GAAP. Therefore, these measures may not be comparable to similar measures provided by other issuers. From time to time, the Company provides forward-looking forecasts of these measures; however, the Company is unable to provide a quantitative reconciliation of the forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP measures because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measures. The reconciling items in future periods could be significant. To see how the Company reconciles its historical presentations of these non-GAAP financial measures to the most directly comparable GAAP measures, please visit the Investors-Documents & Disclosures-Non-GAAP Reconciliation page on the Company's website at https://ir.chordenergy.com/non-gaap. Cash GPT The Company defines Cash GPT as total GPT expenses less non-cash valuation charges on pipeline imbalances and non-cash mark-to-market adjustments on transportation contracts accounted for as derivative instruments. Cash GPT is not a measure of GPT expenses as determined by GAAP. Management believes that the presentation of Cash GPT provides useful additional information to investors and analysts to assess the cash costs incurred to market and transport the Company's commodities from the wellhead to delivery points for sale without regard to the change in value of its pipeline imbalances, which vary monthly based on commodity prices, and without regard to the non-cash mark-to-market adjustments on transportation contracts classified as derivative instruments. The following table presents a reconciliation of the GAAP financial measure of GPT expenses to the non-GAAP financial measure of Cash GPT for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 (In thousands) GPT $ 74,100 $ 63,130 $ 147,415 $ 117,114 Pipeline imbalances (2,270) (488) (1,722) (681) Loss on derivative transportation contract(1) - (2,647) - (5,877) Cash GPT $ 71,830 $ 59,995 $ 145,693 $ 110,556 ___________________ (1) The Company had a buy/sell transportation contract that qualified as a derivative. The changes in the fair value of this contract were recorded to GPT expense. As of June 30, 2024, the term of this contract expired. Cash G&A The Company defines Cash G&A as total G&A expenses less G&A expenses directly attributable to certain merger and acquisition activity, non-cash equity-based compensation expenses and other non-cash charges. Cash G&A is not a measure of G&A expenses as determined by GAAP. Management believes that the presentation of Cash G&A provides useful additional information to investors and analysts to assess the Company's operating costs in comparison to peers without regard to the aforementioned charges, which can vary substantially from company to company. The following table presents a reconciliation of the GAAP financial measure of G&A expenses to the non-GAAP financial measure of Cash G&A for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 (In thousands) General and administrative expenses $ 32,540 $ 82,077 $ 70,917 $ 107,789 Merger costs(1) (2,929) (54,687) (8,064) (62,794) Equity-based compensation expenses (6,121) (5,359) (12,997) (10,130) Other non-cash adjustments (1,790) (199) 193 1,461 Cash G&A $ 21,700 $ 21,832 $ 50,049 $ 36,326 ___________________ (1) Includes costs directly attributable to the arrangement with Enerplus for the three and six months ended June 30, 2025 and 2024. Cash Interest The Company defines Cash Interest as interest expense plus capitalized interest less amortization of deferred financing costs. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on the Company's debt to finance its operating activities and the Company's ability to maintain compliance with its debt covenants. The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 (In thousands) Interest expense $ 18,788 $ 12,208 $ 34,606 $ 19,800 Capitalized interest 1,109 1,158 2,188 1,867 Amortization of deferred financing costs (1,255) (1,366) (2,526) (2,258) Cash Interest $ 18,642 $ 12,000 $ 34,268 $ 19,409 Adjusted EBITDA and Adjusted Free Cash Flow The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization ("DD&A"), merger costs, exploration expenses, impairment expenses, loss on debt extinguishment and other similar non-cash or non-recurring charges. The Company defines Adjusted Free Cash Flow as Adjusted EBITDA less Cash Interest and E&P and other capital expenditures (excluding capitalized interest and acquisition capital). Adjusted EBITDA and Adjusted Free Cash Flow are not measures of net income or cash flows from operating activities as determined by GAAP. Management believes that the presentation of Adjusted EBITDA and Adjusted Free Cash Flow provides useful additional information to investors and analysts for assessing the Company's results of operations, financial performance, ability to generate cash from its business operations without regard to its financing methods or capital structure and the Company's ability to maintain compliance with its debt covenants. The following table presents reconciliations of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted Free Cash Flow for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 (In thousands) Net income (loss) $ (389,905) $ 213,361 $ (170,068) $ 412,715 Interest expense, net of capitalized interest 18,788 12,208 34,606 19,800 Loss on debt extinguishment - - 3,494 - Income tax expense 54,216 78,003 127,380 135,541 Depreciation, depletion and amortization 376,997 227,928 726,806 396,822 Merger costs(1) 2,929 54,687 8,064 62,794 Impairment and exploration expenses(2) 541,940 1,485 543,923 7,639 (Gain) loss on sale of assets 522 (15,486) (4,993) (16,788) Net (gain) loss on derivative instruments (82,231) (4,608) (61,950) 22,969 Realized gain (loss) on commodity price derivative contracts 14,090 (3,896) 13,839 (5,257) Net (gain) loss from investment in unconsolidated affiliate 962 (5,862) 5,862 (22,158) Distributions from investment in unconsolidated affiliate 2,377 2,305 4,736 4,591 Equity-based compensation expenses 6,121 5,359 12,997 10,130 Other non-cash adjustments 420 2,455 (1,960) 3,919 Adjusted EBITDA 547,226 567,939 1,242,736 1,032,717 Cash interest (18,642) (12,000) (34,268) (19,409) E&P and other capital expenditures (355,589) (314,311) (711,028) (572,059) Cash taxes paid (32,148) (25,500) (66,098) (25,500) Adjusted Free Cash Flow $ 140,847 $ 216,128 $ 431,342 $ 415,749 Net cash provided by operating activities $ 419,810 $ 460,875 $ 1,076,703 $ 867,574 Changes in working capital 49,725 8,229 12,516 18,078 Interest expense, net of capitalized interest 18,788 12,208 34,606 19,800 Current income tax expense 34,931 34,271 78,331 64,841 Merger costs(1) 2,929 54,687 8,064 62,794 Exploration expenses 2,623 1,485 4,605 3,720 Realized gain (loss) on commodity price derivative contracts 14,090 (3,896) 13,839 (5,257) Distributions from investment in unconsolidated affiliate 2,377 2,305 4,736 4,591 Deferred financing costs amortization and other 1,533 (4,680) 11,296 (7,343) Other non-cash adjustments 420 2,455 (1,960) 3,919 Adjusted EBITDA 547,226 567,939 1,242,736 1,032,717 Cash interest (18,642) (12,000) (34,268) (19,409) E&P and other capital expenditures (355,589) (314,311) (711,028) (572,059) Cash taxes paid (32,148) (25,500) (66,098) (25,500) Adjusted Free Cash Flow $ 140,847 $ 216,128 $ 431,342 $ 415,749 ___________________ (1) Includes costs directly attributable to the arrangement with Enerplus for the three and six months ended June 30, 2025 and 2024. (2) Includes non-cash goodwill impairment charge of $539.3 million for the three and six months ended June 30, 2025, as a result of the decline in the Company's market capitalization during the second quarter. Adjusted Net Income and Adjusted Diluted Earnings Per Share Adjusted Net Income and Adjusted Diluted Earnings Per Share are supplemental non-GAAP financial measures that are used by management and external users of the Company's financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted Net Income as net income after adjusting for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, non-cash changes in the fair value of the Company's investment in an unconsolidated affiliate, impairment, loss on debt extinguishment and other similar non-cash charges (2) merger costs and (3) the impact of taxes based on an estimated tax rate applicable to those adjusting items in the same period. Adjusted Net Income is not a measure of net income as determined by GAAP. The Company calculates earnings per share under the two-class method in accordance with GAAP. The two-class method is an earnings allocation formula that computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Adjusted Diluted Earnings Per Share is calculated as (i) Adjusted Net Income (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The following table presents reconciliations of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted Net Income and the GAAP financial measure of diluted earnings per share to the non-GAAP financial measure of Adjusted Diluted Earnings Per Share for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 (In thousands) Net income (loss) $ (389,905) $ 213,361 $ (170,068) $ 412,715 Net (gain) loss on derivative instruments (82,231) (4,608) (61,950) 22,969 Realized gain (loss) on commodity price derivativecontracts 14,090 (3,896) 13,839 (5,257) Net (gain) loss from investment in unconsolidated affiliate 962 (5,862) 5,862 (22,158) Distributions from investment in unconsolidated affiliate 2,377 2,305 4,736 4,591 Impairment(1) 539,317 - 539,318 3,919 Merger costs(2) 2,929 54,687 8,064 62,794 (Gain) loss on sale of assets, net 522 (15,486) (4,993) (16,788) Amortization of deferred financing costs 1,255 1,366 2,526 2,258 Loss on debt extinguishment - - 3,494 - Other non-cash adjustments 420 2,455 (1,960) 3,919 Tax impact(3) 14,032 (8,288) 7,140 (13,952) Adjusted net income 103,768 236,034 346,008 455,010 Distributed and undistributed earnings allocated to participating securities (614) (1,121) (1,436) (1,494) Adjusted net income attributable to common stockholders $ 103,154 $ 234,913 $ 344,572 $ 453,516 Three Months Ended June 30, Six Months Ended June 30, 2025 2024 2025 2024 Diluted earnings (loss) per share $ (6.75) $ 4.25 $ (2.91) $ 8.87 Net (gain) loss on derivative instruments (1.42) (0.09) (1.06) 0.50 Realized gain (loss) on commodity price derivative contracts 0.24 (0.08) 0.24 (0.11) Net (gain) loss from investment in unconsolidatedaffiliate 0.02 (0.12) 0.10 (0.48) Distributions from investment in unconsolidated affiliate 0.04 0.05 0.08 0.10 Impairment(1) 9.33 - 9.22 0.08 Merger costs(2) 0.05 1.10 0.14 1.36 (Gain) loss on sale of assets, net 0.01 (0.31) (0.09) (0.36) Amortization of deferred financing costs 0.02 0.03 0.04 0.05 Loss on debt extinguishment - - 0.06 - Other non-cash adjustments 0.02 0.05 (0.03) 0.08 Tax impact(3) 0.24 (0.17) 0.12 (0.30) Adjusted Diluted Earnings Per Share 1.80 4.71 5.91 9.79 Less: Distributed and undistributed earnings allocated toparticipating securities (0.01) (0.02) (0.02) (0.03) Adjusted Diluted Earnings Per Share $ 1.79 $ 4.69 $ 5.89 $ 9.76 Diluted weighted average shares outstanding (in thousands) 57,786 49,916 58,501 46,313 Tax rate applicable to adjustment items(2) 23.5 % 26.8 % 23.5 % 24.7 % _____________________ (1) Includes non-cash goodwill impairment charge of $539.3 million for the three and six months ended June 30, 2025, as a result of the decline in the Company's market capitalization during the second quarter. (2) Includes costs directly attributable to the arrangement with Enerplus for the three and six months ended June 30, 2025 and 2024. (3) The tax impact is computed by applying an estimated tax rate to the adjustments for certain non-cash and non-recurring items. View original content to download multimedia:https://www.prnewswire.com/news-releases/chord-energy-reports-second-quarter-2025-financial-and-operating-results-declares-base-dividend-and-issues-updated-outlook-302523552.html SOURCE Chord Energy
/C O R R E C T I O N -- EnerCom, Inc./
/C O R R E C T I O N -- EnerCom, Inc./ In the news release, EnerCom Announces Andrew Rapp, Senior Advisor in the U.S. Department of Energy, as Keynote Speaker on August 18th at EnerCom's 30th Anniversary Energy Investment Conference, issued 06-Aug-2025 by EnerCom, Inc. over PR Newswire, we are advised by the company that the second paragraph should read "Chad Zamarin" rather than "Chris Zamarin" as originally issued inadvertently. The complete, corrected release follows: EnerCom Announces Andrew Rapp, Senior Advisor in the U.S. Department of Energy, as Keynote Speaker on August 18th at EnerCom's 30th Anniversary Energy Investment Conference Qualified Investors and Analysts Can Register at No Cost at www.enercomdenver.com Deadline to Submit One-on-One Meeting Requests to Presenting Companies is Friday, August 8th Registration still available for EnerCom Denver - The Energy Investment Conference, featuring a broad group of public and private energy companies at www.enercomdenver.com DENVER, Aug. 6, 2025 /PRNewswire/ -- EnerCom, Inc., a leading energy consulting and strategic communications firm, is pleased to announce that Andrew Rapp, Senior Advisor in the U.S. Department of Energy, has been confirmed as the keynote luncheon speaker on Monday, August 18th, at EnerCom Denver - The Energy Investment Conference. Other keynote speakers participating in the conference include Ron Gusek, CEO of Liberty Energy, Chad Zamarin, CEO of Williams, and Craig Bealmear, CFO of Oklo. For the past 30 years, EnerCom Denver has been the largest independent investor conference for the global oil and gas and broadening energy industry that is open to all energy companies, investors, and professionals to participate. This year's conference will occur August 17-20, 2025, at The Westin Denver Downtown. Institutional investors, portfolio managers, family offices, financial analysts, CIOs, and other investment community and industry professionals are encouraged to register now for EnerCom Denver at www.EnerComDenver.com. The conference is free for qualified investment professionals. About Andrew Rapp Andrew Rapp is a Senior Advisor in the United States Department of Energy, where he works closely with Secretary Chris Wright to advance energy abundance, reliability, and security in the United States and abroad. Prior to his appointment to the Department of Energy, Andrew was a co-founder and Vice-Chairman of Petrie Partners, an energy-focused, boutique investment bank specializing in strategic transaction advisory assignments. Before forming Petrie in 2011, Andrew was a Managing Director of Bank of America Merrill Lynch in the Energy and Power Group. Andrew joined Bank of America Merrill Lynch as part of Merrill Lynch's acquisition of Petrie Parkman & Co. in 2006. During his 25-year investment banking career, Andrew completed 185 merger, divestiture, joint venture, and financing transactions totaling over $200 billion in consideration while working with public and private energy companies and sovereign entities throughout the United States and the world. He advised on 30 corporate mergers involving publicly traded companies, including the $68 billion merger of Pioneer Natural Resources and ExxonMobil, the largest energy transaction of the 21st century, and largest global transaction in 2024. Andrew earned his B.A. in Economics, Policy Studies, and Managerial Studies from Rice University. The full schedule for the conference can be found at www.enercomdenver.com. EnerCom Denver Investor Conference Details In its 30th year, the conference kicks off with the annual Charity Golf Tournament on Sunday, August 17th at the scenic Arrowhead Golf Club. The golf event is sponsored by global sponsor Netherland, Sewell & Associates and EnerCom. The tournament is a fundraiser for IN! Pathways to Inclusive Higher Education. By participating in the charity golf tournament, requiring a $150 donation, you directly contribute to creating inclusive college opportunities in Colorado for students with intellectual disabilities and fostering academic growth, social development, and career advancement. EnerCom Denver also hosts a Monday Mixer cocktail reception after day one of conference presentations, which is sponsored by ATB Capital Markets. This valuable opportunity for attendees to enjoy appetizers, drinks, and live music while networking with other conference participants and key representatives from the energy industry shouldn't be missed. Casino Night, sponsored by CAC Specialty, follows day two of the conference; experience the entertainment, fun, and excitement of playing in a real casino environment with "funny money" (no cash value, for entertainment only) at the poker, blackjack, roulette, and craps tables manned by professional dealers. This year will also include a charity poker tournament. Join us for a night of revelry, music, good food, and drinks, and it is open to all conference attendees. Please join us after the conference concludes on Wednesday afternoon with a closing reception as we reflect on the 2025 Conference. Institutional investors, portfolio managers, family offices, financial analysts, CIOs, and other investment community and industry professionals are encouraged to register now for EnerCom Denver at www.EnerComDenver.com. The conference is free for qualified investment professionals. Companies interested in presenting can contact Larry Busnardo at lbusnardo@enercominc.com. Sponsorship opportunities are available by contacting Blanca Andrus at bandrus@enercominc.com. The presenting company lineup as of August 5, 2025, includes: Advantage Energy (TSX: AAV) Amplify Energy (NYSE: AMPY)Anschutz ExplorationAPA Corp. (NASDAQ: APA)Armstrong Oil & GasAureus Energy ServicesBaytex Energy (NYSE/TSX: BTE) Berry Corporation (NASDAQ: BRY) Bison Oil & Gas IV BKV (NYSE: BKV)Blackbeard Operatingbpx energy (NYSE: BP)CanCambria Energy (TSXV: CCEC; OTCQB: CCEYF) Deep Blue WaterDeep FissionDeep IsolationDiversified Energy (NYSE/LSE: DEC) DNOW (NYSE: DNOW) Drilling Tools International (NASDAQ: DTI)EnerComEnergy Fuels (NYSE: UUUU; TSX: EFR)Eni SpA (NYSE: E) EOG Resources (NYSE: EOG)Epsilon Energy (NASDAQ: EPSN)ESalFlotek Industries (NYSE: FTK) Freehold Royalties (TSX: FRU)Fundare Resources Gondola Resources Gran Tierra Energy (NYSE/TSX/LSE: GTE) Granite Ridge Resources (NYSE: GRNT)GreenFlare TechnologyHaynes Boone Hemisphere Energy (TSX: HME; OTCQX: HMENF) Kelt Exploration (TSX: KEL) KODALiberty Energy (NYSE: LBRT) Logan Energy (TSXV: LGN)LOGOS EnergyMach Natural Resources (NYSE: MNR) Meren Energy (TSX: MER) NCS Multistage (NASDAQ: NCSM) New Era Helium (NASDAQ: NEHC) NuVista Energy (TSX: NVA) NXT Energy Solutions (TSX: SFD; OTCQB: NSFDF)Oklo (NYSE: OKLO)Parex Resources (TSX: PXT; OTCMKTS: PARXF) Petrie PartnersPGIM Private CapitalPrairie Operating (NASDAQ: PROP) Precision Drilling (NYSE: PDS; TSX: PD) Prospera Energy (TSX: PEI; OTC: GXRFF) Providence Energy Raisa Energy ReconAfrica (TSXV: RECO; OTCQX: RECAF; Frankfurt: 0XD) Renewell EnergyRiley Permian (NYSE: REPX)Ring Energy (NYSE: REI) SandRidge Energy (NYSE: SD)Saturn Oil & Gas (TSX: SOIL; OTCQX: OILSF) Select Water Solutions (NYSE: WTTR) SM Energy (NYSE: SM)Solestiss Spartan Delta (TSX: SDE) Surge Energy AmericaTamarack Valley Energy (TSX: TVE) Tenaz Energy (TSX: TNZ)Teren UbiterraU.S. Energy Development CorporationUpCurve Energy Valeura Energy (TSX: VLE; OTCQX: VLERF) Verde EOR Solutions Vermilion Energy (NYSE/TSX: VET) Vero3Vitesse Energy (NYSE: VTS) Whitecap Resources (TSX: WCP) Williams (NYSE: WMB)Zephyr Energy (AIM: ZPHR; OTCQB: ZPHRF) Conference Overview Conference Details: EnerCom Denver offers investment professionals a unique opportunity to network and listen to senior management teams from leading companies across the energy value chain update investors on their operational and financial strategies and learn how they create value for stakeholders. Conference Dates: August 17-20, 2025. EnerCom will host its annual Charity Golf Tournament on Sunday, August 17th at the scenic Arrowhead Golf Club in Littleton, Colorado. Benefitting IN! Pathways to Inclusive Higher Education, the Golf Tournament requires a $150 charity donation to participate. Formal presentations and meetings will be held Monday, August 18th, through Wednesday, August 20th. Venue: Westin Denver Downtown. Please book rooms under the EnerCom Denver block. We encourage attendees to book their reservations as soon as possible, as rooms sell out. Who Attends the Conference: Institutional investors, family offices, high-net-worth investors, private equity, research analysts, retail brokers, trust officers, investment and commercial bankers, and energy industry professionals gather in Denver for the conference. Conference Format and Details: The EnerCom Denver conference follows EnerCom's familiar 25-minute presentation format, followed by 50-minute Q&A opportunities in separate breakout rooms, one-on-one meetings, and multiple networking opportunities. In addition to in-person access to all company presentations, panel discussions, and keynote speakers, conference registration allows investors and management teams to meet formally and informally over cocktails, breakfast, and lunch. About EnerCom, Inc.: Founded in 1994, EnerCom, Inc. has been a trusted advisor to the global energy industry, working with clients to differentiate and deliver targeted messages to investors. Headquartered in Denver, EnerCom is an internationally recognized strategic communications and management consultancy that advises companies on investor relations, corporate strategy/board advisory, fractional/interim CFO advisory services, marketing, financial analysis and valuation, media, branding, and visual communications design. For more information about EnerCom and its services, please visit www.enercominc.com or call (303) 296-8834 to speak with one of our consultants. EnerCom Denver Sponsors Include: Netherland, Sewell & Associates, Inc. (NSAI) Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations, and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. netherlandsewell.com Haynes Boone Haynes Boone is an energy-focused corporate law firm that provides a full spectrum of legal services and solutions to clients across the energy industry, including the upstream, midstream, and downstream sectors as well as power and renewables. Our team of more than 100 energy lawyers and landmen has been helping operators, lenders, and private equity firms with some of their most complex and significant transactions and disputes in recent years. The firm's nearly 700 lawyers practice across 19 global offices located in California, Colorado, Illinois, New York, North Carolina, Texas, Virginia, Washington, D.C., London, Mexico City, and Shanghai. The 2023 Chambers USA Legal Guide ranked 31 different firm practice areas, and in 2024, Haynes Boone became the first Am Law 100 firm to ever earn a Gold-level Bell Seal from Mental Health America. The U.S. News & World Report and Best Lawyers "Best Law Firms" 2023 survey ranked Haynes Boone in National Tier 1 in Oil & Gas Law. haynesboone.com Baker Botts For over 100 years, Baker Botts has been helping energy clients tackle the toughest of their legal challenges. Our deep bench of experienced transactional, environmental, litigation, regulatory, IP, and tax lawyers has helped companies all across the energy industry. Throughout this time we have served as trusted advisors to companies working in every sector of energy - from oil and gas to conventional and renewable power to renewable fuels to LNG and many other related areas. Much of this work has involved our clients' development and deployment of new energy technologies, which has allowed our lawyers to practice at the cutting edge of every energy "revolution" since the turn of the last century. Wherever significant energy is produced in the world, Baker Botts lawyers work to advance our clients' objectives in the boardroom, the courtroom, and on-the-ground, drawing upon our deep understanding of the complex legal, technical and policy issues that they face. bakerbotts.com ATB Capital Markets ATB Capital Markets offers holistic corporate and capital markets advice, combined with customised financial solutions to help businesses thrive. We're a full-service financial services provider for key industries. Backed by ATB Financial, a leading financial institution with $62.0 billion in assets, ATB Capital Markets helps clients with services that include investment and corporate banking, sales and trading, institutional research, and risk management. atb.com CAC Specialty CAC Specialty is an employee owned risk solutions company of seasoned and proactive industry leaders, operating as a nimble and collaborative partner who puts you and your business first. With a knowledge-driven approach informed by industry data and decades of honed instinct, CAC brings an innovative vision to insurance broking and merchant banking by providing solutions to solve your risk challenges - from the simple to the previously unsolvable. Backed by a $40B AUM asset manager and not constrained by traditional risk transfer thinking, CAC can expand the range of risk transfer through access to private debt and alternative pools of risk capital. cacgroup.com bpx energy bpx energy, bp's US onshore business, operates in the Permian, Eagle Ford, and Haynesville basins. Headquartered in Denver, bpx embodies the entrepreneurial spirit of a domestic U.S. onshore producer - utilizing next level technology to safely increase production while lowering emissions, and leveraging other integrated bp business like supply, trading and shipping to maximize value. bp.com Petrie Partners Petrie Partners, LLC is a boutique investment banking firm dedicated to the energy industry. The senior leadership has a multi-decade legacy of delivering specialized advice on mergers and acquisitions, asset transactions and valuations, and financings to the boards and managements of public, private, and sovereign entities. Petrie clients benefit from the independent, conflict-free perspective and unwavering advocacy of their best interests that the team brings to every engagement. www.petrie.com Vitesse Energy Vitesse is a Denver-based company focused on returning capital to stockholders through owning and acquiring predominantly non-operated working interests in oil and gas properties in the Williston Basin of North Dakota and Montana. The Company also owns non-operated interests in the Central Rockies, including the Denver-Julesburg Basin and the Powder River Basin. www.vitesse-vts.com IMA IMA Financial Group is an independent broker, defining the future of insurance through comprehensive and consultative risk and wealth management services. A majority employee-owned and managed company, its 2,300-plus associates in offices across the country are empowered by a shared mission to manage risk, protect assets, and make a difference. www.imacorp.com Oil & Gas 360® The Media Sponsor of Enercom Denver, Oil & Gas 360® is a one-stop source of news, information, and analysis from the professionals at EnerCom, Inc. The website is dedicated to all things energy: people, technologies, transactions, trends, and macro-economic analysis that impact our industry. Oil & Gas 360 View original content to download multimedia:https://www.prnewswire.com/news-releases/enercom-announces-andrew-rapp-senior-advisor-in-the-us-department-of-energy-as-keynote-speaker-on-august-18th-at-enercoms-30th-anniversary-energy-investment-conference-302523471.html SOURCE EnerCom, Inc.
DISA Technologies Closes Oversubscribed $30M Series A2 Round to Accelerate Mineral Processing & Uranium Remediation Solutions
DISA Technologies Closes Oversubscribed $30M Series A2 Round to Accelerate Mineral Processing & Uranium Remediation Solutions Evok Innovations and Constellation Technology Ventures Lead Investment in Scalable Technology for Critical Mineral Liberation and Legacy Waste Cleanup CASPER, Wyo., Aug. 6, 2025 /PRNewswire/ -- DISA Technologies Inc. (DISA), a company pioneering high-impact solutions for mineral recovery and uranium remediation, has closed its oversubscribed Series A2 financing round. DISA raised a total of $30 million in private capital, including $23 million in primary funding and $7 million in secondary to accommodate oversubscription and provide liquidity for early angel investors. The round was led by Evok Innovations with cornerstone strategic investment from Constellation Technology Ventures (CTV), the venture investing organization within Constellation, the nation's largest producer of reliable, emissions-free energy and participation from Valor Equity Partners, Veriten, and existing backers including Halliburton Labs. DISA's patented High-Pressure Slurry Ablation (HPSA) technology was developed to serve both modern mineral processing and environmental remediation needs-delivering a cleaner, faster and more efficient way to liberate valuable minerals. HPSA is now being scaled for deployment across two critical applications: improving grades and recoveries of critical minerals for mining operators, and cleaning up Abandoned Uranium Mine (AUM) waste by recycling uranium and vanadium while reducing environmental liability. "We're proud to have the support of such forward-thinking partners who share our vision: increasing the global production of critical minerals and converting toxic legacy waste into strategic assets that advance American sustainability, energy resilience, and national security," said Greyson Buckingham, DISA's CEO, President and Co-Founder. "This investment allows us to accelerate commercial deployment of HPSA units for both mining operators and uranium remediation stakeholders." "We're especially grateful to Evok for believing in DISA from the beginning, and to Constellation for their bold leadership in shaping America's energy future," Buckingham added. "We're also excited to welcome Veriten and Valor Equity Partners to the team, and deeply appreciate the continued support from Halliburton Labs and our other existing investors who have helped make this next chapter possible." CTV's investment highlights the strategic importance of DISA's accelerating uranium remediation work. Following a successful 2023 EPA Treatability Study, DISA signed an MOU with the Navajo Nation EPA to launch a Phase 2 commercial-scale demonstration project. In April 2025, DISA's application for an NRC Service Providers License (SPL) was accepted for technical review, with completion of the licensing action decision expected by September. Constellation's backing strengthens DISA's position as the nation's first licensed provider focused on AUM remediation. "At Constellation, we recognize that securing America's energy future starts with securing its fuel supply," said Bryan Hanson, Chief Generation Officer, Constellation. "DISA's innovative approach aligns with our goal to strengthen domestic energy resilience and deploy cutting-edge technologies that support clean, reliable energy." Evok Innovations and Valor Equity Partners bring deep strategic value to DISA-Evok through its focus on cutting-edge energy innovation, and Valor through its operational expertise with high-growth companies. Veriten adds industry insight and connectivity across the energy landscape, while Halliburton Labs continues to be a vital collaborator supporting founder-led innovation. "Valor Equity Partners is proud to invest in DISA, a company that embodies innovation and possesses significant growth potential. Our investment reflects our belief in the company's vision and leadership team, along with our focus on disruptive technologies that are making the world a better place. We are grateful for the opportunity to partner with DISA in this next phase of growth," said David Heskett, Operating Partner at Valor Equity Partners. "Halliburton Labs reaffirms its support of DISA through this strategic investment," said Andres Cabada, managing director at Halliburton Labs. "DISA's innovation in mineral processing and remediation creates meaningful value for resource owners and other stakeholders. We welcome the opportunity to collaborate as DISA advances its commercialization efforts and expands its operations. We look forward to their success". "Investing in DISA is an opportunity to catalyze groundbreaking uranium remediation solutions that can have downstream impacts on our energy landscape. Complemented by their entrepreneurial founder-led team, we are excited to begin this partnership," said Maynard Holt, Founder and CEO of Veriten. DISA has successfully executed several key milestones over the last 24 months, and this funding round will enable the company to scale its operations and expand the capabilities of HPSA faster than ever. For more information about DISA and its solutions, please visit www.DISAusa.com. About DISA Technologies Founded in 2018, DISA Technologies is revolutionizing mineral recovery through its patented High-Pressure Slurry Ablation (HPSA) technology-an innovative solution that upgrades critical minerals from mined ore and legacy waste. Serving both the mining and remediation sectors, they recover valuable resources that power industry, strengthen energy independence and restore contaminated sites to productive use. DISA's technology unlocks economic and environmental value, transforming how the world processes, remediates and recycles essential mineral assets. DISA is headquartered in0x202FCasper, Wyoming, with a satellite office in Westminster, Colorado. About Evok Innovations Launched in 2016 through a partnership between Suncor, Cenovus and the BC Cleantech CEO Alliance, Evok Innovations (Evok), is committed to developing and deploying cutting-edge clean energy technology. Evok's inaugural fund aimed to accelerate the development of critical energy transition technologies across North America. The fund has made 16 investments in decarbonization technologies, ranging from clean hydrogen and carbon-to-value, to long-duration energy storage. Building on this legacy, Evok launched Fund II in 2022, which targets early-stage investments across North America in key industrial decarbonization verticals, including carbon capture use and storage (CCUS), low-carbon fuels, clean energy and grid innovations, mobility, advanced materials and circularity. About Constellation Technology Ventures Constellation Technology Ventures (CTV) is the venture investing organization within Constellation, the United States' largest producer of clean, carbon-free energy and a leading supplier of energy products and services to businesses, homes, community aggregations and public sector customers. The mission of CTV is to drive innovation by investing in venture-stage energy technology companies that can provide new solutions to Constellation and its customers. CTV invests in companies exploring innovative energy technologies and business models, building a portfolio that represents a broad range of development stages and technology types. About Valor Equity Partners Valor Equity Partners is an operational growth investment firm focused on investing in high-growth companies across various stages of development. For decades, Valor has served its companies with unique expertise to solve the challenges of growth and scale. Valor partners with leading companies and entrepreneurs who are committed to the highest standards of excellence and the courage to transform their industries. For more information on Valor Equity Partners, please visit www.valorep.com. About Veriten's NexTen Fund The NexTen fund leverages Veriten's broad network and expertise to invest in reliable, sustainable, scalable, and economically viable energy solutions. Dedicated to understanding the constantly evolving, volatile, and often noisy and confusing energy landscape, the firm has now backed 13 innovative, private companies poised to capitalize on long-term, global energy trends. About Halliburton Labs Halliburton Labs is a collaborative environment where entrepreneurs, academics, investors, and experienced practitioners advance the future of energy faster. Halliburton Labs provides access to world-class facilities, a global business network, commercialization expertise, and financing opportunities to help participants scale their business. Visit the company's website at Halliburton Labs. Connect with Halliburton Labs on LinkedIn and Instagram. Halliburton Labs is a wholly owned subsidiary of Halliburton Company (NYSE: HAL). View original content to download multimedia:https://www.prnewswire.com/news-releases/disa-technologies-closes-oversubscribed-30m-series-a2-round-to-accelerate-mineral-processing--uranium-remediation-solutions-302523431.html SOURCE DISA Technologies, Inc.