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Global Partners Reports Third-Quarter 2025 Financial Results
Global Partners Reports Third-Quarter 2025 Financial Results WALTHAM, Mass., Nov. 07 /BusinessWire/ -- Global Partners LP (NYSE:GLP) ("Global" or the "Partnership") today reported financial results for the third quarter ended September 30, 2025. CEO Commentary "Global performed well in the third quarter, consistent with our expectations, reflecting our operational strength, focused execution, and the disciplined way we continue to grow and optimize our business," said Eric Slifka, Global Partners' President and Chief Executive Officer. "We delivered a strong performance in our Wholesale segment, fueled by the continued growth and scale of our terminal network, an investment that's enhancing how we move energy and products across our footprint. While our Gasoline Distribution and Station Operations segment experienced lower fuel margins compared with the strong margin environment in Q3 2024, our focus remains clear: operate with discipline, invest wisely, and keep optimizing our assets to drive sustainable growth and long-term value for our unitholders. We're proud of the progress we've made and confident in the opportunities ahead as we continue to put our energy to work across every part of our business." Third-Quarter 2025 Financial Highlights Net income was $29.0 million, or $0.66 per diluted common limited partner unit, for the third quarter of 2025, compared with $45.9 million, or $1.17 per diluted common limited partner unit, in the same period of 2024. Earnings before interest, taxes, depreciation and amortization (EBITDA) was $97.1 million in the third quarter of 2025 compared with $119.1 million in the same period of 2024. Adjusted EBITDA was $98.8 million in the third quarter of 2025 versus $114.0 million in the same period of 2024. Distributable cash flow (DCF) was $53.0 million in the third quarter of 2025 compared with $71.1 million in the same period of 2024. Adjusted DCF was $53.3 million in the third quarter of 2025 compared with $71.6 million in the same period of 2024. Gross profit was $271.4 million in the third quarter of 2025 compared with $286.0 million in the same period of 2024. Combined product margin, which is gross profit adjusted for depreciation allocated to cost of sales, was $303.9 million in the third quarter of 2025 compared with $318.3 million in the same period of 2024. Combined product margin, EBITDA, adjusted EBITDA, DCF and adjusted DCF are non-GAAP (Generally Accepted Accounting Principles) financial measures, which are explained in greater detail below under "Use of Non-GAAP Financial Measures." Please refer to Financial Reconciliations included in this news release for reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures for the three months and nine months ended September 30, 2025, and 2024. Gasoline Distribution and Station Operations (GDSO) segment product margin was $218.9 million in the third quarter of 2025 compared with $237.7 million in the same period of 2024. Product margin from gasoline distribution was $144.8 million compared with $164.1 million in the year-earlier period, reflecting lower retail fuel volume and margin. Product margin from station operations was $74.1 million in the third quarter of 2025 compared with $73.6 million in the third quarter of 2024. Wholesale segment product margin was $78.0 million in the third quarter of 2025 compared with $71.1 million in the same period of 2024. Gasoline and gasoline blendstocks product margin was $61.5 million in the third quarter of 2025 compared with $43.0 million in the same period of 2024. Product margin from distillates and other oils was $16.5 million in the third quarter of 2025 compared with $28.1 million in the same period of 2024. Commercial segment product margin was $7.0 million in the third quarter of 2025 compared with $9.5 million in the same period of 2024. Total sales were $4.7 billion in the third quarter of 2025 compared with $4.4 billion in the same period of 2024. Wholesale segment sales were $3.1 billion in the third quarter of 2025 compared with $2.7 billion in the same period of 2024. GDSO segment sales were $1.3 billion in the third quarter of 2025 compared with $1.4 billion in the same period of 2024. Commercial segment sales were $297.8 million in the third quarter of 2025 compared with $277.1 million in the third quarter of 2024. Total volume was 1.9 billion gallons in the third quarter of 2025 compared with 1.7 billion gallons in the same period of 2024. Wholesale segment volume was 1.4 billion gallons in the third quarter of 2025 compared with 1.2 billion gallons in the same period of 2024. GDSO volume was 390.8 million gallons in the third quarter of 2025 compared with 412.7 million gallons in the same period of 2024. Commercial segment volume was 149.2 million gallons in the third quarter of 2025 compared with 122.6 million gallons in the same period of 2024. Recent Developments Global announced a cash distribution of $0.7550 per unit ($3.02 per unit on an annualized basis) on all of its outstanding common units from July 1, 2025 through September 30, 2025. The distribution will be paid on November 14, 2025 to unitholders of record as of the close of business on November 10, 2025. Financial Results Conference Call Management will review the Partnership's third-quarter 2025 financial results in a teleconference call for analysts and investors today. Please plan to dial in to the call at least 10 minutes prior to the start time. The call also will be webcast live and archived on Global Partners' website, https://ir.globalp.com About Global Partners LP Building on a legacy that began more than 90 years ago, Global Partners has evolved into a Fortune 500 company and industry-leading integrated owner, supplier, and operator of liquid energy terminals, fueling locations, and guest-focused retail experiences. Global operates or maintains dedicated storage at 55 liquid energy terminals-with connectivity to strategic rail, pipeline, and marine assets-spanning from Maine to Florida and into the U.S. Gulf States. Through this extensive network, the company distributes gasoline, distillates, residual oil, and renewable fuels to wholesalers, retailers, and commercial customers. In addition, Global owns, operates and/or supplies approximately 1,700 retail locations across the Northeast states, the Mid-Atlantic, and Texas, providing the fuels people need to keep them on the go at their unique guest-focused convenience destinations. Recognized as one of Fortune's Most Admired Companies, Global Partners is embracing progress and diversifying to meet the needs of the energy transition. Global Partners, a master limited partnership, trades on the New York Stock Exchange under the ticker symbol "GLP." For additional information, visit www.globalp.com. Use of Non-GAAP Financial Measures Product Margin Global Partners views product margin as an important performance measure of the core profitability of its operations. The Partnership reviews product margin monthly for consistency and trend analysis. Global Partners defines product margin as product sales minus product costs. Product sales primarily include sales of unbranded and branded gasoline, distillates, residual oil, renewable fuels and crude oil, as well as convenience store and prepared food sales, gasoline station rental income and revenue generated from logistics activities when the Partnership engages in the storage, transloading and shipment of products owned by others. Product costs include the cost of acquiring products and all associated costs including shipping and handling costs to bring such products to the point of sale as well as product costs related to convenience store items and costs associated with logistics activities. The Partnership also looks at product margin on a per unit basis (product margin divided by volume). Product margin is a non-GAAP financial measure used by management and external users of the Partnership's consolidated financial statements to assess its business. Product margin should not be considered an alternative to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, product margin may not be comparable to product margin or a similarly titled measure of other companies. EBITDA and Adjusted EBITDA EBITDA and adjusted EBITDA are non-GAAP financial measures used as supplemental financial measures by management and may be used by external users of Global Partners' consolidated financial statements, such as investors, commercial banks and research analysts, to assess the Partnership's: compliance with certain financial covenants included in its debt agreements; financial performance without regard to financing methods, capital structure, income taxes or historical cost basis; ability to generate cash sufficient to pay interest on its indebtedness and to make distributions to its partners; operating performance and return on invested capital as compared to those of other companies in the wholesale, marketing, storing and distribution of refined petroleum products, gasoline blendstocks, renewable fuels, crude oil and propane, and in the gasoline stations and convenience stores business, without regard to financing methods and capital structure; and viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities. Adjusted EBITDA is EBITDA further adjusted for gains or losses on the sale and disposition of assets, goodwill and long-lived asset impairment charges and Global's proportionate share of EBITDA related to its Spring Partners Retail LLC joint venture, which is accounted for using the equity method. EBITDA and adjusted EBITDA should not be considered as alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and adjusted EBITDA exclude some, but not all, items that affect net income, and these measures may vary among other companies. Therefore, EBITDA and adjusted EBITDA may not be comparable to similarly titled measures of other companies. Distributable Cash Flow and Adjusted Distributable Cash Flow Distributable cash flow is an important non-GAAP financial measure for the Partnership's limited partners since it serves as an indicator of Global's success in providing a cash return on their investment. Distributable cash flow as defined by the Partnership's partnership agreement (the "partnership agreement") is net income plus depreciation and amortization minus maintenance capital expenditures, as well as adjustments to eliminate items approved by the audit committee of the board of directors of the Partnership's general partner that are extraordinary or non-recurring in nature and that would otherwise increase distributable cash flow. Distributable cash flow as used in the partnership agreement also determines Global's ability to make cash distributions on its incentive distribution rights. The investment community also uses a distributable cash flow metric similar to the metric used in the partnership agreement with respect to publicly traded partnerships to indicate whether or not such partnerships have generated sufficient earnings on a current or historical level that can sustain distributions on preferred or common units or support an increase in quarterly cash distributions on common units. The partnership agreement does not permit adjustments for certain non-cash items, such as net losses on the sale and disposition of assets and goodwill and long-lived asset impairment charges. Adjusted distributable cash flow is a non-GAAP financial measure intended to provide management and investors with an enhanced perspective of the Partnership's financial performance. Adjusted distributable cash flow is distributable cash flow (as defined in the partnership agreement) further adjusted for Global's proportionate share of distributable cash flow related to its Spring Partners Retail LLC joint venture, which is accounted for using the equity method. Adjusted distributable cash flow is not used in the partnership agreement to determine the Partnership's ability to make cash distributions and may be higher or lower than distributable cash flow as calculated under the partnership agreement. Distributable cash flow and adjusted distributable cash flow should not be considered as alternatives to net income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, the Partnership's distributable cash flow and adjusted distributable cash flow may not be comparable to distributable cash flow or similarly titled measures of other companies. Forward-looking Statements Certain statements and information in this press release may constitute "forward-looking statements." The words "believe," "expect," "anticipate," "plan," "intend," "foresee," "should," "would," "could" or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Global's current expectations and beliefs concerning future developments and their potential effect on the Partnership. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting the Partnership will be those that it anticipates. Forward-looking statements involve significant risks and uncertainties (some of which are beyond the Partnership's control) including, without limitation, uncertainty around the timing of an economic recovery in the United States which will impact the demand for the products we sell and the services that we provide, and assumptions that could cause actual results to differ materially from the Partnership's historical experience and present expectations or projections. We believe these assumptions are reasonable given currently available information. Our assumptions and future performance are subject to a wide range of business risks, uncertainties and factors, which are described in our filings with the Securities and Exchange Commission (SEC). For additional information regarding known material factors that could cause actual results to differ from the Partnership's projected results, please see Global's filings with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Global undertakes 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. View source version on businesswire.com: https://www.businesswire.com/news/home/20251107841374/en/ back
Enbridge Reports Strong Third Quarter Results, Announces Accretive Investments and Reaffirms 2025 Financial Guidance
Enbridge Reports Strong Third Quarter Results, Announces Accretive Investments and Reaffirms 2025 Financial Guidance CALGARY, AB, Nov. 7, 2025 /PRNewswire/ - Enbridge Inc. (Enbridge or the Company) (TSX: ENB) (NYSE: ENB) today reported third quarter 2025 financial results, reaffirmed its 2025 financial guidance and provided a quarterly business update. Highlights (All financial figures are unaudited and in Canadian dollars unless otherwise noted. * identifies non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.) Third quarter GAAP earnings attributable to common shareholders of $0.7 billion or $0.30 per common share, compared with GAAP earnings attributable to common shareholders of $1.3 billion or $0.59 per common share in 2024 Adjusted earnings* of $1.0 billion or $0.46 per common share*, compared with $1.2 billion or $0.55 per common share in 2024 Adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA)* of $4.3 billion, compared with $4.2 billion in 2024 Cash provided by operating activities of $2.9 billion, compared with $3.0 billion in 2024 Distributable cash flow (DCF)* of $2.6 billion compared with the same amount in 2024 Reaffirmed 2025 full year financial guidance and multi-year financial outlook Sanctioned Southern Illinois Connector connecting Wood River to Patoka, IL, creating 100 kbpd of long-haul, contracted service to Nederland, TX via a 30 kbpd expansion on Express-Platte and utilizing 70 kbpd of existing capacity on Spearhead for US$0.5B Sanctioned expansion of the Canyon System Pipeline to serve bp's Tiber Offshore development for an incremental US$0.3B Sanctioned expansions of Egan and Moss Bluff natural gas storage facilities to support increasing natural gas demand in the USGC, adding 23 Bcf of incremental capacity for US$0.5B, to be delivered in stages from 2028-2033 Sanctioned the Algonquin Gas Transmission (AGT) Enhancement project to serve rising local natural gas demand for US$0.3B Sanctioned the Eiger Express Pipeline, alongside our joint venture partners, adding up to 2.5 Bcf/d of Permian takeaway within Matterhorn Express' existing pathway Reached positive rate case settlements at Enbridge Gas North Carolina and at Enbridge Gas Utah Sanctioned the Pelican CO2 Hub in Louisiana in partnership with Occidental Petroleum Corporation (Oxy) for US$0.3B Exited the quarter with Debt-to-EBITDA* of 4.8x CEO COMMENT Greg Ebel, President and CEO commented the following: "Energy demand continues to grow in North America and beyond. Throughout North America, we have an abundant supply of natural resources. Enbridge is the only company with a large incumbent footprint positioned to deliver gas, liquids and renewable power to customers across the continent and to new markets. Our 'all-of-the-above' approach enables us to capitalize on growing demand for all forms of energy, providing first-choice service for customers both today and in the future. "During the quarter, high utilization across our systems resulted in record Q3 EBITDA, and we're well set up to achieve our financial guidance for the 20th consecutive year. We also sanctioned $3 billion of attractive projects, leveraging our footprint, scale and diversification. "In Liquids, we reached a positive final investment decision on the Southern Illinois Connector project, which is backed by 100 kbpd of long-term contracts for full-path service from Western Canada to Nederland, Texas. The project includes a 30 kbpd expansion of Express-Platte and 56 miles of new pipe that connects Wood River to Patoka, Illinois, as well as utilization of 70 kbpd of existing capacity on Spearhead Pipeline. Looking ahead, we are also advancing another 400 kbpd of expansion opportunities to add incremental Western Canadian Sedimentary Basin egress to key North American refining markets. Mainline Optimization Phase 1, which will add 150 kbpd, is in the final stages of customer negotiations and we expect to make an announcement this quarter. The team is also actively advancing Mainline Optimization Phase 2. Utilizing the existing Mainline system, in combination with the Dakota Access Pipeline[1], Mainline Optimization Phase 2 would add another 250 kbpd of incremental full-path capacity before the end of the decade. Enbridge will continue to provide quick-cycle, capital efficient expansions to support our customers' growth. "In Gas Transmission, we sanctioned $2 billion of investment across our footprint to support growing natural gas, power, and LNG demand. Following two successful gas storage open seasons, we are proceeding with a 7 bcf expansion of Moss Bluff and a 16 bcf expansion of Egan. Upon completion, these projects will further enhance Enbridge's storage presence which already provides critical flexibility for the tightening U.S. Gulf Coast gas market. We are also expanding the Canyon System offshore pipeline project that was previously announced to support bp's Kaskida development, tying to bp's recently sanctioned Tiber development. Earlier in the quarter, we announced the AGT Enhancement, which is expected to deliver approximately 75 Mmcf/d of incremental natural gas under long-term contracts to the U.S. Northeast. This US$0.3 billion project is designed to increase reliable supply and improve affordability by reducing winter price volatility for customers. Finally, through our Matterhorn joint venture, we reached a final investment decision on the Eiger Express Pipeline, an up to 2.5 bcf/d pipeline from the Permian Basin to the Katy, Texas area to serve the growing U.S. Gulf Coast LNG market. "In Gas Distribution, we completed our first full year of ownership of the three U.S. gas utilities acquired in 2024. We remain very pleased with their performance and have now completed rate cases in all three major jurisdictions. During the third quarter, Enbridge Gas North Carolina and Enbridge Gas Utah both reached positive rate settlements, and new rates are effective November 1, 2025, and expected to be effective January 1, 2026, respectively. As data center investment continues to accelerate, we see more avenues for growth in our utility franchise than originally anticipated. Our Gas Distribution teams are now advancing more than $4 billion of data center and power generation opportunities across 60 different projects to serve our customers' growing energy needs through the end of the decade. "In Renewable Power, we have more than 1.4 GW of solar projects expected to enter service through 2027. Enbridge will continue to invest opportunistically, providing power to a growing list of technology and data center players that include Meta and Amazon. We are continuing to monitor the policy environment, but don't expect any of our sanctioned or late-stage development projects to be impacted by legislative changes to renewable tax credits. "All four of our premier franchises continue to deliver strong results and generate new growth opportunities, reinforcing our ability to win in multiple ways. Year-to-date, Enbridge has added approximately $7 billion to its secured project backlog. We now have $35 billion of sanctioned growth capital entering service through 2030, as we continue to add visibility to our post-2026 5% annual growth outlook for EBITDA, EPS and DCF/share. Looking ahead, we remain committed to disciplined capital allocation, protecting the balance sheet and growing our dividend. We believe that our formula of steady cash flow growth and annual dividend increases will continue to drive strong shareholder returns and positions Enbridge as a first-choice investment." __________________________________ 1 The Dakota Access Pipeline is a joint venture owned 38.2% by Energy Transfer, 27.6% by Enbridge, 25% by Phillips 66, and 9.2% by MPLX FINANCIAL RESULTS SUMMARY Financial results for the three and nine months ended September 30, 2025 and 2024 are summarized in the table below: Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (Unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions) GAAP Earnings attributable to common shareholders 682 1,293 5,120 4,560 GAAP Earnings per common share 0.30 0.59 2.34 2.12 Cash provided by operating activities 2,868 2,973 9,159 8,938 Adjusted EBITDA1 4,267 4,201 14,739 13,490 Adjusted Earnings1 997 1,194 4,657 4,397 Adjusted Earnings per common share1 0.46 0.55 2.14 2.05 Distributable Cash Flow1 2,566 2,596 9,246 8,917 Weighted average common shares outstanding 2,181 2,177 2,180 2,147 1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices. GAAP earnings attributable to common shareholders for the third quarter of 2025 decreased by $0.6 billion, or $0.29 per share, compared with the same period in 2024. This decrease was primarily due to non-cash, unrealized changes in the value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks as well as the quarterly operating performance factors discussed below. The period-over-period comparability of GAAP earnings attributable to common shareholders is impacted by certain unusual, infrequent or other non-operating factors which are noted in the reconciliation schedule included in Appendix A of this news release. Refer to the Company's Management's Discussion & Analysis for Q3 2025 filed in conjunction with the quarter-end financial statements for a detailed discussion of GAAP financial results. Adjusted EBITDA in the third quarter of 2025 increased by $0.1 billion compared with the same period in 2024. This was due primarily to contributions from the acquisition of Enbridge Gas North Carolina in the fourth quarter of 2024, favorable contracting and rate case settlements on U.S. Gas Transmission assets, and placing Texas Eastern Venice Extension in service. These factors were partially offset by lower contributions from the Liquids Pipelines Gulf Coast and Mid-Continent segment. Adjusted earnings in the third quarter of 2025 decreased by $0.2 billion, or $0.09 per share, compared with the same period in 2024, due to EBITDA factors discussed above offset by higher financing costs and depreciation expense from the acquisition of Enbridge Gas North Carolina and other capital investments. DCF for the third quarter of 2025 was comparable with the same period in 2024, primarily due to EBITDA factors discussed above, offset by higher financing costs. Detailed financial information and analysis can be found below under Third Quarter 2025 Financial Results. FINANCIAL OUTLOOK The Company reaffirms its 2025 financial guidance for adjusted EBITDA between $19.4 billion and $20.0 billion and DCF per share between $5.50 and $5.90. The Company also reaffirms its financial outlook presented at its Investor Day on March 4, 2025; 2023 to 2026 near-term growth of 7-9% for adjusted EBITDA, 4-6% for adjusted earnings per share (EPS) and approximately 3% for DCF per share; and Post 2026; adjusted EBITDA, EPS and DCF per share are all expected to grow by approximately 5% annually. Enbridge does not expect tariffs to have a material impact on our current operations or deployment of capital, though the Company will continue to monitor developments. FINANCING UPDATE In September 2025, Enbridge Inc. completed a $1.0 billion offering consisting of 30-year hybrid subordinated notes. Proceeds from this offering were used to pay down existing indebtedness, fund capital expenditures, and for general corporate purposes. In September 2025, Enbridge Gas Inc. completed an $800 million medium-term note offering consisting of $500 million of 10-year notes and $300 million of 30-year notes. Proceeds from these offerings were used to refinance maturing debt at Enbridge Gas Inc. The Company's rolling 12 month Debt-to-EBITDA metric at the end of the quarter was 4.8x. SECURED GROWTH PROJECT EXECUTION UPDATE Enbridge added approximately $3 billion of new projects to its secured growth backlog this quarter: Southern Illinois Connector; US$0.5B Canyon System Pipelines; US$0.3B USGC Storage Growth Program; US$0.5B AGT Enhancement; US$0.3B Pelican CO2 Hub; US$0.3B Eiger Express Pipeline The secured growth backlog now sits at approximately $35 billion. Financing of the secured growth program is expected to be provided through the Company's anticipated $9-10 billion of annual growth capital investment capacity. THIRD QUARTER BUSINESS UPDATES Liquids Pipelines: Southern Illinois Connector Enbridge has sanctioned the construction of the Southern Illinois Connector, connecting the Platte Pipeline to our jointly owned Energy Transfer Crude Oil Pipeline (ETCOP). Once complete, the project will offer 100 kbpd of long-haul, contracted service to shippers, including 30 kbpd of incremental egress out of the WCSB via an expansion on Express-Platte and utilizing 70 kbpd of existing capacity on Spearhead Pipeline. A new 24-inch pipeline will connect 56 miles from Wood River, Illinois to Patoka, Illinois, offering service to Nederland, Texas in the Gulf Coast and will be 50% jointly owned with Energy Transfer. In addition, new pump stations will add incremental capacity to the Platte system. The 100 kbpd is secured under long-term take-or-pay agreements with investment grade customers. The project is expected to cost US$0.5 billion and enter service in 2028. Liquids Pipelines: Pelican CO2 Hub Enbridge has entered into a definitive agreement with a subsidiary of Oxy to design, construct and operate a 2.3 MTPA CO2 transportation and sequestration hub in the Louisiana Mississippi River corridor. The transaction has been structured as a 50/50 joint venture, with Enbridge managing the pipeline and Oxy managing the sequestration portions of the CO2 Hub. The project is supported by a 25-year take-or-pay offtake agreement with an investment grade counterparty. Enbridge expects its share of the project to cost approximately US$0.3 billion, and enter service in 2029. Gas Transmission: Tiber Offshore Extension to Canyon Pipelines Enbridge has expanded its Canyon System Pipelines project to serve bp's Tiber offshore production facility in the U.S. Gulf Coast. This project will include both crude oil and natural gas pipeline extensions and is underpinned by long-term contracts. The Canyon Systems Pipelines project was previously sanctioned to support bp's Kaskida offshore development and now includes 24/26" oil pipeline which will connect to Shell Pipeline Company LP's Green Canyon 19 Platform and a 12" gas pipeline connecting to Enbridge's existing Magnolia Gas Gathering Pipeline for both Tiber and Kaskida. The project extension is expected to cost US$0.43 billion, bringing the combined system cost to US$1.0 billion, and enter service in 2029. Gas Transmission: USGC Storage Growth Program Enbridge has sanctioned the expansion of two natural gas storage facilities in the US Gulf Coast to support the growing power demand and LNG market. Egan Storage will be expanded over two phases, with the first 8 Bcf phase expected to enter service in 2030. Construction will involve the addition of nearby caverns, adding 16 Bcf of total capacity by 2033. Enbridge has also sanctioned an expansion of Moss Bluff Storage, which is expected to increase storage capability by 7 Bcf and enter service in 2028. Together, these expansions will offer vital storage capacity to Gulf Coast LNG and power generation facilities during periods of high demand. The total cost of both projects is expected to be US$0.5 billion. Gas Transmission: Eiger Express Pipeline Enbridge announced it would participate in the construction of the Eiger Express Pipeline via its interest in the Matterhorn joint venture. Eiger is an up to 2.5 Bcf/d pipeline from the Permian Basin to the Katy area and will serve the growing U.S. Gulf Coast LNG market. The project is complementary to the Whistler JV assets and is backed by long-term contracts with predominantly investment grade counterparties. The project is expected to enter service in 2028. Gas Transmission: AGT Enhancement Enbridge has sanctioned the Algonquin Gas Transmission Reliable Affordable Resilient Enhancement project (AGT Enhancement), which will deliver approximately 75 Mmcf/d of incremental natural gas to the U.S. Northeast under long-term contracts with investment-grade counterparties. The expanded system will enhance supply reliability and improve affordability by reducing winter price volatility for customers. The project is expected to cost US$0.3 billion and enter service in 2029. Gas Distribution & Storage: Enbridge Gas North Carolina Rate Settlement Enbridge has filed a joint stipulated settlement on the Enbridge Gas North Carolina rate case and is pending approval from the North Carolina Utilities Commission. Interim rates were approved and effective November 1, 2025. As a result of the settlement, return on equity increased from 9.60% to 9.65% and equity thickness increased from 52% to 54% resulting in an increase to the annual revenue requirement of $34 million. Gas Distribution & Storage: Enbridge Gas Utah Rate Settlement Enbridge has filed a settlement on the Enbridge Gas Utah rate case, increasing the annual revenue requirement by $62 million. A decision on the filing is expected from the Public Service Commission of Utah before the end of the year with new rates expected to take effect on January 1, 2026. THIRD QUARTER 2025 FINANCIAL RESULTS GAAP Segment EBITDA and Cash Flow from Operations Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Liquids Pipelines 2,283 2,325 7,207 7,179 Gas Transmission 1,270 1,146 4,185 4,506 Gas Distribution and Storage 560 522 2,670 1,854 Renewable Power Generation 89 102 421 497 Eliminations and Other (379) 295 828 (502) EBITDA 1 3,823 4,390 15,311 13,534 Earnings attributable to common shareholders 682 1,293 5,120 4,560 Cash provided by operating activities 2,868 2,973 9,159 8,938 1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. For purposes of evaluating performance, the Company makes adjustments to GAAP reported earnings, segment EBITDA and cash flow provided by operating activities for unusual, infrequent or other non-operating factors, which allow management and investors to more accurately compare the Company's performance across periods, normalizing for factors that are not indicative of underlying business performance. Tables incorporating these adjustments follow below. Schedules reconciling EBITDA, adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per share and DCF to their closest GAAP equivalent are provided in the Appendices to this news release. Adjusted EBITDA By Segment Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Liquids Pipelines 2,307 2,343 7,264 7,259 Gas Transmission 1,262 1,154 4,085 3,510 Gas Distribution and Storage 560 522 3,000 1,854 Renewable Power Generation 100 86 461 512 Eliminations and Other 38 96 (71) 355 Adjusted EBITDA1 4,267 4,201 14,739 13,490 Adjusted Earnings1 997 1,194 4,657 4,397 1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. Adjusted EBITDA generated from U.S. dollar denominated businesses was translated to Canadian dollars at a higher average exchange rate (C$1.38/US$) in the third quarter of 2025 when compared with the same quarter in 2024 (C$1.36/US$). A significant portion of U.S. dollar earnings are hedged under the Company's enterprise-wide financial risk management program. The hedge settlements are reported within Eliminations and Other. Liquids Pipelines Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Mainline System 1,343 1,348 4,096 4,003 Regional Oil Sands System 236 223 729 693 Gulf Coast and Mid-Continent Systems1 319 364 1,052 1,227 Other Systems2 409 408 1,387 1,336 Adjusted EBITDA3 2,307 2,343 7,264 7,259 1 Consists of Flanagan South Pipeline, Seaway Pipeline, Gray Oak Pipeline, Cactus II Pipeline, Enbridge Ingleside Energy Center, and others. 2 Other consists of Southern Lights Pipeline, Express-Platte System, Bakken System, and others. 3 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. Liquids Pipelines adjusted EBITDA decreased $36 million compared with the third quarter of 2024, primarily related to: lower contributions from the Flanagan South Pipeline and Spearhead Pipeline. Gas Transmission Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) U.S. Gas Transmission 1,070 946 3,339 2,786 Canadian Gas Transmission 122 101 439 395 Other1 70 107 307 329 Adjusted EBITDA2 1,262 1,154 4,085 3,510 1 Other consists of Tomorrow RNG, Gulf Offshore assets, our investment in DCP Midstream, and others. 2 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. Gas Transmission adjusted EBITDA increased $108 million compared with the third quarter of 2024, primarily related to: favorable contracting and successful rate case settlements on certain U.S. Gas Transmission assets; contributions from the Venice Extension project which entered service in the fourth quarter of 2024; and contributions from the acquisitions of an interest in the Matterhorn Express Pipeline in the second quarter of 2025 and the Delaware Basin Residue Pipeline in the fourth quarter of 2024; partially offset by lower contributions from renewable natural gas assets due to lower Renewable Identification Number (RIN) pricing and timing of RIN sales. Gas Distribution and Storage Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Enbridge Gas Ontario1 292 297 1,660 1,370 U.S. Gas Utilities1 258 217 1,308 445 Other 10 8 32 39 Adjusted EBITDA2 560 522 3,000 1,854 1 Enbridge Gas Inc. doing business as Enbridge Gas Ontario. U.S. Gas Utilities consist of East Ohio Gas Company (doing business as Enbridge Gas Ohio), Questar Gas Company (doing business as Enbridge Gas Utah) and Public Service Company of North Carolina (doing business as Enbridge Gas North Carolina). 2 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. Adjusted EBITDA for Enbridge Gas Ontario, Enbridge Gas Utah and Enbridge Gas North Carolina typically follows a seasonal profile. EBITDA is generally highest in the first and fourth quarters of the year. Seasonal profiles for Enbridge Gas Ontario, Enbridge Gas Utah and Enbridge Gas North Carolina reflect greater volumetric demand during the heating season and the magnitude of the seasonal adjusted EBITDA fluctuations will vary from year-to-year in Ontario reflecting the impact of colder or warmer than normal weather on distribution volumes. Enbridge Gas Ohio's earnings are largely decoupled from volumes and less impacted by weather fluctuations. Enbridge Gas Utah and Enbridge Gas North Carolina have revenue decoupling mechanisms that are not impacted by weather or gas volume variability, but revenues are shaped to align with the seasonal usage profile. Enbridge Gas Ontario revenue is affected by weather variability. Adjusted EBITDA for the third quarter increased $38 million compared with the third quarter of 2024 primarily related to: full-quarter contributions from the acquisition of Enbridge Gas North Carolina; and increased revenue requirement from contributions from capital investments at Enbridge Gas Ohio. When compared with the normal forecast embedded in rates, the impact of weather to Adjusted EBITDA for Enbridge Gas Ontario was negligible in both the third quarter of 2025 and the third quarter of 2024. Renewable Power Generation Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Adjusted EBITDA1 100 86 461 512 1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. Renewable Power Generation adjusted EBITDA increased $14 million compared with the third quarter of 2024 primarily related to: higher contributions related to higher revenue from sale of renewable energy certificates and Orange Grove Solar entering service. Eliminations and Other Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Operating and administrative recoveries 89 96 314 381 Realized foreign exchange hedge settlement (loss)/gain (51) - (385) (26) Adjusted EBITDA1 38 96 (71) 355 1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices. Operating and administrative recoveries captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) inclusive of amounts recovered from business units for the provision of those services. U.S. dollar denominated earnings within operating segment results are translated at average foreign exchange rates during the quarter, and the impact of settlements made under the Company's enterprise foreign exchange hedging program are captured in this corporate segment. Eliminations and Other adjusted EBITDA decreased $58 million compared with the third quarter of 2024 due to: higher realized foreign exchange losses on hedge settlements in 2025. Distributable Cash Flow Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars; number of shares in millions) Liquids Pipelines 2,307 2,343 7,264 7,259 Gas Transmission 1,262 1,154 4,085 3,510 Gas Distribution and Storage 560 522 3,000 1,854 Renewable Power Generation 100 86 461 512 Eliminations and Other 38 96 (71) 355 Adjusted EBITDA1,3 4,267 4,201 14,739 13,490 Maintenance capital (303) (290) (848) (748) Interest expense1 (1,247) (1,133) (3,696) (3,228) Current income tax1 (154) (176) (771) (597) Distributions to noncontrolling interests1 (81) (79) (276) (245) Cash distributions in excess of equity earnings1 138 109 335 347 Preference share dividends (105) (99) (311) (287) Other receipts of cash not recognized in revenue2 36 53 89 89 Other non-cash adjustments 15 10 (15) 96 DCF3 2,566 2,596 9,246 8,917 Weighted average common shares outstanding 2,181 2,177 2,180 2,147 1 Presented net of adjusting items. 2 Consists of cash received, net of revenue recognized, for contracts under make-up rights and similar deferred revenue arrangements. 3 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices. Third quarter 2025 DCF decreased $30 million compared with the same period of 2024 primarily due to operational factors discussed above contributing to higher adjusted EBITDA, offset by: higher debt principal, resulting in higher interest expense; and higher maintenance capital relating to recently acquired and in-service assets. Adjusted Earnings Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars; except per share amounts) Adjusted EBITDA1,2 4,267 4,201 14,739 13,490 Depreciation and amortization (1,453) (1,368) (4,353) (3,919) Interest expense2 (1,256) (1,150) (3,730) (3,261) Income taxes2 (397) (363) (1,535) (1,490) Noncontrolling interests2 (58) (27) (153) (136) Preference share dividends (106) (99) (311) (287) Adjusted earnings1 997 1,194 4,657 4,397 Adjusted earnings per common share1 0.46 0.55 2.14 2.05 1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices. 2 Presented net of adjusting items. Adjusted earnings decreased $197 million and adjusted earnings per share decreased by $0.09 when compared with the third quarter in 2024 primarily due to higher adjusted EBITDA driven by operational factors discussed above, offset by: higher depreciation and amortization related to recently acquired and in-service assets; higher debt principal, resulting in higher interest expense; and higher non-controlling interests related to the sale of interest in the Westcoast system. CONFERENCE CALL Enbridge will host a conference call and webcast on November 7, 2025 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide a business update and review 2025 third quarter results. Analysts, members of the media and other interested parties can access the call toll free at 1-800-606-3040. The call will be audio webcast live at https://events.q4inc.com/attendee/209607087. It is recommended that participants dial in or join the audio webcast fifteen minutes prior to the scheduled start time. A webcast replay will be available soon after the conclusion of the event and a transcript will be posted to the website. The replay will be available for seven days after the call toll-free 1-(800)-606-3040 (conference ID: 9581867). The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge's media and investor relations teams will be available after the call for any additional questions. DIVIDEND DECLARATION The Board of Directors has declared the following quarterly dividends. All dividends are payable on December 1, 2025 to shareholders of record on November 14, 2025. Dividend per share Common Shares $0.94250 Preference Shares, Series A $0.34375 Preference Shares, Series B $0.32513 Preference Shares, Series D $0.33825 Preference Shares, Series F $0.34613 Preference Shares, Series G1 $0.32411 Preference Shares, Series H $0.38200 Preference Shares, Series I2 $0.29980 Preference Shares, Series L US$0.36612 Preference Shares, Series N $0.41850 Preference Shares, Series P $0.36988 Preference Shares, Series R $0.39463 Preference Shares, Series 1 US$0.41898 Preference Shares, Series 3 $0.33050 Preference Shares, Series 43 $0.31601 Preference Shares, Series 5 US$0.41769 Preference Shares, Series 7 $0.37425 Preference Shares, Series 9 $0.35450 Preference Shares, Series 11 $0.34231 Preference Shares, Series 13 $0.33719 Preference Shares, Series 154 $0.35163 Preference Shares, Series 19 $0.38825 1 The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.32411 from $0.32515 on September 1, 2025 due to the reset of the dividend on a quarterly basis. 2 The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.29980 from $0.30058 on September 1, 2025 due to the reset of the dividend on a quarterly basis. 3 The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.31601 from $0.31696 on September 1, 2025 due to the reset of the dividend on a quarterly basis. 4 The quarterly dividend per share paid on Preference Shares, Series 15 was increased to $0.35163 from $0.18644 on September 1, 2025 due to the reset of the annual dividend on September 1, 2025. FORWARD-LOOKING INFORMATION Forward-looking information, or forward-looking statements, have been included in this news release to provide information about Enbridge and its subsidiaries and affiliates, including management's assessment of Enbridge and its subsidiaries' future plans and operations. This information may not be appropriate for other purposes. Forward looking statements are typically identified by words such as ''anticipate'', ''believe'', "estimate'', ''expect'', ''forecast'', ''intend'', "likely", ''plan'', ''project'', ''target'', and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including our strategic priorities and enablers; 2025 financial guidance and near term outlook, including projected DCF per share, EPS and adjusted EBITDA and expected growth thereof; expected dividends, dividend growth and payout policy; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquefied natural gas (LNG), renewable natural gas (RNG) and renewable energy; industry and market conditions; anticipated utilization of our assets; expected EBITDA and adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected DCF and DCF per share; expected future cash flows; expected shareholder returns and asset returns; expected performance of Enbridge's businesses; financial strength, capacity and flexibility; financing costs and plans; expectations on leverage, including Debt-to EBITDA ratio; expectations on sources of liquidity and sufficiency of financial resources; expected costs, benefits and in-service dates related to announced projects and projects under construction; investable capacity and capital allocation priorities; impact of weather and seasonality; expected future growth, development and expansion opportunities, including with respect to the Southern Illinois Connector, Canyon System Pipelines expansion, USGC Storage Growth Program, AGT Enhancement and Pelican CO2 Hub; the characteristics, anticipated benefits, financing and timing of our acquisitions, dispositions and other transactions, including the Acquisitions; government trade policies, as well as possible impacts of potential and announced tariffs, duties, fees, economic sanctions, or other trade measures and the timing thereof; expected future actions and decisions of regulators and courts and the timing and impact thereof; and toll and rate case discussions and proceedings and anticipated outcomes, timelines and impacts therefrom, including those relating to the Gas Distribution and Storage business. Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, demand for, export of and prices of crude oil, natural gas, NGL, LNG, RNG and renewable energy; anticipated utilization of our assets; exchange rates; inflation; interest rates; tariffs and trade policies; availability and price of labour and construction materials; the stability of our supply chain; operational reliability and performance; maintenance of support and regulatory approvals for our projects and transactions; anticipated in-service dates; weather; the timing, terms and closing of announced and potential acquisitions, dispositions and other transactions and projects and the anticipated benefits thereof; governmental legislation; litigation; credit ratings; capital project funding; hedging program; expected EBITDA and adjusted EBITDA; expected earnings/ (loss) and adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected future DCF and DCF per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; and general economic and competitive conditions. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG, RNG and renewable energy and the prices of these commodities are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation, interest rates and tariffs impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs and are therefore inherent in all forward-looking statements. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the stability of our supply chain; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather; and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes. Enbridge's forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities; operating performance; legislative and regulatory parameters and decisions; litigation; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom, including the Acquisitions; evolving government trade policies, including potential and announced tariffs, duties, fees, economic sanctions or other trade measures; operational dependence on third parties; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; global geopolitical conditions; political decisions; public opinion; dividend policy; changes in tax laws and tax rates; exchange rates; interest rates; inflation; commodity prices; access to and cost of capital; our ability to maintain adequate insurance in the future at commercially reasonable rates and terms; and supply of, demand for, and prices of commodities and other alternative energy, including but not limited to those risks and uncertainties discussed in this news release and in Enbridge's other filings with Canadian and U.S. securities regulators. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty, as these are interdependent, and our future course of action depends on management's assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statement made in this news release or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements. ABOUT ENBRIDGE INC. At Enbridge, we safely connect millions of people to the energy they rely on every day, fueling quality of life through our North American natural gas, oil and renewable power networks and our growing European offshore wind portfolio. We're investing in modern energy delivery infrastructure to sustain access to secure, affordable energy and building on more than a century of operating conventional energy infrastructure and two decades of experience in renewable power. We're advancing new technologies including hydrogen, renewable natural gas, and carbon capture and storage. Headquartered in Calgary, Alberta, Enbridge's common shares trade under the symbol ENB on the Toronto (TSX) and New York (NYSE) stock exchanges. To learn more, visit us at enbridge.com. None of the information contained in, or connected to, Enbridge's website is incorporated in or otherwise forms part of this news release. FOR FURTHER INFORMATION PLEASE CONTACT: Enbridge Inc. - Media Enbridge Inc. - Investment Community Jesse Semko Rebecca Morley Toll Free: (888) 992-0997 Toll Free: (800) 481-2804 Email: media@enbridge.com Email: investor.relations@enbridge.com NON-GAAP RECONCILIATIONS APPENDICES This news release contains references to EBITDA, adjusted EBITDA, adjusted earnings, adjusted earnings per common share (EPS) and DCF per share. Management believes the presentation of these metrics gives useful information to investors and shareholders, as they provide increased transparency and insight into the performance of the Company. EBITDA represents earnings before interest, tax, depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating factors on both a consolidated and segmented basis. Management uses EBITDA and adjusted EBITDA to set targets and to assess the performance of the Company and its business units. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, infrequent or other non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes and noncontrolling interests on a consolidated basis. Management uses adjusted earnings as another measure of the Company's ability to generate earnings and uses EPS to assess performance of the Company. DCF is defined as cash flow provided by operating activities before the impact of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests, preference share dividends and maintenance capital expenditures and further adjusted for unusual, infrequent or other non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target. This news release also contains references to Debt-to-EBITDA, a non-GAAP ratio which utilizes adjusted EBITDA as one of its components. Debt-to-EBITDA is used as a liquidity measure to indicate the amount of adjusted earnings to pay debt, as calculated on the basis of generally accepted accounting principles in the United States of America (U.S. GAAP), before covering interest, tax, depreciation and amortization. Reconciliations of forward-looking non-GAAP financial measures and non-GAAP ratios to comparable GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures and non-GAAP ratios is not available without unreasonable effort. Our non-GAAP financial measures and non-GAAP ratios described above are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. The tables below provide a reconciliation of the non-GAAP measures to comparable GAAP measures. APPENDIX A NON-GAAP RECONCILIATIONS - ADJUSTED EBITDA AND ADJUSTEDEARNINGS CONSOLIDATED EARNINGS Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Liquids Pipelines 2,283 2,325 7,207 7,179 Gas Transmission 1,270 1,146 4,185 4,506 Gas Distribution and Storage 560 522 2,670 1,854 Renewable Power Generation 89 102 421 497 Eliminations and Other (379) 295 828 (502) EBITDA 3,823 4,390 15,311 13,534 Depreciation and amortization (1,398) (1,317) (4,197) (3,783) Interest expense (1,262) (1,314) (3,777) (3,301) Income tax expense (316) (312) (1,679) (1,437) Earnings attributable to noncontrolling interests (59) (56) (227) (167) Preference share dividends (106) (98) (311) (286) Earnings attributable to common shareholders 682 1,293 5,120 4,560 ADJUSTED EBITDA TO ADJUSTED EARNINGS Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars; except per share amounts) Liquids Pipelines 2,307 2,343 7,264 7,259 Gas Transmission 1,262 1,154 4,085 3,510 Gas Distribution and Storage 560 522 3,000 1,854 Renewable Power Generation 100 86 461 512 Eliminations and Other 38 96 (71) 355 Adjusted EBITDA 4,267 4,201 14,739 13,490 Depreciation and amortization (1,453) (1,368) (4,353) (3,919) Interest expense (1,256) (1,150) (3,730) (3,261) Income tax expense (397) (363) (1,535) (1,490) Earnings attributable to noncontrolling interests (58) (27) (153) (136) Preference share dividends (106) (99) (311) (287) Adjusted earnings 997 1,194 4,657 4,397 Adjusted earnings per common share 0.46 0.55 2.14 2.05 EBITDA TO ADJUSTED EARNINGS Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars; except per share amounts) EBITDA 3,823 4,390 15,311 13,534 Adjusting items: Change in unrealized derivative fair value (gain)/loss 390 (271) (1,091) 742 Employee severance costs - - - 105 Gain on debt extinguishment - - (25) - Gain on sale of assets (16) - (130) (1,092) Realized hedge loss - - 139 - Asset impairment - - 330 - Other 70 82 205 201 Total adjusting items 444 (189) (572) (44) Adjusted EBITDA 4,267 4,201 14,739 13,490 Depreciation and amortization (1,398) (1,317) (4,197) (3,783) Interest expense (1,262) (1,312) (3,777) (3,298) Income tax expense (316) (312) (1,679) (1,437) Earnings attributable to noncontrolling interests (59) (56) (227) (167) Preference share dividends (106) (99) (311) (287) Adjusting items in respect of: Depreciation and amortization (55) (51) (156) (136) Interest expense 6 162 47 37 Income tax expense (81) (51) 144 (53) Earnings attributable to noncontrolling interests 1 29 74 31 Adjusted earnings 997 1,194 4,657 4,397 Adjusted earnings per common share 0.46 0.55 2.14 2.05 APPENDIX B NON-GAAP RECONCILIATION - ADJUSTED EBITDA TO SEGMENTEDEBITDA LIQUIDS PIPELINES Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Adjusted EBITDA 2,307 2,343 7,264 7,259 Change in unrealized derivative fair value gain/(loss) 16 26 54 20 Other (40) (44) (111) (100) Total adjustments (24) (18) (57) (80) EBITDA 2,283 2,325 7,207 7,179 GAS TRANSMISSION Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Adjusted EBITDA 1,262 1,154 4,085 3,510 Change in unrealized derivative fair value gain/(loss) - Commodity prices (9) 13 (30) (4) Gain on sale of assets 16 - 103 1,063 Other 1 (21) 27 (63) Total adjustments 8 (8) 100 996 EBITDA 1,270 1,146 4,185 4,506 GAS DISTRIBUTION AND STORAGE Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Adjusted EBITDA 560 522 3,000 1,854 Asset impairment - - (330) - Total adjustments - - (330) - EBITDA 560 522 2,670 1,854 RENEWABLE POWER GENERATION Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Adjusted EBITDA 100 86 461 512 Change in unrealized derivative fair value gain/(loss) - 26 105 (13) Realized hedge loss - - (139) - Gain on sale of assets - - 27 29 Other (11) (10) (33) (31) Total adjustments (11) 16 (40) (15) EBITDA 89 102 421 497 ELIMINATIONS AND OTHER Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Adjusted EBITDA 38 96 (71) 355 Change in unrealized derivative fair value gain/(loss) - Foreign exchange (452) 217 834 (716) Gain on debt extinguishment - - 25 - Employee severance costs - - - (105) Other 35 (18) 40 (36) Total adjustments (417) 199 899 (857) EBITDA (379) 295 828 (502) APPENDIX C NON-GAAP RECONCILIATION - CASH PROVIDED BY OPERATINGACTIVITIES TO DCF Three months endedSeptember 30, Nine months endedSeptember 30, 2025 2024 2025 2024 (unaudited; millions of Canadian dollars) Net cash provided by operating activities 2,868 2,973 9,159 8,938 Adjusted for changes in operating assets and liabilities1 (102) (155) 739 352 2,766 2,818 9,898 9,290 Distributions to noncontrolling interests2 (81) (79) (276) (245) Preference share dividends2 (105) (99) (311) (287) Maintenance capital (303) (290) (848) (748) Significant adjusting items: Other receipts of cash not recognized in revenue 36 53 89 89 Employee severance costs, net of tax - 4 - 95 Distributions from equity investments in excess of cumulative earnings2 160 174 556 650 Other items 93 15 138 73 DCF 2,566 2,596 9,246 8,917 1 Changes in operating assets and liabilities, net of recoveries. 2 Presented net of adjusting items. View original content:https://www.prnewswire.com/news-releases/enbridge-reports-strong-third-quarter-results-announces-accretive-investments-and-reaffirms-2025-financial-guidance-302608101.html SOURCE Enbridge Inc.
Delek US Holdings Reports Third Quarter 2025 Results
Delek US Holdings Reports Third Quarter 2025 Results Delek US reported third quarter net income of $178.0 million or $2.93 per share, adjusted net income of $434.2 million or $7.13 per share, adjusted EBITDA of $759.6 millionRecognized a $280.8 million benefit related to the reduction in cost of materials and other as a result of being granted Small Refinery Exemptions ("SREs") by the U.S. Environmental Protection Agency ("EPA") for past Renewable Volume Obligation ("RVO") compliance periodsAdjusted EBITDA and adjusted net income also include the impact of 50% reduction in RVO for the first nine months, to include any potential 2025 SRE grants, of ~$160 millionExcluding the above mentioned SRE items, adjusted EBITDA was $318.6 million and adjusted EPS was $1.52 p/sExpect proceeds of ~$400 million related to monetization of historical SRE grants over the next six to nine monthsFurther advanced key objectives of Enterprise Optimization Plan ("EOP")Increasing the annual run-rate cash flow improvements guidance from $130 to 170 million to at least $180 millionRecognized ~$60 million of improvements in 3Q'25Delek Logistics (DKL) is executing well and is set to finish the year in the top half of its full year adjusted EBITDA guidance of $480 to $520 million. DKL's new expected full year guidance range is $500 - $520 millionDelek US purchased ~$15 million in DK common stock during the quarterPaid $15.3 million of dividends and announced regular quarterly dividend of $0.255 per share BRENTWOOD, Tenn., Nov. 07 /BusinessWire/ -- Delek US Holdings, Inc. (NYSE:DK) ("Delek US", "Company") today announced financial results for its third quarter ended September 30, 2025. "We continue to make progress in achieving our Sum of the Parts goals and improving the overall profitability of the company as highlighted by a strong EOP contribution in 3Q'25," said Avigal Soreq, President and Chief Executive Officer of Delek US. "Our EOP efforts, which are exceeding previous guidance, and clarity on SREs, significantly improve DK's free cash flow generation in the short and the long term. DKL also continues to make progress in strengthening its premier position in the Permian basin as demonstrated by its guidance raise to $500 - $520 million. The new processing plant, ongoing AGI initiatives, and DKL's increasing economic separation from DK are getting us closer to unlocking the full value of our midstream assets." "Looking ahead, we will continue to execute on our priorities of running safe and reliable operations, making further progress on our Sum of the Parts initiative, improving cash flow generation, and delivering shareholder value while maintaining our financial strength and flexibility," Soreq concluded. Delek US Results Refining Segment The refining segment Adjusted EBITDA was $696.9 million in the third quarter 2025 compared with $10.2 million in the same quarter last year, which reflects the impacts related to the small refinery exemptions in the third quarter and an increase in refining margin driven by increased crack spreads. During the third quarter 2025, Delek US's benchmark crack spreads were up an average of 46.8% from prior-year levels. Adjusted EBITDA was also impacted favorably by other inventory impacts of $67.5 million and $25.8 million for third quarter 2025 and 2024, respectively. Logistics Segment The logistics segment Adjusted EBITDA in the third quarter 2025 was $131.5 million compared with $106.1 million in the prior-year quarter. The increase over last year's third quarter was driven by the impact of the W2W dropdown and incremental contribution due to the H2O Midstream Acquisition on September 11, 2024, the Gravity Acquisition on January 2, 2025, and the increase in wholesale margins. Shareholder Distributions On October 29, 2025, the Board of Directors approved the regular quarterly dividend of $0.255 per share that will be paid on November 17, 2025 to shareholders of record on November 10, 2025. Liquidity As of September 30, 2025, Delek US had a cash balance of $630.9 million and total consolidated long-term debt of $3,177.3 million, resulting in net debt of $2,546.4 million. As of September 30, 2025, Delek Logistics Partners, LP (NYSE:DKL) ("Delek Logistics") had $6.9 million of cash and $2,288.3 million of total long-term debt, which are included in the consolidated amounts on Delek US' balance sheet. Excluding Delek Logistics, Delek US had $624.0 million in cash and $889.0 million of long-term debt, or a $265.0 million net debt position. Third Quarter 2025 Results | Conference Call Information Delek US will hold a conference call to discuss its third quarter 2025 results on Friday, November 7, 2025 at 9:30 a.m. Central Time. Investors will have the opportunity to listen to the conference call live by going to www.DelekUS.com and clicking on the Investor Relations tab. Participants are encouraged to register at least 15 minutes early to download and install any necessary software. Presentation materials accompanying the call will be available on the investor relations tab of the Delek US website approximately ten minutes prior to the start of the call. For those who cannot listen to the live broadcast, the online replay will be available on the website for 90 days. Investors may also wish to listen to Delek Logistics' (NYSE: DKL) third quarter 2025 earnings conference call that will be held on Friday, November 7, 2025 at 11:00 a.m. Central Time and review Delek Logistics' earnings press release. Market trends and information disclosed by Delek Logistics may be relevant to the logistics segment reported by Delek US. Both a replay of the conference call and press release for Delek Logistics will be available online at www.deleklogistics.com. About Delek US Holdings, Inc. Delek US Holdings, Inc. is a diversified downstream energy company with assets in petroleum refining, logistics, pipelines, and renewable fuels. The refining assets consist primarily of refineries operated in Tyler and Big Spring, Texas, El Dorado, Arkansas and Krotz Springs, Louisiana with a combined nameplate crude throughput capacity of 302,000 barrels per day. The logistics operations include Delek Logistics Partners, LP (NYSE: DKL). Delek Logistics Partners, LP is a growth-oriented master limited partnership focused on owning and operating midstream energy infrastructure assets. Delek US Holdings, Inc. and its subsidiaries owned approximately 63.3% (including the general partner interest) of Delek Logistics Partners, LP at September 30, 2025. Safe Harbor Provisions Regarding Forward-Looking Statements This press release contains forward-looking statements that are based upon current expectations and involve a number of risks and uncertainties. Statements concerning current estimates, expectations and projections about future results, performance, prospects, opportunities, plans, actions and events and other statements, concerns, or matters that are not historical facts are "forward-looking statements," as that term is defined under the federal securities laws. These statements contain words such as "possible," "believe," "should," "could," "would," "predict," "plan," "estimate," "intend," "may," "anticipate," "will," "if", "potential," "expect" or similar expressions, as well as statements in the future tense. These forward-looking statements include, but are not limited to, statements regarding anticipated performance and financial position; cost reductions; throughput at the Company's refineries; crude oil prices, discounts and quality and our ability to benefit therefrom; growth; scheduled turnaround activity; projected capital expenditures and investments into our business; liquidity and EBITDA impacts from strategic and intercompany transactions; the performance of our midstream growth initiatives, and the flexibility, benefits and expected returns therefrom; and projected benefits of Delek Logistics' acquisition of the Delaware Gathering, Permian Gathering, H2O Midstream and Gravity Water Midstream businesses. Investors are cautioned that the following important factors, among others, may affect these forward-looking statements: political or regulatory developments, including tariffs, taxes and changes in governmental policies relating to crude oil, natural gas, refined products or renewables; uncertainty related to timing and amount of future share repurchases and dividend payments; risks and uncertainties with respect to the quantities and costs of crude oil we are able to obtain and the price of the refined petroleum products we ultimately sell, uncertainties regarding actions by OPEC and non-OPEC oil producing countries impacting crude oil production and pricing; risks and uncertainties related to the integration by Delek Logistics of the Delaware Gathering, Permian Gathering, H2O Midstream or Gravity businesses following their acquisition; Delek US' ability to realize cost reductions; risks related to exposure to Permian Basin crude oil, such as supply, pricing, gathering, production and transportation capacity; gains and losses from derivative instruments; risks associated with acquisitions and dispositions; risks and uncertainties with respect to the possible benefits of the retail and H2O Midstream and Gravity transactions; acquired assets may suffer a diminishment in fair value as a result of which we may need to record a write-down or impairment in carrying value of the asset; the possibility of litigation challenging renewable fuel standard waivers; changes in the scope, costs, and/or timing of capital and maintenance projects; the ability to grow the Midland Gathering System; the ability of the Red River joint venture to complete the expansion project to increase the Red River pipeline capacity; operating hazards inherent in transporting, storing and processing crude oil and intermediate and finished petroleum products; our competitive position and the effects of competition; the projected growth of the industries in which we operate; general economic and business conditions affecting the geographic areas in which we operate; and other risks described in Delek US' filings with the United States Securities and Exchange Commission (the "SEC"), including risks disclosed in our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings and reports with the SEC. Forward-looking statements should not be read as a guarantee of future performance or results and will not be accurate indications of the times at, or by, which such performance or results will be achieved. Forward-looking information is based on information available at the time and/or management's good faith belief with respect to future events, and is subject to risks and uncertainties that could cause actual performance or results to differ materially from those expressed in the statements. Delek US undertakes no obligation to update or revise any such forward-looking statements to reflect events or circumstances that occur, or which Delek US becomes aware of, after the date hereof, except as required by applicable law or regulation. Non-GAAP Disclosures: Our management uses certain "non-GAAP" operational measures to evaluate our operating segment performance and non-GAAP financial measures to evaluate past performance and prospects for the future to supplement our financial information presented in accordance with United States ("U.S.") Generally Accepted Accounting Principles ("GAAP"). These financial and operational non-GAAP measures are important factors in assessing our operating results and profitability and include: Adjusting items - certain identified infrequently occurring items, non-cash items, and items that are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends; Adjusted net income (loss) - calculated as net income (loss) attributable to Delek US adjusted for relevant Adjusting items recorded during the period; Adjusted net income (loss) per share - calculated as Adjusted net income (loss) divided by weighted average shares outstanding, assuming dilution, as adjusted for any anti-dilutive instruments that may not be permitted for consideration in GAAP earnings per share calculations but that nonetheless favorably impact dilution; Earnings before interest, taxes, depreciation and amortization ("EBITDA") - calculated as net income (loss) attributable to Delek US adjusted to add back interest expense, income tax expense, depreciation and amortization; Adjusted EBITDA - calculated as EBITDA adjusted for the relevant identified Adjusting items in Adjusted net income (loss) that do not relate to interest expense, income tax expense, depreciation or amortization, and adjusted to include income (loss) attributable to non-controlling interests; Refining margin - calculated as gross margin (which we define as sales minus cost of sales) adjusted for operating expenses and depreciation and amortization included in cost of sales; Adjusted refining margin - calculated as refining margin adjusted for other inventory impacts, net inventory LCM valuation loss (benefit), unrealized hedging (gain) loss and intercompany lease impacts; Refining production margin - calculated based on the regional market sales price of refined products produced, less allocated transportation, Renewable Fuel Standard volume obligation and associated feedstock costs. This measure reflects the economics of each refinery exclusive of the financial impact of inventory price risk mitigation programs and marketing uplift strategies; Refining production margin per throughput barrel - calculated as refining production margin divided by our average refining throughput in barrels per day (excluding purchased barrels) multiplied by 1,000 and multiplied by the number of days in the period; and Net debt - calculated as long-term debt including both current and non-current portions (the most comparable GAAP measure) less cash and cash equivalents as of a specific balance sheet date. We believe these non-GAAP operational and financial measures are useful to investors, lenders, ratings agencies and analysts to assess our ongoing performance because, when reconciled to their most comparable GAAP financial measure, they provide improved relevant comparability between periods, to peers or to market metrics through the inclusion of retroactive regulatory or other adjustments as if they had occurred in the prior periods they relate to, or through the exclusion of certain items that we believe are not indicative of our core operating performance and that may obscure our underlying results and trends. "Net debt," also a non-GAAP financial measure, is an important measure to monitor leverage and evaluate the balance sheet. Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings and operating income. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures. Additionally, because Adjusted net income or loss, Adjusted net income or loss per share, EBITDA and Adjusted EBITDA, Adjusted Refining Margin and Refining Production Margin or any of our other identified non-GAAP measures may be defined differently by other companies in its industry, Delek US' definition may not be comparable to similarly titled measures of other companies. See the accompanying tables in this earnings release for a reconciliation of these non-GAAP measures to the most directly comparable GAAP measures. Significant Transactions During the Quarter Impacting Results: Small Refinery Exemptions In the third quarter of 2025, the United States Environmental Protection Agency ("EPA") announced its decisions on the backlog of 175 Small Refinery Exemption ("SRE") petitions from refineries seeking an exemption from their Renewable Fuel Standard obligations. Delek fully complied with Renewable Identification Number ("RIN") obligations for all years, incurring significant costs to finance our compliance. EPA granted Delek full and partial exemptions for substantially all of our 20 petitions for the 2019-2024 calendar years. Because RINs are valid for a one-year period, a majority of the refunded RINs were expired and therefore had no value, and are the subject of ongoing litigation. The valid RINs received from prior year SREs resulted in a reduction of our Consolidated Net RIN Obligation and therefore a reduction within Cost of materials and other of approximately $280.8 million in the third quarter of 2025. Impairment Charges We review investments held at cost and long-lived assets quarterly for indicators of impairment. During the three months ended September 30, 2025, we recorded an $16.3 million ($12.6 million, after-tax) of impairment primarily related to software development costs. Transaction Costs We incurred $0.9 million ($0.7 million after-tax) of additional transaction related costs in connection with the previously announced acquisition of interests in H2O Midstream Intermediate, LLC, H2O Midstream Permian LLC, and H2O Midstream LLC (the "H2O Midstream Acquisition"), intercompany agreement amendments and acquisition of interests in Gravity Water Intermediate Holdings LLC ("Gravity Acquisition") during the three months ended September 30, 2025. Restructuring Costs In 2022, we announced that we are progressing a business transformation focused on enterprise-wide opportunities to improve the efficiency of our cost structure. For the third quarter 2025, we recorded restructuring costs totaling $34.1 million ($26.4 million after-tax) associated with our business transformation. Restructuring costs of $26.1 million are recorded in general and administrative expenses, $7.5 million are included in operating expenses, and $0.5 million are included in cost of materials and other in our condensed consolidated statements of income. General and Administrative Expenses Excluding transaction costs and restructuring costs, general and administrative expenses were $49.8 million for the three months ended September 30, 2025. DPG Dropdown On May 1, 2025, we transferred the Delek Permian Gathering ("DPG") purchasing and blending activities to Delek Logistics (the "DPG Dropdown"). The operating results of DPG are now reported in our Logistics segment, while previously recorded in the Refining segment. The dropdown has no impact to Delek US consolidated results as these amounts eliminate in consolidation. Other Inventory Impact "Other inventory impact" is primarily calculated by multiplying the number of barrels sold during the period by the difference between current period weighted average purchase cost per barrel directly related to our refineries and per barrel cost of materials and other for the period recognized on a first-in, first-out basis directly related to our refineries. It assumes no beginning or ending inventory, so that the current period average purchase cost per barrel is a reasonable estimate of our market purchase cost for the current period, without giving effect to any build or draw on beginning inventory. These amounts are based on management estimates using a methodology including these assumptions. However, this analysis provides management with a means to compare hypothetical refining margins to current period average crack spreads, as well as provides a means to better compare our results to peers. Intercompany Leases As a result of amendments to intercompany lease agreements in August 2024, we had to reassess lease classification for the agreements that contain leases under Accounting Standards Codification 842. As a result of these lease assessments, certain of these agreements met the criteria to be accounted for as sales-type leases for Delek Logistics and finance leases for the Refining segment. Therefore, portions of the minimum volume commitments under these agreements subject to sales-type lease accounting are recorded as interest income with the remaining amounts recorded as a reduction in net investment in leases. Prior to the amendments, these agreements were accounted for as operating leases and these minimum volume commitments were recorded as revenues in the Logistics segment. Similarly, these minimum volume commitments were previously recorded as costs of sales for the Refining segment, as the underlying lease was reclassified from an operating lease to a finance lease, and these payments are now recorded as interest expense and reductions in the lease liability. These accounting changes have no impact to the Delek US consolidated results as these amounts eliminate in consolidation. View source version on businesswire.com: https://www.businesswire.com/news/home/20251107386370/en/ back
Venture Global Announces New Long-Term LNG Sales and Purchase Agreement With Greece
Venture Global Announces New Long-Term LNG Sales and Purchase Agreement With Greece 20-year sales and purchase agreement begins partnership with newly formed Greek entity to bolster Central and Eastern European energy securityDeal builds on Venture Global's regasification capacity investment in the Alexandroupolis LNG import terminal to supply U.S. LNG to the region ATHENS, Greece, Nov. 07 /BusinessWire/ -- Today, Venture Global, Inc. (NYSE:VG) and ATLANTIC - SEE LNG TRADE S.A. of Greece announced the execution of a new Sales and Purchase Agreement (SPA) for the purchase of a minimum of 0.5 million tonnes per annum (MTPA) of U.S. liquefied natural gas (LNG) from Venture Global for twenty years starting in 2030. Under the SPA, Atlantic-See has the potential to expand its purchase commitment. Atlantic-See LNG is a newly formed joint venture announced this week at the 6th Partnership for Transatlantic Energy Cooperation (PTEC) conference hosted in Athens, Greece between Greek companies AKTOR and DEPA. This deal marks Greece's first ever long-term LNG supply agreement with a U.S. exporter, launching a dynamic and growing partnership between Atlantic-See LNG and Venture Global. The announcement of this supply agreement follows Venture Global's previously announced investment in regasification capacity at the Alexandroupolis LNG import terminal in Greece, which currently accounts for approximately 25% of the terminal's total capacity. The Alexandroupolis LNG FSRU receiving terminal and South-North `Vertical Corridor' will be essential to enhancing Central and Eastern European energy security by providing a new route to bring affordable and reliable U.S. natural gas into the region. "Venture Global is thrilled to expand our energy partnership with Greece and bring additional LNG supply to this critical region, building on our previous investment in the vertical corridor through the Alexandroupolis terminal," said Venture Global CEO Mike Sabel. "As a major point of entry for U.S. LNG into Central and Eastern Europe, this strategically important infrastructure and SPA agreement are key to strengthening the region's ability to diversify their energy mix and access a secure and reliable source of supply. We are excited to grow our partnership with key regional players such as the newly formed Atlantic-See LNG, and we are grateful for the strong leadership of President Trump, Secretary Burgum, Secretary Wright, Ambassador Guilfoyle and other officials on both sides of the Atlantic who are encouraging further trade of American LNG." About Venture Global Venture Global is an American producer and exporter of low-cost U.S. liquefied natural gas (LNG) with over 100 MTPA of capacity in production, construction, or development. Venture Global began producing LNG from its first facility in 2022 and is now one of the largest LNG exporters in the United States. The company's vertically integrated business includes assets across the LNG supply chain including LNG production, natural gas transport, shipping and regasification. The company's first three projects, Calcasieu Pass, Plaquemines LNG, and CP2 LNG, are located in Louisiana along the Gulf of America. Venture Global is developing Carbon Capture and Sequestration projects at each of its LNG facilities. Forward-looking Statements This press release contains forward-looking statements. We intend such forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in 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 facts, included herein are "forward-looking statements." In some cases, forward-looking statements can be identified by terminology such as "may," "might," "will," "could," "should," "expect," "plan," "project," "intend," "anticipate," "believe," "estimate," "predict," "potential," "pursue," "target," "continue," the negative of such terms or other comparable terminology. These forward-looking statements, which are subject to risks, uncertainties and assumptions about us, may include statements about our future performance, our contracts, our anticipated growth strategies and anticipated trends impacting our business. These statements are only predictions based on our current expectations and projections about future events. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the results, level of activity, performance or achievements expressed or implied by the forward-looking statements. Those factors include our need for significant additional capital to construct and complete future projects and related assets, and our potential inability to secure such financing on acceptable terms, or at all; our potential inability to accurately estimate costs for our projects, and the risk that the construction and operations of natural gas pipelines and pipeline connections for our projects suffer cost overruns and delays related to obtaining regulatory approvals, development risks, labor costs, unavailability of skilled workers, operational hazards and other risks; the uncertainty regarding the future of global trade dynamics, international trade agreements and the United States' position on international trade, including the effects of tariffs; our dependence on our EPC and other contractors for the successful completion of our projects, including the potential inability of our contractors to perform their obligations under their contracts; various economic and political factors, including opposition by environmental or other public interest groups, or the lack of local government and community support required for our projects, which could negatively affect the permitting status, timing or overall development, construction and operation of our projects; and risks related to other factors discussed under "Item 1A.-Risk Factors" of our annual report on Form 10-K for the year ended December 31, 2024 as filed with the Securities and Exchange Commission ("SEC") and any subsequent reports filed with the SEC. Any forward-looking statements contained herein speak only as of the date of this press release and are based on assumptions that we believe to be reasonable as of this date. We undertake no obligation to update these statements to reflect subsequent events or circumstances, except as may be required by law. View source version on businesswire.com: https://www.businesswire.com/news/home/20251107005517/en/ back
OPAL Fuels Reports Third Quarter 2025 Results
OPAL Fuels Reports Third Quarter 2025 Results WHITE PLAINS, N.Y., Nov. 06 /BusinessWire/ -- OPAL Fuels ("OPAL Fuels" or the "Company") (NASDAQ:OPAL) today announced financial and operating results for the three and nine months ended September 30, 2025. "Third quarter results were in line with our expectations," said Adam Comora, Co-Chief Executive Officer of OPAL Fuels. "RNG production continues to increase, up 8% sequentially and 30% when compared to the third quarter of 2024. We are pleased operationally with the progress made in the third quarter and we expect full year results to be within our 2025 guidance range, despite a lower D3 RIN price environment. We continue to execute on our strategic growth objectives having placed our Atlantic RNG Project online last month and today announce our CMS RNG Project in North Carolina has entered construction representing 1.0 million MMBtu of annual design capacity net to OPAL Fuels. We continue to see a positive policy environment where RNG receives bipartisan support. In the quarter, we completed our fourth sale of IRA Investment Tax Credits with aggregate total gross sale proceeds greater than $40 million this year and expect to begin recognizing 45Z production tax credits in the fourth quarter." "Our annual design capacity is now at 9.1 million MMBtu across twelve operating projects, our vertical integration with the marketing and distribution of RNG and CNG as a transportation fuel continues to contribute to our growth," said Co-Chief Executive Officer Jonathan Maurer. "We are building an energy infrastructure platform to address heavy-duty transportation, historically a hard to de-carbonize sector. At present, RNG and CNG are the most attractive alternatives to replace diesel for the Class 8 trucking market. We are positioned to lead faster adoption in this market which is building long-term and sustainable intrinsic value for OPAL shareholders." Financial Highlights Revenue for the three and nine months ended September 30, 2025, was $83.4 million and $249.2 million respectively, a decrease of (1)% and an increase 13% respectively, compared to the prior-year period. Net income for the three and nine months ended September 30, 2025, was $11.4 million and $20.2 million respectively, compared to $17.1 million and $19.7 million in the same periods last year. Basic and diluted net income per share attributable to Class A common shareholders for the three and nine months ended September 30, 2025 were $0.05 and $0.07 compared to $0.09 and $0.07 in the comparable periods last year. Adjusted EBITDA1 for the three and nine months ended September 30, 2025, was $19.5 million and $56.0 million respectively, compared to $31.1 million2 and $67.4 million2 respectively, in the comparable periods last year. At September 30, 2025, RNG Pending Monetization totaled $14.7 million. Completed sale of $17.3 million of IRA Investment Tax Credits. Operational Highlights RNG produced was 1.3 million and 3.5 million MMBtu for the three and nine months ended September 30, 2025, an increase of 30% and 25% respectively, compared to the prior-year periods.3 The Fuel Station Services segment sold, dispensed, and serviced an aggregate of 38.9 million and 120.4 million GGEs of transportation fuel for the three and nine months ended September 30, 2025, an increase of 1% and 10% respectively, compared to the prior-year periods. Of this amount, RNG dispensed as a transportation fuel was 20.4 and 60.5 million GGEs, an increase of 4% and 11% respectively, compared to the prior-year periods. Construction Update The Atlantic RNG Project commenced commercial operations last month. This project represents approximately 0.3 million MMBtu for OPAL Fuels' 50% ownership share of annual design capacity.45 The Burlington and Cottonwood RNG projects, representing an aggregate annual design capacity of 1.1 million MMBtu for OPAL's share, are expected to commence commercial operations in 2026. The Kirby RNG Project located in California, representing an aggregate annual design capacity of 0.7 million MMBtu for OPAL's 100% ownership, is expected to commence commercial operations in 2027. In October 2025, the Company began construction of the CMS Concord RNG facility in North Carolina. This project represents approximately 0.7 million MMBtu for OPAL's 70% ownership share of annual design capacity. Completion of construction at two dairy projects in California (Hilltop and Vander Schaaf) continues to be delayed due to a dispute with the prior Engineering, Procurement and Construction contractor over a series of change order requests.6 At September 30, 2025, we had 47 operating fueling stations owned by OPAL and an additional 16 under construction. There are also 25 fueling stations under construction owned by third parties. Guidance We maintain full year 2025 guidance. . Results of Operations Results of Operations from equity method investments Landfill RNG Facility Capacity and Utilization Summary RNG Pending Monetization Summary Liquidity As of September 30, 2025, our liquidity was $183.8 million, consisting of $138.4 million of unused capacity under our $450.0 million senior secured credit facility, $15.5 million of unused capacity under the associated revolver, and $29.9 million of cash and cash equivalents. We expect that our available cash together with our other assets, expected cash flows from operations, and access to expected sources of capital will be sufficient to meet our existing commitments for a period of at least twelve months from the date of this report. Capital Expenditures During the nine months ended September 30, 2025, OPAL Fuels invested $60.9 million across RNG projects in construction and OPAL Fuels owned fueling stations in construction as compared to $72.8 million in the prior year. In addition, for the nine months ended September 30, 2025, the Company's portion of capital expenditures in unconsolidated entities was $17.9 million. This represents our share of capital expenditures incurred by equity method investments. Earnings Call A webcast to review OPAL Fuels' Third Quarter 2025 results is being held tomorrow, November 7, 2025 at 11:00AM ET. Materials to be discussed in the webcast will be available before the call on the Company's website. Participants may access the call at https://edge.media-server.com/mmc/p/5s3pfnti. Investors can also listen to a webcast of the presentation on the Company's Investor Relations website at https://investors.opalfuels.com/news-events/events-presentations. ----------------------------------- Glossary of terms "D3" refers to cellulosic biofuel with a 60% GHG reduction requirement. "GGE" refers to gasoline gallon equivalent. The conversion ratio is 1 MMBtu of natural gas equal to 7.74 GGE. "LCFS" refers to Low Carbon Fuel Standard or similar types of federal and state programs. "MMBtu" refers to million British thermal units. "RECs" refers to renewable energy credits. "Renewable Power" refers to electricity generated from renewable sources. "RIN" refers to Renewable Identification Numbers. "RNG" refers to renewable natural gas. "VIEs" refers to variable interest entities. About OPAL Fuels OPAL Fuels (Nasdaq: OPAL) is a leader in the capture and conversion of biogas into low carbon intensity RNG and Renewable Power. OPAL Fuels is also a leader in the marketing and distribution of RNG to heavy duty trucking and other hard to decarbonize industrial sectors. For additional information, and to learn more about OPAL Fuels and how it is leading the effort to capture North America's naturally occurring methane and decarbonize the economy, please visit www.opalfuels.com. Forward-Looking Statements Certain statements in this communication may be considered forward-looking statements within the meaning of the "safe harbor" provisions of the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements are statements that are not historical facts and generally relate to future events or the Company's future financial or other performance metrics. In some cases, you can identify forward-looking statements by terminology such as "believe," "may," "will," "potentially," "estimate," "continue," "anticipate," "intend," "could," "would," "project," "target," "plan," "expect," or the negatives of these terms or variations of them or similar terminology. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those expressed or implied by such forward-looking statements. New risks and uncertainties may emerge from time to time, and it is not possible to predict all risks and uncertainties. These forward-looking statements are based upon estimates and assumptions that, while considered reasonable by the Company and its management, as the case may be, are inherently uncertain and subject to material change. Factors that may cause actual results to differ materially from current expectations include various factors beyond management's control, including but not limited to general economic conditions and other risks, uncertainties and factors set forth in the sections entitled "Risk Factors" and "Forward-Looking Statements and Risk Factor Summary" in the Company's annual report on Form 10-K and quarterly reports on Form 10-Q, and other filings the Company makes with the Securities and Exchange Commission. Nothing in this communication 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. You should not place undue reliance on forward-looking statements in this communication, which speak only as of the date they are made and are qualified in their entirety by reference to the cautionary statements herein. The Company expressly disclaims any obligations or undertaking to release publicly any updates or revisions to any forward-looking statements contained herein to reflect any change in the Company's expectations with respect thereto or any change in events, conditions, or circumstances on which any statement is based. Disclaimer This communication is for informational purposes only and is neither an offer to purchase, nor a solicitation of an offer to sell, subscribe for or buy, any securities, nor shall there be any sale, issuance or transfer of securities in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Non-GAAP Financial Measures (Unaudited) This release includes various financial measures that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. We believe these measures provide important supplemental information to investors to use in evaluating ongoing operating results. We use these measures, together with accounting principles generally accepted in the United States ("GAAP" or "U.S. GAAP"), for internal managerial purposes and as a means to evaluate period-to-period comparisons. However, we do not, and you should not, rely on non-GAAP financial measures alone as measures of our performance. We believe that non-GAAP financial measures reflect an additional way of viewing aspects of our operations, that when taken together with GAAP results and the reconciliations to corresponding GAAP financial measures that we also provide, give a more complete understanding of factors and trends affecting our business. We strongly encourage you to review all of our financial statements and publicly filed reports in their entirety and to not solely rely on any single non-GAAP financial measure. Non-GAAP financial measures are limited as an analytical tool and should not be considered in isolation from, or as a substitute for, the Company's GAAP results. The Company expects to continue reporting non-GAAP financial measures, adjusting for the items described below (and/or other items that may arise in the future as the Company's management deems appropriate), and the Company expects to continue to incur expenses, charges or gains like the non-GAAP adjustments described below. Accordingly, unless expressly stated otherwise, the exclusion of these and other similar items in the presentation of non-GAAP financial measures should not be construed as an inference that these costs are unusual, infrequent, or non-recurring. These Non-GAAP financial measures are not recognized terms under GAAP and do not purport to be alternatives to GAAP net income or any other GAAP measure as indicators of operating performance. Moreover, because not all companies use identical measures and calculations, the Company's presentation of Non-GAAP financial measures may not be comparable to other similarly titled measures used by other companies. We strongly encourage you to review all of our financial statements and publicly filed reports in their entirety and to not solely rely on any single non-GAAP financial measure. Adjusted EBITDA To supplement the Company's unaudited condensed consolidated financial statements presented in accordance with GAAP, the Company uses a non-GAAP financial measure that it calls adjusted EBITDA ("Adjusted EBITDA"). This non-GAAP financial measure adjusts net income for interest and financing expense, net, net income attributable to non-redeemable non-controlling interests, depreciation, amortization and accretion, adjustments to reflect Adjusted EBITDA from equity method investments, fair value changes and non-recurring charges, Stock-based compensation, major maintenance on Renewable Power, RNG development costs, and ITC proceeds, net. Management believes this non-GAAP financial measure provides meaningful supplemental information about the Company's performance, for the following reasons: (1) it allows for greater transparency with respect to key metrics used by management to assess the Company's operating performance and make financial and operational decisions; (2) the measure excludes the effect of items that management believes are not directly attributable to the Company's core operating performance and may obscure trends in the business; (3) the measure better aligns revenues with expenses; and (4) the measure is used by institutional investors and the analyst community to help analyze the Company's business. In future quarters, the Company may adjust for other expenditures, charges or gains to present non-GAAP financial measures that the Company's management believes are indicative of the Company's core operating performance. The following table presents the reconciliation of our net income to Adjusted EBITDA: View source version on businesswire.com: https://www.businesswire.com/news/home/20251106130297/en/ back
Granite Ridge Resources, Inc. Reports Third Quarter 2025 Results and Declares Quarterly Cash Dividend
Granite Ridge Resources, Inc. Reports Third Quarter 2025 Results and Declares Quarterly Cash Dividend DALLAS, Nov. 06 /BusinessWire/ -- Granite Ridge Resources, Inc. ("Granite Ridge" or the "Company") (NYSE:GRNT) today reported financial and operating results for the third quarter of 2025. Third Quarter 2025 Highlights Grew daily production 27% to 31,925 barrels of oil equivalent ("Boe") per day (51% oil), from 25,177 Boe per day for the third quarter of 2024. Reported net income of $14.5 million, or $0.11 per diluted share, versus $9.1 million, or $0.07 per diluted share, for the prior year period. Adjusted Net Income (non-GAAP) totaled $11.8 million, or $0.09 Adjusted Earnings Per Diluted Share (non-GAAP). Generated $78.6 million of Adjusted EBITDAX (non-GAAP). Invested $64.0 million in development capital expenditures and $16.5 million in acquisition capital to capture high quality drilling opportunities. Placed 9.3 net wells online. Declared dividend of $0.11 per share of common stock. Net Debt to Trailing Twelve Months Adjusted EBITDAX (non-GAAP) of 0.9x. Subsequent to quarter end, the Company's Board of Directors declared a regular quarterly dividend of $0.11 per share payable on 12/15/2025 to shareholders of record as of 11/28/2025. Future declarations of dividends are subject to approval by the Board of Directors. Subsequent to quarter end, the Company issued $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with a stated maturity of November 5, 2029. See "Supplemental Non-GAAP Financial Measures" below for descriptions of the above non-GAAP measures as well as a reconciliation of these measures to the associated GAAP (as defined herein) measures. Tyler Farquharson, President and CEO of Granite Ridge, commented, "Granite Ridge delivered another quarter of strong execution and disciplined growth, demonstrating the consistency of our model and the strength of our diversified portfolio. Our Operated Partnership platform continues to perform well, highlighted by Admiral Permian Resources and other key partners who are driving operational excellence and capital efficiency across our portfolio. "Subsequent to quarter end, we further strengthened our balance sheet through proactive refinancing that enhanced our liquidity and extended our financial runway heading into 2026. These actions reflect our continued commitment to maintaining a conservative capital structure and ensuring the flexibility to pursue high-return opportunities while delivering consistent cash returns to shareholders. "As we look ahead to 2026, Granite Ridge is well positioned to build on this momentum. Our Operated Partnerships provide a repeatable path to growth, our non-operated portfolio continues to generate steady cash flow, and our financial strength enables us to create long-term value for shareholders through commodity cycles." Financial Results Oil and natural gas sales for the third quarter of 2025 were $112.7 million. Net income was $14.5 million, or $0.11 per diluted share. Excluding non-cash and special items, Adjusted Net Income (non-GAAP) was $11.8 million, or $0.09 per diluted share. Adjusted EBITDAX (non-GAAP) for the third quarter of 2025 totaled $78.6 million compared to $75.4 million for the third quarter of 2024. Cash flow from operating activities was $77.8 million, including $4.7 million in working capital changes. Operating Cash Flow Before Working Capital Changes (non-GAAP) was $73.1 million. Production Results Third quarter 2025 oil production volumes totaled 16,222 barrels ("Bbls") per day, a 28% increase from the third quarter of 2024. Natural gas production for the third quarter of 2025 totaled 94,217 thousand cubic feet of natural gas ("Mcf") per day, a 25% increase from the third quarter of 2024. The Company's daily production for the third quarter of 2025 grew 27% from the third quarter of the prior year to 31,925 Boe per day. Oil, Natural Gas and Related Product Sales The Company's average realized price for oil and natural gas for the third quarter of 2025, excluding the effect of commodity derivatives, was $61.62 per Bbl and $2.39 per Mcf, respectively, compared to $73.44 per Bbl and $1.24 per Mcf realized in the third quarter of 2024. Operating Costs Lease operating expenses were $23.6 million ($8.03 per Boe) for the three months ended September 30, 2025 compared to $13.0 million ($5.62 per Boe) during the same period in 2024. The increase was primarily due to an overall increase in service costs, particularly saltwater disposal costs. Production and ad valorem taxes were $6.6 million for the quarter, or 6% of oil and natural gas sales. During the quarter, general and administrative expenses totaled $7.0 million, or $2.38 per Boe, inclusive of $0.4 million of nonrecurring severance and capital markets expenses and $1.3 million of non-cash stock-based compensation. Capital Expenditures and Operational Activity Capital expenditures for the quarter were $80.5 million comprised of $64.0 million of development capital and $16.5 million of property acquisition costs. The Company closed 17 acquisitions in the Permian and Utica Basins, adding an aggregate inventory of 13.6 net undeveloped locations. The table below provides the costs incurred for oil and natural gas producing activities for the periods indicated: The Company had 9.3 net wells turned in-line ("TIL") during the third quarter of 2025, compared to 5.2 net wells TIL in the third quarter of 2024. Granite Ridge saw strong well performance across multiple basins, highlighted by robust initial production from recently TIL wells in the Permian Basin. The table below provides a summary of gross and net wells completed and TIL for the three and nine months ended September 30, 2025: At September 30, 2025, the Company had 108 gross (11.3 net) wells in process. Liquidity and Capital Resources As of September 30, 2025, Granite Ridge had $300.0 million of debt outstanding under its existing Credit Agreement and $86.5 million of liquidity, consisting of $74.7 million of committed borrowing availability and $11.8 million of cash on hand. On November 5, 2025, the Company, as issuer, completed an issuance of $350.0 million aggregate principal amount of 8.875% senior unsecured notes at 96.0% of par with stated maturity on November 5, 2029 (the "2029 Senior Notes") pursuant to a note purchase agreement. The 2029 Senior Notes were purchased by a group of institutional accounts, including funds managed by EOC Partners Advisors L.P. The Company used the net proceeds from issuance of the 2029 Senior Notes to repay certain amounts under the Credit Agreement and to pay related fees and expenses. On November 5, 2025, the Company and its lenders entered into the Sixth Amendment to Credit Agreement, which amended the Credit Agreement to, among other things: reaffirm the borrowing base and aggregate elected commitment amounts at $375.0 million, permit the issuance of the 2029 Senior Notes, and extend the maturity date to 2029. Commodity Derivatives Update The Company's commodity derivatives strategy is intended to manage its exposure to commodity price fluctuations. Please see the table under "Derivatives Information" below for detailed information about Granite Ridge's current derivatives positions. 2025 Guidance The following table summarizes the Company's operational and financial guidance for 2025. Conference Call Granite Ridge will host a conference call on November 7, 2025, at 10:00 AM CT (11:00 AM ET) to discuss its third quarter 2025 results. A brief Q&A session for security analysts will immediately follow the discussion. The telephone number and passcode to access the conference call are provided below: Dial-in: (888) 660-6093 Intl. dial-in: (929) 203-0844 Participant Passcode: 4127559 To access the live webcast visit Granite Ridge's website at www.graniteridge.com. Alternatively, an audio replay will be available through November 21, 2025. To access the audio replay, dial (800) 770-2030 and enter confirmation code 4127559. Upcoming Investor Events Granite Ridge management will be participating in the following upcoming investor events: BofA Securities Global Energy Conference (Houston, TX) - November 12, 2025 Stephens Annual Investment Conference (Nashville, TN) - November 20, 2025 Capital One Securities Energy Conference (New Orleans, LA) - December 9, 2025 Any investor presentations to be used for such events will be posted prior to the respective event on Granite Ridge's website. Information on Granite Ridge's website does not constitute a portion of, and is not incorporated by reference into this press release. About Granite Ridge Granite Ridge is a scaled energy company which aims to provide shareholders with exposure similar to energy private equity through operated partnerships and traditional non-operated assets. We own assets in six prolific unconventional basins across the United States. We aim to deliver a diversified portfolio with best-in-class full cycle returns by investing in a large number of high-graded deals developed by proven public and private operators. We focus on success as measured by total shareholder returns, which we seek to balance with a low leverage profile. For more information, visit Granite Ridge's website at www.graniteridge.com. Forward-Looking Statements and Cautionary Statements This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this release regarding, without limitation, Granite Ridge's 2025 outlook, financial position, operating and financial performance, business strategy, plans and objectives of management for future operations, industry conditions, indebtedness covenant compliance, capital expenditures, production and cash flows are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as "estimate," "project," "predict," "believe," "expect," "continue," "anticipate," "target," "could," "plan," "intend," "seek," "goal," "will," "should," "may" or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future production and sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements. Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond Granite Ridge's control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in Granite Ridge's strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects and plans, changes in current or future commodity prices and interest rates, supply chain disruptions, infrastructure constraints and related factors affecting our properties, ability to acquire additional development opportunities and potential or pending acquisition transactions, as well as the effects of such acquisitions on the Company's cash position and levels of indebtedness, changes in reserves estimates or the value thereof, operational risks including, but not limited to, the pace of drilling and completions activity on our properties, changes in the markets in which Granite Ridge competes, geopolitical risk and changes in applicable laws, legislation, or regulations, including those relating to environmental matters, cyber-related risks, the fact that reserve estimates depend on many assumptions that may turn out to be inaccurate and that any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of Granite Ridge's reserves, the outcome of any known and unknown litigation and regulatory proceedings, limited liquidity and trading of Granite Ridge's securities, acts of war, terrorism or uncertainty regarding the effects and duration of global hostilities, including the Israel-Hamas conflict, the Russia-Ukraine war, continued instability in the Middle East, and any associated armed conflicts or related sanctions which may disrupt commodity prices and create instability in the financial markets, and market conditions and global, regulatory, technical, and economic factors beyond Granite Ridge's control, including the potential adverse effects of world health events, affecting capital markets, general economic conditions, global supply chains, uncertainties with respect to trade policies (including the imposition of tariffs) and Granite Ridge's business and operations, increasing regulatory and investor emphasis on, and attention to, environmental, social and governance matters, our ability to establish and maintain effective internal control over financial reporting, and the other risks described under the heading "Item 1A. Risk Factors" in Granite Ridge's Annual Report on Form 10-K for the year ended December 31, 2024 filed with the Securities and Exchange Commission ("SEC"), as updated by any subsequent Quarterly Reports on Form 10-Q that Granite Ridge files with the SEC. Granite Ridge has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Granite Ridge's control. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected. Granite Ridge does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws. Use of Non-GAAP Financial Measures To supplement the presentation of the Company's financial results prepared in accordance with U.S. Generally Accepted Accounting Principles ("GAAP"), this press release contains certain financial measures that are not prepared in accordance with GAAP, including Adjusted Net Income, Adjusted Earnings Per Share, Adjusted EBITDAX, Trailing Twelve Months Adjusted EBITDAX, Operating Cash Flow Before Working Capital Changes, and Net Debt. See "Supplemental Non-GAAP Financial Measures" below for a description and reconciliation of each non-GAAP measure presented in this press release to the most directly comparable financial measure calculated in accordance with GAAP. Granite Ridge Resources, Inc. Condensed Consolidated Balance Sheets (Unaudited) Granite Ridge Resources, Inc. Condensed Consolidated Statements of Operations (Unaudited) Granite Ridge Resources, Inc. Condensed Consolidated Statements of Cash Flows (Unaudited) Granite Ridge Resources, Inc. Summary Production and Price Data The following table sets forth summary information concerning production and operating data for the periods indicated: Granite Ridge Resources, Inc. Derivatives Information The table below provides data associated with the Company's derivatives at November 6, 2025, for the periods indicated: Granite Ridge Resources, Inc. Supplemental Non-GAAP Financial Measures The Company reports its financial results in accordance with GAAP. However, the Company believes certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results, the results of its peers and the results of prior periods. In addition, the Company believes these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations throughout this release of GAAP financial measures to non-GAAP financial measures for the periods indicated. Reconciliation of Net Income to Adjusted EBITDAX Adjusted EBITDAX is presented herein and reconciled from the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator. The Company defines Adjusted EBITDAX as net income before depletion and accretion expense, unrealized (gain) loss on derivatives - commodity derivatives, interest expense, net, non-cash stock-based compensation, income tax expense, impairment of unproved properties, impairment of long-lived assets, (gain) loss on equity investments, and other, net. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP. The Company's Adjusted EBITDAX measure provides additional information that may be used to better understand the Company's operations. Adjusted EBITDAX is one of several metrics that the Company uses as a supplemental financial measurement in the evaluation of its business and should not be considered in isolation or as an alternative to, or more meaningful than, net income as an indicator of operating performance. 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 cost of depreciable and depletable assets. Adjusted EBITDAX, as used by the Company, may not be comparable to similarly titled measures reported by other companies. The Company believes that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by the Company's management team and by other users of the Company's consolidated financial statements. For example, Adjusted EBITDAX can be used to assess the Company's operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of the Company's assets and the Company without regard to capital structure or historical cost basis. The following table provides a reconciliation of the GAAP measure of net income to Adjusted EBITDAX for the periods indicated: The Company defines Trailing Twelve Months Adjusted EBITDAX as the accumulation of the prior twelve months Adjusted EBITDAX. Adjusted EBITDAX for each of the quarters ended December 31, 2024, March 31, 2025, and June 30, 2025 were previously reported in an earnings release relating to the applicable quarter, and the reconciliation of net income to Adjusted EBITDAX for each quarter is included in the applicable earnings release. The following table provides a reconciliation of the GAAP measure of net income to Trailing Twelve Months Adjusted EBITDAX for the period indicated: Reconciliation of Debt to Net Debt The Company provides Net Debt, which is a non-GAAP financial measure. The Company defines Net Debt as long-term debt less cash as of the balance sheet date. The Company's Net Debt to Trailing Twelve Months Adjusted EBITDAX provides investors with insight into the Company's leverage as of the measurement date. The following table provides a reconciliation from the GAAP measure of Debt to Net Debt and Net Debt to Trailing Twelve Months Adjusted EBITDAX ratio: Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share The Company provides Adjusted Net Income and Adjusted Earnings Per Share, which are non-GAAP financial measures. Adjusted Net Income and Adjusted Earnings Per Share represent earnings and diluted earnings per share determined under GAAP without regard to certain non-cash and nonrecurring items. The Company defines Adjusted Net Income as net income as determined under GAAP excluding impairments of long lived assets, unrealized (gain) loss on derivatives - commodity derivatives, (gain) loss on equity investments, deferred financing cost amortization acceleration, certain nonrecurring general and administrative expenses and tax impact on above adjustments. The Company defines Adjusted Earnings Per Share as Adjusted Net Income divided by weighted average number of diluted shares of common stock outstanding. The Company believes these measures provide useful information to analysts and investors for analysis of its operating results on a recurring, comparable basis from period to period. Adjusted Net Income and Adjusted Earnings Per Share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with GAAP and may not be comparable to other similarly titled measures of other companies. The following table provides a reconciliation from the GAAP measure of net income to Adjusted Net Income, both in total and on a per diluted share basis, for the periods indicated: Reconciliation of Net Cash Provided by Operating Activities to Operating Cash Flow Before Working Capital Changes The Company provides Operating Cash Flow ("OCF") Before Working Capital Changes, which is a non-GAAP financial measure. The Company defines OCF Before Working Capital Changes as net cash provided by operating activities as determined under GAAP excluding changes in operating assets and liabilities such as: changes in cash due to changes in operating assets and liabilities, revenue receivable, other receivable, accounts payable and accrued liabilities, prepaid and other current assets, and other payables. The Company believes OCF Before Working Capital Changes is an accepted measure of an oil and natural gas company's ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. This non-GAAP measure should not be considered as an alternative to, or more meaningful than, net cash provided by operating activities as an indicator of operating performance. The following table provides a reconciliation from the GAAP measure of net cash provided by operating activities to OCF Before Working Capital Changes: View source version on businesswire.com: https://www.businesswire.com/news/home/20251106355453/en/ back
Targa Resources Corp. Prices $1.75 Billion Offering of Senior Notes
Targa Resources Corp. Prices $1.75 Billion Offering of Senior Notes HOUSTON, Nov. 06, 2025 (GLOBE NEWSWIRE) -- Targa Resources Corp. ("Targa" or the "Company") (NYSE: TRGP) announced today the pricing of an underwritten public offering (the "Offering") of $750 million aggregate principal amount of its 4.350% Senior Notes due 2029 and $1.0 billion aggregate principal amount of its 5.400% Senior Notes due 2036 at a price to the public of 99.938% and 99.920% of their face value, respectively. The Offering is expected to close on November 12, 2025, subject to the satisfaction of customary closing conditions. The Company expects to use a portion of the net proceeds from the Offering to redeem the 6.875% Senior Notes due 2029 (the "6.875% 2029 Notes") issued by Targa Resources Partners LP and to use the remaining net proceeds for general corporate purposes, including to repay borrowings under its unsecured commercial paper note program, to repay other indebtedness, to repurchase or redeem securities or to fund capital expenditures, additions to working capital or investments in its subsidiaries. The Offering is being made pursuant to an effective shelf registration statement and prospectus filed by the Company with the U.S. Securities and Exchange Commission (the "SEC") and may be made only by means of a prospectus and prospectus supplement related to such Offering meeting the requirements of Section 10 of the Securities Act of 1933, as amended (the "Securities Act"). This announcement shall not constitute an offer to sell or a solicitation of an offer to buy any of these securities, except as required by law. About Targa Resources Corp. Targa Resources Corp. (NYSE: TRGP) is a leading provider of midstream services and is one of the largest independent infrastructure companies in North America. The Company owns, operates, acquires, and develops a diversified portfolio of complementary domestic infrastructure assets and its operations are critical to the efficient, safe and reliable delivery of energy across the United States and increasingly to the world. The Company's assets connect natural gas and natural gas liquids to domestic and international markets with growing demand for cleaner fuels and feedstocks. The principal executive offices of Targa Resources Corp. are located at 811 Louisiana, Suite 2100, Houston, TX 77002 and its telephone number is 713-584-1000. Forward-Looking Statements Certain statements in this release are "forward-looking statements" within the meaning of Section 27A of the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this 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, including the expected closing date and use of proceeds from the Offering, such as the redemption of the 6.875% 2029 Notes. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company's control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, those described more fully in the Company's filings with the SEC, including its most recent Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Targa Investor RelationsInvestorRelations@targaresources.com(713) 584-1133
Mach Natural Resources LP Reports Third Quarter 2025 Results; Declares Quarterly Cash Distribution of $0.27 Per Common Unit; Provides Recent Well Results and Updated 2026 Outlook
Mach Natural Resources LP Reports Third Quarter 2025 Results; Declares Quarterly Cash Distribution of $0.27 Per Common Unit; Provides Recent Well Results and Updated 2026 Outlook OKLAHOMA CITY, Nov. 06 /BusinessWire/ -- Mach Natural Resources LP (NYSE:MNR) ("Mach" or the "Company") today reported financial and operating results for the three months ended September 30, 2025. The Company also announced its quarterly cash distribution and updated its full-year 2026 outlook. Third Quarter 2025 Highlights Averaged total net production of 94.0 thousand barrels of oil equivalent per day ("Mboe/d") Lease operating expense of $6.82 per barrel of oil equivalent ("Boe") Reported net losses and Adjusted EBITDA(1) of $36 million and $124 million, respectively Generated net cash provided by operating activities of $106 million Incurred total development costs of $59 million Successfully closed on September 16, 2025, two acquisitions of oil and gas assets located in the Permian Basin and San Juan Basin which contributed approximately two weeks to the Company's operational and financial results Declared a quarterly cash distribution of $0.27 per common unit Recent Highlights Reduced 2026 drilling and completion capital program by 18% while maintaining prior production guidance, reflecting continued capital discipline and strong capital efficiency Delivered a combined current production rate in excess of 40 million cubic feet of natural gas per day ("MMcf/d") from Mach's first two-well pad drilled and operated in the Deep Anadarko, consisting of two three-mile laterals totaling roughly 25,000 feet; additional wells are scheduled to turn in line through 2026 Achieved a combined initial production rate in excess of 100 MMcf/d from Mach's first five wells drilled and operated in the Mancos Shale, totaling roughly 65,000 feet of laterals "The third quarter was a defining period for Mach with the closing of our Permian and San Juan acquisitions," said Tom L. Ward, Chief Executive Officer of Mach Natural Resources. "These transactions have transformed our scale and operating footprint while remaining fully aligned with the disciplined strategy that has guided Mach since inception. Looking ahead to 2026, we are focused on integrating these assets and deploying capital efficiently across all areas of our business for the benefit of our unitholders. Mach is well positioned to navigate a dynamic commodity environment with disciplined capital allocation and an unwavering focus on delivering cash to our unitholders." Third Quarter 2025 Financial Results Mach reported total revenue and net losses of $273 million and $36 million in the third quarter of 2025, respectively. Additionally, during the third quarter, the average realized price was $64.79 per barrel of oil, $2.54 per Mcf of natural gas, and $21.78 per barrel of natural gas liquids ("NGLs"). These prices exclude the effects of derivatives. As of September 30, 2025, Mach had a cash balance of $54 million, remaining availability under the Revolving Credit Facility of $295 million, and a pro forma net-debt-to-Adjusted-EBITDA ratio of 1.3x. Third Quarter 2025 Operational Results During the third quarter of 2025, Mach achieved average oil equivalent production of 94.0 Mboe/d, which consisted of 21% oil, 56% natural gas and 23% NGLs. Also, for the third quarter of 2025, Mach's production revenues from oil, natural gas, and NGLs sales totaled $235 million, comprised of 50% oil, 32% natural gas, and 18% NGLs. The Company spud 5 gross (3.3 net) operated wells and brought online 3 gross (1.7 net) operated wells in the third quarter of 2025. As of September 30, 2025, the Company had 6 gross (4.6 net) operated wells in various stages of drilling and completion. Mach's lease operating expense in the third quarter of 2025 was $59 million, or $6.82 per Boe. Mach incurred $33 million, or $3.83 per Boe, of gathering and processing expenses in the third quarter of 2025. Furthermore, during the third quarter of 2025, production taxes as a percentage of oil, natural gas, and NGL sales were approximately 4.4%, midstream operating profit was approximately $3 million, general and administrative expenses-excluding equity-based compensation of $2 million-was $21 million, and interest expense was $17 million. In the third quarter of 2025, Mach's total development costs were $59 million, including $53 million of upstream capital and $6 million of other capital (including midstream and land). Distributions Mach announced today that the board of directors of its general partner declared a quarterly cash distribution for the third quarter of 2025 of $0.27 per common unit. The quarterly cash distribution is to be paid on December 4, 2025, to common unitholders of record as of the close of trading on November 20, 2025. 2026 Outlook Today the Company also provided updates to its full-year 2026 guidance. Mach reduced its 2026 drilling and completion capital guidance by 18%, or $63 million, while maintaining prior production expectations. The revision highlights strong well performance and continued efficiency gains. Additional details of Mach's guidance are available on the Company's website at www.machnr.com. Conference Call and Webcast Information Mach will host a conference call and webcast at 9:00 a.m. Central (10:00 a.m. Eastern) on Friday, November 7, 2025, to discuss its third quarter 2025 results. Participants can access the conference call by dialing 877-407-2984. A webcast link to the conference call will be provided on the Company's website at www.ir.machnr.com. A replay will also be available on the Company's website following the call. About Mach Natural Resources LP Mach Natural Resources LP is an independent upstream oil and gas company focused on the acquisition, development and production of oil, natural gas, and NGL reserves. The Company operates a diversified portfolio across the Anadarko, Permian and San Juan Basins. For more information, please visit www.machnr.com. Non-GAAP Financial Measures and Disclosures This press release includes non-GAAP financial measures. Pursuant to regulatory disclosure requirements, Mach is required to reconcile non-GAAP financial measures to the related GAAP information. Reconciliations of these non-GAAP measures are provided below. Reconciliations of these non-GAAP measures, along with other financial and operational disclosures, are also within the supplemental tables that are available on the Company's website at www.machnr.com and in the related Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission (the "SEC"). Adjusted EBITDA(1) Mach includes in this press release the supplemental non-GAAP financial performance measure Adjusted EBITDA and provides the Company's calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, the Company's most directly comparable financial measure calculated and presented in accordance with GAAP. The Company defines Adjusted EBITDA as net (loss) income before (1) interest expense, net, (2) depreciation, depletion, amortization and accretion, (3) unrealized (gain) loss on derivative instruments, (4) impairment of oil and gas assets, (5) loss on debt extinguishment, (6) equity-based compensation expense, and (7) gain on sale of assets, net. Adjusted EBITDA is used as a supplemental financial performance measure by Mach's management and by external users of Mach's financial statements, such as industry analysts, investors, lenders, rating agencies and others, to more effectively evaluate the Company's operating performance and results of operation from period to period and against Mach's peers without regard to financing methods, capital structure or historical cost basis. Mach excludes the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within the industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA is not a measurement of Mach's financial performance under GAAP and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as indicators of the Company's operating performance. 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 burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDA. The Company's presentation of Adjusted EBITDA should not be construed as an inference that Mach's results will be unaffected by unusual items. The Company's computations of Adjusted EBITDA may not be identical to other similarly titled measures of other companies. Cautionary Note Regarding Forward-Looking Statements This release contains statements that express the Company's opinions, expectations, beliefs, plans, objectives, assumptions or projections regarding future events or future results, in contrast with statements that reflect historical facts. All statements, other than statements of historical fact included in this 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 release, words such as "may," "assume," "forecast," "could," "should," "will," "plan," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget" and similar expressions are used 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 belief, based on currently available information as to the outcome and timing of future events at the time such statement was made. Such statements are subject to a number of assumptions, risk and uncertainties, many of which are beyond the control of the Company. These include, but are not limited to, the Company's future financial condition, results of operations, strategy and plans; changes in capital markets and the ability of the Company to finance operations in the manner expected; the effects of commodity prices; and the risks of oil and gas activities. Additionally, risks and uncertainties that could cause actual results to differ materially from those anticipated also include: commodity price volatility; the impact of epidemics, outbreaks or other public health events, and the related effects on financial markets, worldwide economic activity and our operations; uncertainties about our estimated oil, natural gas and natural gas liquids reserves, including the impact of commodity price declines on the economic producibility of such reserves, and in projecting future rates of production; difficult and adverse conditions in the domestic and global capital and credit markets; lack of transportation and storage capacity as a result of oversupply, government regulations or other factors; lack of availability of drilling and production equipment and services; potential financial losses or earnings reductions resulting from our commodity price risk management program or any inability to manage our commodity risks; failure to realize expected value creation from property acquisitions and trades; access to capital and the timing of development expenditures; environmental, weather, drilling and other operating risks; regulatory changes, including potential shut-ins or production curtailments mandated by the Railroad Commission of Texas, the Oklahoma Corporation Commission and/or the Kansas Corporation Commission; competition in the oil and natural gas industry; loss of production and leasehold rights due to mechanical failure or depletion of wells and our inability to re-establish their production; our ability to service our indebtedness; any downgrades in our credit ratings that could negatively impact our cost of and ability to access capital; cost inflation; the potential for significant new tariffs and their impact on global oil, natural gas and NGL markets; 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, 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; evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, 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 risks related to our ability to expand our business, including through the recruitment and retention of qualified personnel. Please read the Company's filings with the U.S. Securities and Exchange Commission (the "SEC"), including "Risk Factors" in the Company's Annual Report on Form 10-K and any additional subsequent reports and other documents on file with the SEC, for a discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements. As a result, these forward-looking statements are not a guarantee of our performance, and you should not place undue reliance on such statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise. View source version on businesswire.com: https://www.businesswire.com/news/home/20251106712051/en/ back
Pembina Pipeline Corporation Reports Results for the Third Quarter of 2025 and Provides Business Update
Pembina Pipeline Corporation Reports Results for the Third Quarter of 2025 and Provides Business Update All financial figures are in Canadian dollars unless otherwise noted. This news release refers to certain financial measures and ratios that are not specified, defined or determined in accordance with Generally Accepted Accounting Principles ("GAAP"), including net revenue; adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA"); adjusted cash flow from operating activities; and adjusted cash flow from operating activities per common share. For more information see "Non-GAAP and Other Financial Measures" herein. CALGARY, Alberta, Nov. 06 /BusinessWire/ -- Pembina Pipeline Corporation ("Pembina" or the "Company") (TSX: PPL; NYSE:PBA) announced today its financial and operating results for the third quarter of 2025. This press release features multimedia. View the full release here: https://www.businesswire.com/news/home/20251106637433/en/ Highlights Quarterly Results - Reported third quarter earnings of $286 million, adjusted EBITDA of $1,034 million, and adjusted cash flow from operating activities of $648 million ($1.12 per share). Adjusted EBITDA Guidance - Pembina has updated its 2025 adjusted EBITDA guidance range to $4.25 billion to $4.35 billion (previously $4.225 billion to $4.425 billion). New Commercial Agreements - Pembina has signed new transportation agreements on the Peace Pipeline for the renewal and addition of volumes totaling approximately 50,000 barrels per day ("bpd") with a weighted average term of approximately 10 years. Alliance Pipeline - The long-term contractual profile of Alliance Pipeline has been strengthened with shippers taking advantage of a one-time term extension option and electing a new 10-year toll on approximately 96 percent of the firm capacity available. Advancing Pipeline Expansions - Pembina continues to advance more than $1 billion of proposed pipeline expansions to meet rising transportation demand from growing production across the Montney, Duvernay, and Deep Basin plays. Cedar LNG - As previously disclosed, Pembina has entered into a 20-year agreement with PETRONAS related to 1.0 million tonnes per annum ("mtpa") of Pembina's 1.5 mtpa of capacity at the Cedar LNG facility. Greenlight Electricity Centre - As previously disclosed, Pembina and its partner, Kineticor continue to make significant progress towards the commercialization of the Greenlight Electricity Centre ("Greenlight") and anticipate a final investment decision ("FID") in the first half of 2026. Financial and Operational Overview Financial and Operational Overview by Division For further details on the Company's significant assets, including definitions for capitalized terms used herein that are not otherwise defined, refer to Pembina's Annual Information Form for the year ended December 31, 2024, and Pembina's Management's Discussion and Analysis dated November 6, 2025 for the three and nine months ended September 30, 2025, filed at www.sedarplus.ca (filed with the U.S. Securities and Exchange Commission at www.sec.gov under Form 40-F) and on Pembina's website at www.pembina.com. Executive Overview and Business Update 2025 Guidance Based on year-to-date results and the current commodity price outlook for the remainder of the year, Pembina has updated its 2025 adjusted EBITDA guidance range to $4.25 billion to $4.35 billion (previously $4.225 billion to $4.425 billion). Business Update In executing its strategy, Pembina strives to ensure the long-term resilience of its business and provide investors with visibility to attractive growth through the end of the decade, and beyond. The continued execution of Pembina's strategy is highlighted by the following recent and ongoing developments. Contracting Successes in the Base Business Through ongoing contracting success, Pembina continues to show the value of its conventional pipeline systems, including the Peace Pipeline, in serving customer demand for transportation service within the growing Western Canadian Sedimentary Basin ("WCSB"). Pembina has successfully recontracted substantially all volumes available for renewal under contracts expiring in 2025 and 2026. In particular, Pembina recently signed new transportation agreements on the Peace Pipeline system for the renewal and addition of volumes totaling approximately 50,000 bpd. The contracts have a weighted average term of approximately 10 years and include the dedication of certain lands and facilities for the duration of the terms. Approximately 80 percent of the volumes are currently being serviced, with the renewals taking effect in the fourth quarter of 2025 and the new volumes taking effect in 2026. Consistent with Pembina's previously disclosed expectations, recent shipper elections on Alliance Pipeline have significantly strengthened its long-term contractual profile. The negotiated settlement between Alliance Pipeline Limited Partnership and shippers and interested parties on the Canadian portion of Alliance Pipeline included a revised term-differentiated toll schedule which established a new 10-year toll and reduced the existing 1-year, 3-year, and 5-year tolls. Under the settlement, long-term shippers were provided a one-time term extension option, enabling them to take advantage of the new term-differentiated tolls, effective November 1, 2025. Shippers subsequently elected the 10-year toll option on approximately 96 percent of the 1.325 billion cubic feet per day of firm capacity available. Industry-Leading Project Execution Pembina continues to demonstrate its industry-leading project execution and ability to deliver capital projects that provide strong returns and a competitive service offering. Pembina and Pembina Gas Infrastructure ("PGI") are nearing completion on approximately $850 million (gross) of projects that are expected to enter service throughout the first half of 2026. Construction of RFS IV, a new 55,000 bpd propane-plus fractionator within Pembina's Redwater Complex, has progressed to approximately 75 percent complete. The project continues to trend under budget with an expected in-service date in the second quarter of 2026. PGI's Wapiti Expansion will increase natural gas processing capacity at the Wapiti Plant by 115 mmcf/d (gross). During the third quarter of 2025, construction activities progressed, with tie-in work nearing completion. The project is trending on budget with an expected in-service date in the first quarter of 2026. PGI is developing a 28-megawatt ("MW") cogeneration facility at its K3 Plant, which is expected to reduce overall operating costs by providing power and heat to the gas processing facility, while reducing customers' exposure to power prices. During the third quarter of 2025, engineering work was completed and construction activities progressed. The project is trending under budget with an expected in-service date in the first quarter of 2026. Investing to Meet Growing Demand for Transportation Service Pembina is well advanced on development of approximately $1 billion of conventional pipeline projects. These investments would be supported by a combination of long-term take-or-pay agreements, a cost-of-service structure, and land and facility dedications. In addition to enabling WCSB growth and positioning Pembina to win new liquids transportation opportunities, these projects would also support the Company's downstream value chain, including utilization of the Redwater Complex and marketing business. Engineering activities are ongoing and subject to regulatory and board approval, Pembina expects to move forward with each of the following expansions: Fox Creek-to-Namao Expansion - an expansion of the Peace Pipeline system that, through the addition of new pump stations, would add approximately 70,000 bpd of propane-plus capacity to the market delivery pipelines from Fox Creek, Alberta to Namao, Alberta. A FID is expected by the end of 2025. Taylor-to-Gordondale Project - a new approximately 89-kilometer pipeline, associated pump station, and facility upgrades, proposed by Pouce Coupé Pipe Line Ltd. (a subsidiary of Pembina) connecting mostly condensate volumes from Taylor, British Columbia to the Gordondale, Alberta area. A FID is anticipated in 2026. Birch-to-Taylor NEBC System Expansion - a new 95-kilometre pipeline and facility upgrades that would add propane-plus and condensate capacity to that segment of the NEBC Pipeline system. A FID is expected in 2026. Following successfully contracting the Nipisi Pipeline to serve growing volumes from the Clearwater area, Pembina expects the pipeline to be highly utilized in 2026. With the expectation of continued growth from the Clearwater area and strong customer demand for incremental service, Pembina is currently evaluating opportunities to increase egress capacity, including the optimization or expansion of the Nipisi Pipeline and the re-purposing of existing underutilized assets. Alliance Pipeline previously solicited non-binding expressions of interest ("EOI") for a new short-haul point-to-point transportation service on the Canadian segment of its system in northwest Alberta. The proposed expansion would provide natural gas delivery to a new meter station in Fort Saskatchewan for up to 350 million standard cubic feet per day of incremental capacity with an anticipated in-service date in the fourth quarter of 2029, pending all necessary approvals. Based on the results of the EOI, Alliance Pipeline is planning to launch a binding open season in the first quarter of 2026 for all interested parties. Cedar LNG - Capacity Contracted and Construction Update As previously disclosed, subsidiaries of Pembina and Petroliam Nasional Berhad ("PETRONAS"), have entered into a 20-year agreement (the "LNG Agreement") related to 1.0 mtpa of Pembina's liquefaction capacity at the Cedar LNG facility ("Cedar LNG"). The LNG Agreement is a synthetic liquefaction service structure under which Pembina will provide transportation and liquefaction capacity to PETRONAS and receive a stable long-term, take-or-pay revenue stream with the potential for incremental value enhancement. The LNG Agreement is an extension of the Company's existing relationship with PETRONAS, a global LNG industry leader and one of the largest gas producers in Canada. It is also an important development in Pembina's ongoing expansion of its export business. It further validates Cedar LNG and highlights the strong demand for global export capacity given the clear advantages of Canadian West Coast LNG, including competitively priced feedstock and advantaged shipping distances to Asian markets. It also demonstrates Pembina's commitment to delivering growth and executing its strategy within the Company's long-standing financial guardrails. Pembina previously signed a 20-year take-or-pay liquefaction tolling service agreement for 1.5 mtpa of LNG to support the FID on Cedar LNG in June 2024 and ultimately maintain key project timing and economic parameters, with the expectation of remarketing the capacity at a later stage. The LNG Agreement with PETRONAS marks a significant first step in Pembina's remarketing efforts. Pembina expects to reach definitive agreements for the remaining 0.5 mtpa of capacity by the end of 2025. The 3.3 mtpa, US$4 billion (gross) Cedar LNG project remains on time and on budget. Construction of the floating LNG vessel, including the hull and top side facilities remains on schedule. Cedar LNG has significantly advanced the onshore construction work. Pipeline construction is ahead of schedule, including the completion of all horizontal directional drill (HDD) crossings, a major achievement that derisks that portion of the project. Tree clearing on the transmission line right of way is underway and work on the marine terminal site continues with construction of the retaining wall progressing. Cedar LNG is expected to be in service in late 2028. Greenlight Electricity Centre Advances Towards Commercialization Pembina and Kineticor, an OPTrust portfolio company, continue to make significant progress towards the commercialization of the proposed Greenlight Electricity Centre. Greenlight is a proposed multi-phased natural gas-fired combined cycle power generation facility, to be located in Sturgeon County, Alberta, with a capacity of up to approximately 1,800 MW designed to advance Alberta's innovation economy. As previously disclosed, recent achievements include securing a 907 MW power grid allocation, which was subsequently assigned to a potential customer of Greenlight (the "Customer") to enable development of the Customer's innovation infrastructure development as early as 2027, prior to the startup of Greenlight in 2030. In addition, a recently signed agreement with a reputable manufacturer provides certainty of availability and delivery timing of two turbines to support the approximately 900 MW first phase of Greenlight. Pembina and Kineticor continue to progress towards a final investment decision in the first half of 2026. Greenlight represents an on-strategy extension of Pembina's existing value chain and an opportunity to enhance growth by investing in long-term contracted infrastructure with an investment grade counterparty, while diversifying its customer base. Greenlight would also create incremental demand for natural gas and associated liquids production within western Canada. Pembina is well positioned to leverage the assets and capabilities of its current core business to further support the project and serve customer demand for gas egress and liquids handling and transportation. Most notably, the proximity of Pembina's Alliance Pipeline offers a potential accretive expansion opportunity to supply natural gas to Greenlight. As noted above, Alliance Pipeline is planning to launch a binding open season in the first quarter of 2026 for all interested parties. Financial & Operational Highlights Adjusted EBITDA Pembina reported adjusted EBITDA of $1,034 million in the third quarter, representing a $15 million or one percent increase over the same period in the prior year. Pipelines reported adjusted EBITDA of $630 million for the third quarter, representing a $37 million or six percent increase compared to the same period in the prior year, reflecting the net impact of the following factors: higher demand on seasonal contracts on Alliance Pipeline; higher revenue on the Peace Pipeline system due to increased tolls, mainly related to contractual inflation adjustments; higher interruptible volumes on the Peace Pipeline system; higher contracted volumes on the Nipisi Pipeline; and lower firm tolls on the Cochin Pipeline, due to recontracting in July 2024, and lower interruptible volumes due to narrower condensate price differentials, offset by higher contracted volumes as the third quarter of 2024 was impacted by a contracting gap from mid-July to August 1, 2024, associated with the return of line fill to certain customers. Facilities reported adjusted EBITDA of $354 million for the third quarter, representing a $30 million or nine percent increase over the same period in the prior year, reflecting the net impact of the following factors: higher contribution from PGI, primarily related to transactions with Whitecap Resources Inc., higher capital recoveries due to a turnaround, and higher volumes at the Duvernay Complex. Marketing & New Ventures reported adjusted EBITDA of $99 million for the third quarter, representing a $60 million or 38 percent decrease compared to the same period in the prior year, reflecting the net impact of the following factors: lower net revenue due to a decrease in NGL margins as a result of lower NGL prices, coupled with higher input natural gas prices at Aux Sable; higher NGL marketed volumes, including no similar impact of the nine-day outage at Aux Sable in 2024; and lower realized gains on crude oil-based derivatives, partially offset by lower realized losses on NGL-based derivatives. Corporate reported adjusted EBITDA of negative $49 million for the third quarter, representing a $8 million or 14 percent increase compared to the same period in the prior year, primarily reflecting lower long-term incentive costs, partially offset by increases in other general and administrative expenses. Earnings Pembina reported third quarter earnings of $286 million, representing a $99 million or 26 percent decrease over the same period in the prior year. Pipelines had earnings in the third quarter of $477 million, representing a $44 million or 10 percent increase over the prior period. In addition to the factors impacting adjusted EBITDA, as noted above, the change in earnings was due to the recognition of a gain on the sale of the north segment of Western Pipeline, offset by higher depreciation and amortization due to the decrease in the estimated useful life of an intangible asset. Facilities had earnings in the third quarter of $58 million, representing a $73 million or 56 percent decrease over the prior period. In addition to the factors impacting adjusted EBITDA, as noted above, the change in earnings was due to a share of loss from PGI due to an impairment of $146 million (net to Pembina, after tax) recognized in the third quarter of 2025 on certain PGI assets, and depreciation expense resulting from a larger asset base following recent transactions and asset upgrades, partially offset by the recognition of a gain following the amendment of PGI's credit facility in the third quarter of 2025, lower losses recognized by PGI on interest rate derivative financial instruments, and lower unrealized losses on commodity-related derivatives. Marketing & New Ventures had earnings in the third quarter of $68 million, representing a $57 million or 46 percent decrease over the prior period. In addition to the factors impacting adjusted EBITDA, as noted above, the change in earnings was due to a lower share of loss from Cedar LNG, primarily due to the impact of hedging activities on the credit facility. Quarterly Common Share Dividend Pembina's board of directors has declared a common share cash dividend for the fourth quarter of 2025 of $0.71 per share, to be paid, subject to applicable law, on December 31, 2025, to shareholders of record on December 15, 2025. The common share dividends are designated as "eligible dividends" for Canadian income tax purposes. For non-resident shareholders, Pembina's common share dividends should be considered "qualified dividends" and may be subject to Canadian withholding tax. For shareholders receiving their common share dividends in U.S. funds, the cash dividend is expected to be approximately U.S.$0.5028 per share (before deduction of any applicable Canadian withholding tax) based on a currency exchange rate of 0.7082. The actual U.S. dollar dividend will depend on the Canadian/U.S. dollar exchange rate on the payment date and will be subject to applicable withholding taxes. Quarterly dividend payments are expected to be made on the last business day of March, June, September and December to shareholders of record on the 15th day of the corresponding month, if, as and when declared by the board of directors. Should the record date fall on a weekend or on a statutory holiday, the record date will be the next succeeding business day following the weekend or statutory holiday. Third Quarter 2025 Conference Call & Webcast Pembina will host a conference call on Friday, November 7, 2025, at 8:00 a.m. MT (10:00 a.m. ET) for interested investors, analysts, brokers, and media representatives to discuss results for the third quarter of 2025. The conference call dial-in numbers for Canada and the U.S. are 1-289-819-1520 or 1-800-549-8228. A recording of the conference call will be available for replay until Friday, November 14, 2025, at 11:59 p.m. ET. To access the replay, please dial either 1-289-819-1325 or 1-888-660-6264 and enter the password 43626 #. A live webcast of the conference call can be accessed on Pembina's website at www.pembina.com under Investor Centre/Presentations & Events, or by entering: https://events.q4inc.com/attendee/317616572 in your web browser. Shortly after the call, an audio archive will be posted on the website for a minimum of 90 days. About Pembina Pembina Pipeline Corporation is a leading energy transportation and midstream service provider that has served North America's energy industry for more than 70 years. Pembina owns an extensive network of strategically located assets, including hydrocarbon liquids and natural gas pipelines, gas gathering and processing facilities, oil and natural gas liquids infrastructure and logistics services, and an export terminals business. Through our integrated value chain, we seek to provide safe and reliable energy solutions that connect producers and consumers across the world, support a more sustainable future and benefit our customers, investors, employees and communities. For more information, please visit www.pembina.com. Purpose of Pembina: We deliver extraordinary energy solutions so the world can thrive. Pembina is structured into three Divisions: Pipelines Division, Facilities Division and Marketing & New Ventures Division. Pembina's common shares trade on the Toronto and New York stock exchanges under PPL and PBA, respectively. For more information, visit www.pembina.com. Forward-Looking Statements and Information This news release contains certain forward-looking statements and forward-looking information (collectively, "forward-looking statements"), including forward-looking statements within the meaning of the "safe harbor" provisions of applicable securities legislation, that are based on Pembina's current expectations, estimates, projections and assumptions in light of its experience and its perception of historical trends. In some cases, forward-looking statements can be identified by terminology such as "continue", "anticipate", "schedule", "will", "expects", "estimate", "potential", "planned", "future", "outlook", "strategy", "project", "plan", "commit", "maintain", "focus", "ongoing", "believe" and similar expressions suggesting future events or future performance. In particular, this news release contains forward-looking statements, including certain financial outlooks, pertaining to, without limitation, the following: Pembina's updated 2025 adjusted EBITDA guidance, as well as the factors impacting such future results; Pembina's 2026 guidance, including the timing for issuance thereof; future pipeline, processing, fractionation and storage facility and system operations and throughput levels; treatment under existing and potential governmental policies and regulations, including expectations regarding their impact on Pembina; Pembina's strategy and the development of new business initiatives and growth opportunities, including the anticipated benefits therefrom and the expected timing thereof; expectations about current and future market conditions, industry activities and development opportunities, as well as the anticipated impacts thereof, including general market conditions outlooks and industry developments; expectations about future demand for Pembina's infrastructure and services, including expectations in respect of customer contracts, future volume growth in the WCSB and the drivers thereof, increased utilization and future tolls and volumes; expectations relating to the development of Pembina's new projects and developments, including Cedar LNG, RFS IV, PGI's Wapiti Expansion, PGI's K3 cogeneration facility, the Fox Creek-to-Namao Peace Pipeline expansion, the Birch-to-Taylor NEBC System expansion, the Taylor to Gordondale project, and the Greenlight Electricity Centre, including the outcomes, timing and anticipated benefits thereof; statements regarding commercial discussions regarding the assignment of Pembina's remaining contracted capacity for Cedar LNG, including the timing thereof; Pembina's future common share dividends, including the timing, amount and expected tax treatment thereof; statements regarding optimization and expansion opportunities being evaluated or pursued by Pembina, including future actions which may be taken by Pembina in connection with such opportunities and the outcomes thereof; planning, construction, locations, capital expenditure and funding estimates, schedules, regulatory and environmental applications and anticipated approvals, expected capacity, incremental volumes, contractual arrangements, completion and in-service dates, sources of product, activities, benefits and operations with respect to new construction of, or expansions on existing pipelines, systems, gas services facilities, processing and fractionation facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure, as well as the impact of Pembina's new projects on its future financial performance; and expectations regarding existing and future commercial agreements, including the expected timing and benefit thereof. The forward-looking statements are based on certain factors and assumptions that Pembina has made in respect thereof as at the date of this news release regarding, among other things: oil and gas industry exploration and development activity levels and the geographic region of such activity; the success of Pembina's operations; prevailing commodity prices, interest rates, carbon prices, tax rates, exchange rates and inflation rates; the ability of Pembina to maintain current credit ratings; the availability and cost of capital to fund future capital requirements relating to existing assets, projects and the repayment or refinancing of existing debt as it becomes due; future operating costs; geotechnical and integrity costs; that any third-party projects relating to Pembina's growth projects will be sanctioned and completed as expected; assumptions with respect to our intention to complete share repurchases, including the funding thereof, existing and future market conditions, including with respect to Pembina's common share trading price, and compliance with respect to applicable securities laws and regulations and stock exchange policies; that any required commercial agreements can be reached in the manner and on the terms expected by Pembina; that all required regulatory and environmental approvals can be obtained on acceptable terms and in a timely manner; that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of the relevant projects; prevailing regulatory, tax and environmental laws and regulations; maintenance of operating margins; the amount of future liabilities relating to lawsuits and environmental incidents; and the availability of coverage under Pembina's insurance policies (including in respect of Pembina's business interruption insurance policy). Although Pembina believes the expectations and material factors and assumptions reflected in these forward-looking statements are reasonable as of the date hereof, there can be no assurance that these expectations, factors and assumptions will prove to be correct. These forward-looking statements are not guarantees of future performance and are subject to a number of known and unknown risks and uncertainties including, but not limited to: the regulatory environment and decisions, including the outcome of regulatory hearings, and Indigenous and landowner consultation requirements; the impact of competitive entities and pricing; reliance on third parties to successfully operate and maintain certain assets; reliance on key relationships, joint venture partners and agreements; labour and material shortages; the strength and operations of the oil and natural gas production industry and related commodity prices; non-performance or default by contractual counterparties ; actions by governmental or regulatory authorities, including changes in laws and treatment, changes in royalty rates, regulatory decisions, changes in regulatory processes or increased environmental regulation; the ability of Pembina to acquire or develop the necessary infrastructure in respect of future development projects; Pembina's ability to realize the anticipated benefits of recent acquisitions; fluctuations in operating results; adverse general economic and market conditions, including potential recessions in Canada, North America and worldwide resulting in changes, or prolonged weaknesses, as applicable, in interest rates, foreign currency exchange rates, inflation, commodity prices, supply/demand trends and overall industry activity levels; new Canadian and/or U.S. trade policies or barriers, including the imposition of new tariffs, duties or other trade restrictions; constraints on the, or the unavailability of, adequate supplies, infrastructure or labour; the political environment in North America and elsewhere, including changes in trade relations between Canada and the U.S., and public opinion thereon; the ability to access various sources of debt and equity capital; adverse changes in credit ratings; counterparty credit risk; technology and cyber security risks; natural catastrophes; and certain other risks detailed in Pembina's Annual Information Form and Management's Discussion and Analysis, each dated February 27, 2025 for the year ended December 31, 2024 and from time to time in Pembina's public disclosure documents available at www.sedarplus.ca, www.sec.gov and through Pembina's website at www.pembina.com. This list of risk factors should not be construed as exhaustive. Readers are cautioned that events or circumstances could cause results to differ materially from those predicted, forecasted or projected by forward-looking statements contained herein. The forward-looking statements contained in this news release speak only as of the date of this news release. Pembina does not undertake any obligation to publicly update or revise any forward-looking statements or information contained herein, except as required by applicable laws. Management approved the updated 2025 adjusted EBITDA guidance contained herein on November 6, 2025. The purpose of these financial outlooks is to assist readers in understanding Pembina's expected and targeted financial results, and this information may not be appropriate for other purposes. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement. Non-GAAP and Other Financial Measures Throughout this news release, Pembina has disclosed certain financial measures and ratios that are not specified, defined or determined in accordance with GAAP and which are not disclosed in Pembina's financial statements. Non-GAAP financial measures either exclude an amount that is included in, or include an amount that is excluded from, the composition of the most directly comparable financial measure specified, defined and determined in accordance with GAAP. Non-GAAP ratios are financial measures that are in the form of a ratio, fraction, percentage or similar representation that has a non-GAAP financial measure as one or more of its components. These non-GAAP financial measures and non-GAAP ratios, together with financial measures and ratios specified, defined and determined in accordance with GAAP, are used by management to evaluate the performance and cash flows of Pembina and its businesses and to provide additional useful information respecting Pembina's financial performance and cash flows to investors and analysts. In this news release, Pembina has disclosed the following non-GAAP financial measures and non-GAAP ratios: net revenue, adjusted EBITDA, adjusted EBITDA from equity accounted investees, adjusted cash flow from operating activities and adjusted cash flow from operating activities per common share. The non-GAAP financial measures and non-GAAP ratios disclosed in this news release do not have any standardized meaning under International Financial Reporting Standards ("IFRS") and may not be comparable to similar financial measures or ratios disclosed by other issuers. Such financial measures and ratios should not, therefore, be considered in isolation or as a substitute for, or superior to, measures and ratios of Pembina's financial performance, or cash flows specified, defined or determined in accordance with IFRS, including revenue, earnings, cash flow from operating activities and cash flow from operating activities per share. Except as otherwise described herein, these non-GAAP financial measures and non-GAAP ratios are calculated on a consistent basis from period to period. Specific reconciling items may only be relevant in certain periods. Below is a description of each non-GAAP financial measure and non-GAAP ratio disclosed in this news release, together with, as applicable, disclosure of the most directly comparable financial measure that is determined in accordance with GAAP to which each non-GAAP financial measure relates and a quantitative reconciliation of each non-GAAP financial measure to such directly comparable GAAP financial measure. Additional information relating to such non-GAAP financial measures and non-GAAP ratios, including disclosure of the composition of each non-GAAP financial measure and non-GAAP ratio, an explanation of how each non-GAAP financial measure and non-GAAP ratio provides useful information to investors and the additional purposes, if any, for which management uses each non-GAAP financial measure and non-GAAP ratio; an explanation of the reason for any change in the label or composition of each non-GAAP financial measure and non-GAAP ratio from what was previously disclosed; and a description of any significant difference between forward-looking non-GAAP financial measures and the equivalent historical non-GAAP financial measures, is contained in the "Non-GAAP & Other Financial Measures" section of the management's discussion and analysis of Pembina dated November 6, 2025 for the quarter ended September 30, 2025 (the "MD&A"), which information is incorporated by reference in this news release. The MD&A is available on SEDAR+ at www.sedarplus.ca, EDGAR at www.sec.gov and Pembina's website at www.pembina.com. Net Revenue Net revenue is a non-GAAP financial measure which is defined as total revenue less cost of goods. The most directly comparable financial measure to net revenue that is determined in accordance with GAAP and disclosed in Pembina's financial statements is revenue. Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization Adjusted EBITDA is a non-GAAP financial measure and is calculated as earnings before net finance costs, income taxes, depreciation and amortization (included in gross profit and general and administrative expense), and unrealized gains or losses from derivative instruments. The exclusion of unrealized gains or losses from derivative instruments eliminates the non-cash impact of such gains or losses. Adjusted EBITDA also includes adjustments to earnings for non-controlling interest, losses (gains) on disposal of assets, transaction costs incurred in respect of acquisitions, dispositions and restructuring, impairment charges or reversals in respect of goodwill, intangible assets, investments in equity accounted investees and property, plant and equipment, certain non-cash provisions and other amounts not reflective of ongoing operations. These additional adjustments are made to exclude various non-cash and other items that are not reflective of ongoing operations. Following completion of Pembina acquiring a controlling ownership interest in Alliance and Aux Sable on April 1, 2024, Pembina revised the definition of adjusted EBITDA to deduct earnings for the 14.6 percent non-controlling interest in the Aux Sable U.S. operations. Pembina's subsequent acquisition of the remaining interest in Aux Sable's U.S. operations in the third quarter of 2024 resulted in all of Aux Sable's results being included in the adjusted EBITDA calculation beginning on August 1, 2024. Management believes that adjusted EBITDA provides useful information to investors as it is an important indicator of Pembina's ability to generate liquidity through cash flow from operating activities and equity accounted investees. Management also believes that adjusted EBITDA provides an indicator of operating income generated from capital expenditures, which includes operational finance income and gains from lessor lease arrangements. Adjusted EBITDA is also used by investors and analysts for assessing financial performance and for the purpose of valuing Pembina, including calculating financial and leverage ratios. Management utilizes adjusted EBITDA to set objectives and as a key performance indicator of the Company's success. Pembina presents adjusted EBITDA as management believes it is a measure frequently used by analysts, investors and other stakeholders in evaluating the Company's financial performance. The most directly comparable financial measure to adjusted EBITDA that is specified, defined and determined in accordance with GAAP and disclosed in Pembina's financial statements is earnings. Adjusted EBITDA from Equity Accounted Investees In accordance with IFRS, Pembina's joint ventures are accounted for using equity accounting. Under equity accounting, the assets and liabilities of the investment are presented net in a single line item in the Consolidated Statement of Financial Position, "Investments in Equity Accounted Investees". Earnings from investments in equity accounted investees are recognized in a single line item in the Consolidated Statement of Earnings and Comprehensive Income "Share of Profit from Equity Accounted Investees". The adjustments made to earnings, in adjusted EBITDA above, are also made to share of profit from investments in equity accounted investees. Cash contributions and distributions from investments in equity accounted investees represent Pembina's share paid and received in the period to and from the investments in equity accounted investees. To assist in understanding and evaluating the performance of these investments, Pembina is supplementing the IFRS disclosure with non-GAAP proportionate consolidation of Pembina's interest in the investments in equity accounted investees. Pembina's proportionate interest in equity accounted investees has been included in adjusted EBITDA. Adjusted Cash Flow from Operating Activities and Adjusted Cash Flow from Operating Activities per Common Share Adjusted cash flow from operating activities is a non-GAAP measure which is defined as cash flow from operating activities adjusting for the change in non-cash operating working capital, adjusting for current tax and share-based compensation payments, and deducting distributions to non-controlling interests and preferred share dividends paid. Adjusted cash flow from operating activities deducts distributions to non-controlling interest and preferred share dividends paid because they are not attributable to common shareholders. The calculation has been modified to exclude current tax expense and accrued share-based payment expense, and to include the impact of cash paid for taxes and share-based compensation, as it allows management to better assess the obligations discussed below. Management believes that adjusted cash flow from operating activities provides comparable information to investors for assessing financial performance during each reporting period. Management utilizes adjusted cash flow from operating activities to set objectives and as a key performance indicator of the Company's ability to meet interest obligations, dividend payments and other commitments. Adjusted cash flow from operating activities per common share is a non-GAAP financial ratio which is calculated by dividing adjusted cash flow from operating activities by the weighted average number of common shares outstanding. Following completion of Pembina acquiring a controlling ownership interest in Alliance and Aux Sable on April 1, 2024, Pembina revised the definition of adjusted cash flow from operating activities to deduct distributions related to non-controlling interest in the Aux Sable U.S. operations. On August 1, 2024, Pembina acquired the remaining interest in Aux Sable's U.S. operations. View source version on businesswire.com: https://www.businesswire.com/news/home/20251106637433/en/ back
EOG Resources Reports Third Quarter 2025 Results
EOG Resources Reports Third Quarter 2025 Results HOUSTON, Nov. 6, 2025 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported third quarter 2025 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions and discussion, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors. Key Financial ResultsIn millions of USD, except per-share, per-Boe and ratio data GAAP 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Total Revenue 5,847 5,478 5,669 5,585 5,965 Net Income 1,471 1,345 1,463 1,251 1,673 Net Income Per Share 2.70 2.46 2.65 2.23 2.95 Net Cash Provided by Operating Activities 3,111 2,032 2,289 2,763 3,588 Total Expenditures 8,544 1,883 1,546 1,446 1,573 Current and Long-Term Debt 7,694 4,236 4,744 4,752 3,776 Cash and Cash Equivalents 3,530 5,216 6,599 7,092 6,122 Debt-to-Total Capitalization 20.3 % 12.7 % 13.8 % 13.9 % 11.3 % Cash Operating Costs ($/Boe) 10.50 10.05 10.31 10.15 10.15 Non-GAAP Adjusted Net Income 1,472 1,268 1,586 1,535 1,644 Adjusted Net Income Per Share 2.71 2.32 2.87 2.74 2.89 Adjusted CFO1 3,031 2,496 2,813 2,635 2,988 Capital Expenditures 1,648 1,523 1,484 1,358 1,497 Free Cash Flow 1,383 973 1,329 1,277 1,491 Net Debt 4,164 (980) (1,855) (2,340) (2,346) Net Debt-to-Total Capitalization 12.1 % (3.5 %) (6.7 %) (8.7 %) (8.6 %) Cash Operating Costs ($/Boe) 2,3 9.93 9.94 10.31 10.15 10.05 Third Quarter Highlights Earned adjusted net income of $1.5 billion, or $2.71 per share Generated $1.4 billion of free cash flow Paid $545 million in regular dividends and repurchased $440 million of shares Oil, NGLs and natural gas production above guidance midpoints Capital expenditures and per-unit operating costs better than guidance midpoints Closed on the acquisition of Encino Acquisition Partners (Encino) Third Quarter 2025 Highlights and Cash Return Volumes and Capital Expenditures Volumes 3Q 2025 3Q 2025Guidance Midpoint 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Crude Oil and Condensate (MBod) 534.5 532.4 504.2 502.1 494.6 493.0 Natural Gas Liquids (MBbld) 309.3 305.0 258.4 241.7 252.5 254.3 Natural Gas (MMcfd) 2,745 2,735 2,229 2,080 2,092 1,970 Total Crude Oil Equivalent (MBoed) 1,301.2 1,293.3 1,134.1 1,090.4 1,095.7 1,075.7 Capital Expenditures ($MM) 1,648 1,650 1,523 1,484 1,358 1,497 From Ezra Yacob, Chairman and Chief Executive Officer"EOG delivered another quarter of strong operational performance. Third quarter oil, gas, and NGL volumes exceeded the midpoints of our guidance. Higher volumes, combined with lower-than-expected per-unit cash operating costs and DD&A, helped drive outstanding financial results. We generated substantial free cash flow of $1.4 billion, which helped support nearly $1.0 billion of cash return to shareholders, including $440 million of opportunistic share repurchases. As of quarter-end, we have committed to return 89% of our estimated annual free cash flow to shareholders, with the potential to return additional cash over the balance of the year. Our ability to deliver operational excellence quarter after quarter is the result of EOG's unique culture and the quality of our multi-basin portfolio. EOG's foundational assets, the Delaware Basin, Eagle Ford, and Utica, are delivering strong returns, exceeding our expectations. In the Utica, the integration of the Encino assets is proceeding exceptionally well, with continued incremental efficiency gains. Our emerging and international assets are also performing well, with strong well results in Dorado, the Powder River Basin, and Trinidad, along with continued progress in our exploration prospects in Bahrain and the UAE. Our business has never been stronger. Our pristine balance sheet provides unmatched flexibility to continue to improve our high-return, long-duration asset base while delivering significant cash returns through commodity price cycles. EOG has never been better positioned to create long-term value for our shareholders." Regular Dividend and Third Quarter Share RepurchasesThe Board of Directors today declared a dividend of $1.02 per share on EOG's common stock. The dividend will be payable January 30, 2026, to shareholders of record as of January 16, 2026. This dividend represents an indicated annual rate of $4.08 per share. EOG has never suspended or reduced its regular dividend. During the third quarter, the company repurchased 3.8 million shares for $440 million under its share repurchase authorization. EOG has $4.0 billion remaining on its current share buyback authorization. Third Quarter 2025 Financial Performance Prices NGL and natural gas prices decreased in 3Q compared with 2Q, partially offset by higher crude oil & condensate prices Volumes Oil production of 534.5 MBod was above the midpoint of the guidance range NGL production of 309.3 MBbld was above the midpoint of the guidance range Natural gas production of 2,745 MMcfd was above the midpoint of the guidance range Total company equivalent production of 1,301.2 MBoed was above the midpoint of the guidance range Per-Unit Costs LOE, non-GAAP G&A and DD&A costs decreased in 3Q compared to 2Q, while GP&T costs increased. Encino acquisition-related costs increased GAAP G&A costs in 3Q compared to 2Q Hedges Mark-to-market hedge gains increased GAAP earnings per share in 3Q compared with 2Q Cash received to settle hedges increased adjusted non-GAAP earnings per share in 3Q compared with 2Q Free Cash Flow Adjusted cash flow from operations was $3.0 billion Incurred $1.6 billion of capital expenditures Generated $1.4 billion of free cash flow Cash Return and Working Capital Paid $545 million in regular dividends Repurchased $440 million of stock Closed on the acquisition of Encino for $5.7 billion, subject to post-closing adjustments Issued $3.5 billion of senior notes in conjunction with the Encino acquisition Third Quarter 2025 Operating Performance Lease and Well QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower workover expenses Guidance Midpoint: Lower primarily due to lower workover expenses and operating and maintenance costs General and Administrative (Non-GAAP) QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encino operations, and lower employee-related expenses Guidance Midpoint: Lower primarily due to lower employee-related expenses Gathering, Processing and Transportation Costs QoQ: Increased primarily due to the impact of higher Utica production from the integration of Encino operations Guidance Midpoint: Lower primarily due to lower natural gas gathering and processing fees Depreciation, Depletion and Amortization QoQ: Decreased primarily due to the impact of higher Utica production and well mix Guidance Midpoint: Lower primarily due to the addition of lower-cost reserves Third Quarter 2025 Results vs Guidance (Unaudited) See "Endnotes" below for related discussion and definitions. 3Q 2025 3Q 2025 Guidance Midpoint 6 Variance 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Crude Oil and Condensate Volumes (MBod) United States 532.9 531.0 1.9 503.1 500.9 493.5 491.8 Trinidad 1.6 1.4 0.2 1.1 1.2 1.1 1.2 Total 534.5 532.4 2.1 504.2 502.1 494.6 493.0 Natural Gas Liquids Volumes (MBbld) Total 309.3 305.0 4.3 258.4 241.7 252.5 254.3 Natural Gas Volumes (MMcfd) United States 2,511 2,525 (14) 1,977 1,834 1,840 1,745 Trinidad 230 210 20 252 246 252 225 Other International7 4 0 4 0 0 0 0 Total 2,745 2,735 10 2,229 2,080 2,092 1,970 Total Crude Oil Equivalent Volumes (MBoed) 1,301.2 1,293.3 7.9 1,134.1 1,090.4 1,095.7 1,075.7 Total MMBoe 119.7 119.0 0.7 103.2 98.1 100.8 99.0 Benchmark Price Oil (WTI) ($/Bbl) 64.95 63.71 71.42 70.28 75.16 Natural Gas (HH) ($/Mcf) 3.07 3.44 3.66 2.79 2.16 Crude Oil and Condensate - above (below) WTI 8 ($/Bbl) United States 1.02 0.80 0.22 1.13 1.48 1.40 1.79 Trinidad (7.21) (5.00) (2.21) (9.21) (10.30) (9.81) (12.01) Natural Gas Liquids - Realizations as % of WTI Total 32.7 % 34.0 % (1.3 %) 35.6 % 36.8 % 33.9 % 29.8 % Natural Gas - above (below) NYMEX Henry Hub 9 ($/Mcf) United States (0.36) (0.40) 0.04 (0.57) (0.30) (0.40) (0.32) Natural Gas Realizations ($/Mcf) Trinidad 3.80 3.60 0.20 3.65 3.78 3.86 3.68 Other International7 3.27 0.00 3.27 0.00 0.00 0.00 0.00 Total Expenditures (GAAP) ($MM) 8,544 1,883 1,546 1,446 1,573 Capital Expenditures (non-GAAP) ($MM) 1,648 1,650 (2) 1,523 1,484 1,358 1,497 Operating Unit Costs ($/Boe) Lease and Well 3.60 3.70 (0.10) 3.84 4.09 3.91 3.96 Gathering, Processing and Transportation Costs5 4.90 5.10 (0.20) 4.41 4.48 4.37 4.50 General and Administrative (GAAP) 2.00 1.50 0.50 1.80 1.74 1.87 1.69 General and Administrative (non-GAAP)2,3 1.43 1.50 (0.07) 1.69 1.74 1.87 1.59 Cash Operating Costs (GAAP) 10.50 10.30 0.20 10.05 10.31 10.15 10.15 Cash Operating Costs (non-GAAP)2,3 9.93 10.30 (0.37) 9.94 10.31 10.15 10.05 Depreciation, Depletion and Amortization 9.77 9.85 (0.08) 10.20 10.32 10.11 10.42 Expenses ($MM) Exploration and Dry Hole 71 75 (4) 85 75 60 43 Impairment (GAAP) 71 39 44 276 15 Impairment (excluding certain impairments (non-GAAP))10 71 70 1 28 44 23 15 Capitalized Interest 27 21 6 11 12 13 12 Net Interest (GAAP) 71 83 (12) 51 47 38 31 Net Interest (non-GAAP)11 71 83 (12) 45 47 38 31 TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (GAAP) 6.8 % 7.5 % (0.7 %) 7.3 % 7.6 % 6.8 % 6.5 % (non-GAAP)3 6.8 % 7.5 % (0.7 %) 7.3 % 7.6 % 6.8 % 7.2 % Income Taxes Effective Rate 19.4 % 20.5 % (1.1 %) 23.2 % 22.1 % 23.0 % 21.6 % Current Tax Expense ($MM) 75 180 (105) 301 370 454 240 Fourth Quarter and Full-Year 2025 Guidance12 (Unaudited) See "Endnotes" below for related discussion and definitions. 4Q 2025 Guidance Range 4Q 2025 Midpoint FY 2025 Guidance Range FY 2025Midpoint Crude Oil and Condensate Volumes (MBod) United States 541.4 - 546.0 543.7 518.7 - 521.9 520.3 Trinidad 1.1 - 1.5 1.3 1.1 - 1.5 1.3 Total 542.5 - 547.5 545.0 519.8 - 523.4 521.6 Natural Gas Liquids Volumes (MBbld) Total 315.5 - 330.5 323.0 280.0 - 286.0 283.0 Natural Gas Volumes (MMcfd) United States 2,740 - 2,840 2,790 2,250 - 2,310 2,280 Trinidad 190 - 210 200 220 - 240 230 Total 2,930 - 3,050 2,990 2,470 - 2,550 2,510 Crude Oil Equivalent Volumes (MBoed) United States 1,313.6 - 1,349.8 1,331.7 1,173.7 - 1,192.9 1,183.3 Trinidad 32.8 - 36.5 34.7 37.8 - 41.5 39.7 Total 1,346.4 - 1,386.3 1,366.4 1,211.5 - 1,234.4 1,223.0 Crude Oil and Condensate - above (below) WTI 8 ($/Bbl) United States (0.50) - 1.00 0.25 0.35 - 1.35 0.85 Trinidad (5.25) - (2.75) (4.00) (8.40) - (6.90) (7.65) Natural Gas Liquids - Realizations as % of WTI Total 28.0 % - 38.0 % 33.0 % 31.5 % - 36.5 % 34.0 % Natural Gas - above (below) NYMEX Henry Hub 9 ($/Mcf) United States (0.80) - (0.10) (0.45) (0.95) - 0.05 (0.45) Natural Gas Realizations ($/Mcf) Trinidad 3.00 - 4.20 3.60 3.40 - 3.90 3.65 Capital Expenditures 13 ($MM) 1,600 - 1,700 1,650 6,200 - 6,400 6,300 Operating Unit Costs ($/Boe) Lease and Well 3.50 - 4.00 3.75 3.70 - 3.90 3.80 Gathering, Processing and Transportation Costs5 4.75 - 5.25 5.00 4.65 - 4.85 4.75 General and Administrative 1.40 - 1.70 1.55 1.45 - 1.65 1.55 Cash Operating Costs 9.65 - 10.95 10.30 9.80 - 10.40 10.10 Depreciation, Depletion and Amortization 9.25 - 10.25 9.75 9.70 - 10.30 10.00 Expenses ($MM) Exploration and Dry Hole 40 - 80 60 270 - 310 290 Impairment (excluding certain impairments)10 30 - 110 70 180 - 260 220 Capitalized Interest 34 - 38 36 85 - 89 87 Net Interest 64 - 68 66 228 - 232 230 TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) 6.0 % - 8.0 % 7.0 % 6.5 % - 8.5 % 7.5 % Income Taxes Effective Rate 20.0 % - 25.0 % 22.5 % 19.0 % - 24.0 % 21.5 % Current Tax Expense ($MM) 220 - 320 270 970 - 1,070 1,020 Third Quarter 2025 Results WebcastFriday, November 7, 2025, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. http://investors.eogresources.com/investors About EOGEOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com. Investor ContactsPearce Hammond 713-571-4684Neel Panchal 713-571-4884Shelby O'Connor 713-571-4560 Media ContactKimberly Ehmer 713-571-4676 Endnotes 1) Cash flow from operations before changes in working capital and certain acquisition-related costs. 2) Cash Operating Costs consist of LOE, GP&T and G&A. Excludes Encino acquisition-related G&A costs of $68 million for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such Encino acquisition-related costs on G&A and total Cash Operating Costs for 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Third Quarter 2025 Results vs Guidance" above. G&A per Boe (GAAP) for 3Q 2025 was $2.00 and for 2Q 2025 was $1.80. 3) Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non-GAAP) and G&A (non-GAAP) for 3Q 2024 exclude a state severance tax refund and related consulting fees, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024 was $(0.10) as set forth in "Third Quarter 2025 Results vs Guidance" above. 4) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares. 5) Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line-item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. 6) GAAP and non-GAAP distinctions apply solely to actual results and do not pertain to EOG's third quarter 2025 guidance midpoint disclosures. 7) Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distribution costs. 8) EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. 9) EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. 10) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). 11) Net interest expense (non-GAAP) excludes Encino acquisition-related financing commitment costs of $6 million in 2Q 2025. 12) The forecast items for the fourth quarter and full year 2025 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. 13) The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses. Glossary Acq Acquisitions Adjusted CFO Cash flow from operations before changes in working capital and certain acquisition-related costs ATROR After-tax rate of return Bbl Barrel Bn Billion Boe Barrels of oil equivalent Bopd Barrels of oil per day CAGR Compound annual growth rate Capex Capital expenditures CO2e Carbon dioxide equivalent DD&A Depreciation, Depletion and Amortization Disc Discoveries Divest Divestitures EPS Earnings per share Ext Extensions GAAP Generally Accepted Accounting Principles G&A General and administrative expense G&P Gathering and processing GHG Greenhouse gas GP&T Gathering, processing & transportation expense HH Henry Hub LOE Lease operating expense, or lease and well expense MBbld Thousand barrels of liquids per day MBod Thousand barrels of oil per day MBoe Thousand barrels of oil equivalent MBoed Thousand barrels of oil equivalent per day Mcf Thousand cubic feet of natural gas MMBoe Million barrels of oil equivalent MMcfd Million cubic feet of natural gas per day NGLs Natural gas liquids NYMEX U.S. New York Mercantile Exchange OTP Other than price QoQ Quarter over quarter TOTI Taxes other than income USD United States dollar WTI West Texas Intermediate YoY Year over year $MM Million United States dollars $/Bbl U.S. Dollars per barrel $/Boe U.S. Dollars per barrel of oil equivalent $/Mcf U.S. Dollars per thousand cubic feet This press release and any accompanying disclosures may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG's acquisition of Encino Acquisition Partners, LLC (Encino) are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino's assets and operations or the strategic rationale for, or anticipated benefits of, EOG's acquisition of Encino, in each case are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others: the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities; the extent to which EOG is successful in its efforts to acquire or discover additional reserves; the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations; the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures; the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas; security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents; the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment; the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases; the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; the impact of climate change-related legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change; the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives; EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations); EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties; the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations; competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties; the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities; the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG; EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements; the extent to which EOG is successful in its completion of planned asset dispositions; the extent and effect of any hedging activities engaged in by EOG; the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions; the economic and financial impact of epidemics, pandemics or other public health issues; geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates; the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. Historical Non-GAAP Financial Measures:Reconciliation schedules and definitions for the historical non-GAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com. Cautionary Notice Regarding Forward-Looking Non-GAAP Financial Measures:In addition, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow, adjusted cash flow from operations and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures without unreasonable efforts. The unavailable information could have a significant impact on our ultimate results. However, management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Oil and Gas Reserves:The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release or any accompanying disclosures that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (and any updates to such disclosure set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. Income Statements In millions of USD, except share data (in millions) and per share data (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Operating Revenues and Other Crude Oil and Condensate 3,480 3,692 3,488 3,261 13,921 3,293 2,974 3,243 9,510 Natural Gas Liquids 513 515 524 554 2,106 572 534 604 1,710 Natural Gas 382 303 372 494 1,551 637 600 707 1,944 Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 237 (47) 79 (65) 204 (191) 107 116 32 Gathering, Processing and Marketing 1,459 1,519 1,481 1,341 5,800 1,340 1,247 1,178 3,765 Gains (Losses) on Asset Dispositions, Net 26 20 (7) (23) 16 (1) - (18) (19) Other, Net 26 23 28 23 100 19 16 17 52 Total 6,123 6,025 5,965 5,585 23,698 5,669 5,478 5,847 16,994 Operating Expenses Lease and Well 396 390 392 394 1,572 401 396 431 1,228 Gathering, Processing and Transportation Costs 413 423 445 441 1,722 440 455 587 1,482 Exploration Costs 45 34 43 52 174 41 74 71 186 Dry Hole Costs 1 5 - 8 14 34 11 - 45 Impairments 19 81 15 276 391 44 39 71 154 Marketing Costs 1,404 1,490 1,500 1,323 5,717 1,325 1,216 1,134 3,675 Depreciation, Depletion and Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 3,235 General and Administrative 162 151 167 189 669 171 186 239 596 Taxes Other Than Income 338 337 283 291 1,249 341 301 309 951 Total 3,852 3,895 3,876 3,993 15,616 3,810 3,731 4,011 11,552 Operating Income 2,271 2,130 2,089 1,592 8,082 1,859 1,747 1,836 5,442 Other Income, Net 62 66 76 70 274 65 55 59 179 Income Before Interest Expense and Income Taxes 2,333 2,196 2,165 1,662 8,356 1,924 1,802 1,895 5,621 Interest Expense, Net 33 36 31 38 138 47 51 71 169 Income Before Income Taxes 2,300 2,160 2,134 1,624 8,218 1,877 1,751 1,824 5,452 Income Tax Provision 511 470 461 373 1,815 414 406 353 1,173 Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 4,279 Dividends Declared per Common Share 0.9100 0.9100 0.9100 0.9750 3.7050 0.9750 1.9950 - 2.9700 Net Income Per Share Basic 3.11 2.97 2.97 2.25 11.31 2.66 2.48 2.72 7.85 Diluted 3.10 2.95 2.95 2.23 11.25 2.65 2.46 2.70 7.81 Average Number of Common Shares Basic 575 569 564 557 566 550 543 541 545 Diluted 577 572 568 561 569 553 546 544 548 Volumes and Prices (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Crude Oil and Condensate Volumes (MBbld) (A) United States 486.8 490.1 491.8 493.5 490.6 500.9 503.1 532.9 512.4 Trinidad 0.6 0.6 1.2 1.1 0.8 1.2 1.1 1.6 1.3 Total 487.4 490.7 493.0 494.6 491.4 502.1 504.2 534.5 513.7 Average Crude Oil and Condensate Prices ($/Bbl) (B) United States $ 78.46 $ 82.71 $ 76.95 $ 71.68 $ 77.42 $ 72.90 $ 64.84 $ 65.97 $ 67.83 Trinidad 67.50 70.75 63.15 60.47 64.43 61.12 54.50 57.74 57.80 Composite 78.45 82.69 76.92 71.66 77.40 72.87 64.82 65.95 67.81 Natural Gas Liquids Volumes (MBbld) (A) United States 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 270.0 Total 231.7 244.8 254.3 252.5 245.9 241.7 258.4 309.3 270.0 Average Natural Gas Liquids Prices ($/Bbl) (B) United States $ 24.32 $ 23.11 $ 22.42 $ 23.85 $ 23.40 $ 26.29 $ 22.70 $ 21.25 $ 23.20 Composite 24.32 23.11 22.42 23.85 23.40 26.29 22.70 21.25 23.20 Natural Gas Volumes (MMcfd) (A) United States 1,658 1,668 1,745 1,840 1,728 1,834 1,977 2,511 2,110 Trinidad 200 204 225 252 220 246 252 230 243 Other International (C) - - - - - - - 4 1 Total 1,858 1,872 1,970 2,092 1,948 2,080 2,229 2,745 2,354 Average Natural Gas Prices ($/Mcf) (B) United States $ 2.10 $ 1.57 $ 1.84 $ 2.39 $ 1.99 $ 3.36 $ 2.87 $ 2.71 $ 2.94 Trinidad 3.54 3.48 3.68 3.86 3.65 3.78 3.65 3.80 3.74 Other International (C) - - - - - - - 3.27 3.27 Composite 2.26 1.78 2.05 2.57 2.17 3.41 2.96 2.80 3.03 Crude Oil Equivalent Volumes (MBoed) (D) United States 994.7 1,013.0 1,037.1 1,052.7 1,024.5 1,048.3 1,090.9 1,260.7 1,134.1 Trinidad 34.1 34.5 38.6 43.0 37.6 42.1 43.2 39.8 41.7 Other International - - - - - - - 0.7 0.2 Total 1,028.8 1,047.5 1,075.7 1,095.7 1,062.1 1,090.4 1,134.1 1,301.2 1,176.0 Total MMBoe (D) 93.6 95.3 99.0 100.8 388.7 98.1 103.2 119.7 321.0 (A) Thousand barrels per day or million cubic feet per day, as applicable. (B) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 10 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025). (C) Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distribution costs. (D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. Balance Sheets In millions of USD (Unaudited) 2024 2025 MAR JUN SEP DEC MAR JUN SEP DEC Current Assets Cash and Cash Equivalents 5,292 5,431 6,122 7,092 6,599 5,216 3,530 Accounts Receivable, Net 2,688 2,657 2,545 2,650 2,621 2,504 2,680 Inventories 1,154 1,069 1,038 985 897 934 945 Assets from Price Risk Management Activities 110 4 - - - - 19 Other (A) 684 642 460 503 563 591 646 Total 9,928 9,803 10,165 11,230 10,680 9,245 7,820 Property, Plant and Equipment Oil and Gas Properties (Successful Efforts Method) 73,356 74,615 75,887 77,091 78,432 80,139 88,301 Other Property, Plant and Equipment 5,768 6,078 6,314 6,418 6,510 6,616 6,772 Total Property, Plant and Equipment 79,124 80,693 82,201 83,509 84,942 86,755 95,073 Less: Accumulated Depreciation, Depletion and Amortization (46,047) (47,049) (48,075) (49,297) (50,310) (51,394) (52,488) Total Property, Plant and Equipment, Net 33,077 33,644 34,126 34,212 34,632 35,361 42,585 Deferred Income Taxes 38 44 42 39 44 39 37 Other Assets 1,753 1,733 1,818 1,705 1,626 1,639 1,757 Total Assets 44,796 45,224 46,151 47,186 46,982 46,284 52,199 Current Liabilities Accounts Payable 2,389 2,436 2,290 2,464 2,353 2,266 2,944 Accrued Taxes Payable 786 600 855 1,007 668 348 392 Dividends Payable 523 516 513 539 534 1,081 550 Liabilities from Price Risk Management Activities - 8 32 116 276 85 17 Current Portion of Long-Term Debt 34 534 34 532 1,280 778 27 Current Portion of Operating Lease Liabilities 318 303 338 315 318 360 433 Other 223 231 344 381 290 257 452 Total 4,273 4,628 4,406 5,354 5,719 5,175 4,815 Long-Term Debt 3,757 3,250 3,742 4,220 3,464 3,458 7,667 Other Liabilities 2,533 2,456 2,480 2,395 2,368 2,398 2,496 Deferred Income Taxes 5,597 5,731 5,949 5,866 5,915 6,015 6,936 Commitments and Contingencies Stockholders' Equity Common Stock, $0.01 Par 206 206 206 206 206 206 206 Additional Paid in Capital 6,188 6,219 6,058 6,090 6,095 6,153 5,978 Accumulated Other Comprehensive Loss (8) (8) (9) (4) (4) (7) (5) Retained Earnings 23,897 25,071 26,231 26,941 27,869 28,131 29,603 Common Stock Held in Treasury (1,647) (2,329) (2,912) (3,882) (4,650) (5,245) (5,497) Total Stockholders' Equity 28,636 29,159 29,574 29,351 29,516 29,238 30,285 Total Liabilities and Stockholders' Equity 44,796 45,224 46,151 47,186 46,982 46,284 52,199 (A) Effective October 1, 2024, EOG combined Income Taxes Receivable into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets. Cash Flow Statements In millions of USD (Unaudited) 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Cash Flows from Operating Activities Reconciliation of Net Income to Net Cash Provided by Operating Activities: Net Income 1,789 1,690 1,673 1,251 6,403 1,463 1,345 1,471 4,279 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 1,074 984 1,031 1,019 4,108 1,013 1,053 1,169 3,235 Impairments 19 81 15 276 391 44 39 71 154 Stock-Based Compensation Expenses 45 45 58 51 199 50 53 53 156 Deferred Income Taxes 199 128 220 (80) 467 44 105 278 427 (Gains) Losses on Asset Dispositions, Net (26) (20) 7 23 (16) 1 - 18 19 Other, Net 9 3 2 3 17 11 11 2 24 Dry Hole Costs 1 5 - 8 14 34 11 - 45 Mark-to-Market Financial Commodity and Other Derivative Contracts (Gains) Losses, Net (237) 47 (79) 65 (204) 191 (107) (116) (32) Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 55 79 61 19 214 (38) (24) 27 (35) Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable 58 33 109 (99) 101 48 122 133 303 Inventories 117 75 30 37 259 76 (45) 4 35 Accounts Payable (58) 29 (159) 152 (36) (129) (107) 5 (231) Accrued Taxes Payable 319 (185) 256 151 541 (339) (321) 28 (632) Other Assets (161) 42 197 (34) 44 (43) (43) (28) (114) Other Liabilities (71) (20) 108 6 23 (96) (52) 155 7 Changes in Components of Working Capital Associated with Investing Activities (229) (127) 59 (85) (382) (41) (8) (159) (208) Net Cash Provided by Operating Activities 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 7,432 Investing Cash Flows Acquisition of Encino Acquisition Partners, LLC, Net of Cash Acquired - - - - - - - (4,464) (4,464) Additions to Oil and Gas Properties (1,485) (1,357) (1,263) (1,248) (5,353) (1,381) (1,699) (1,492) (4,572) Additions to Other Property, Plant and Equipment (350) (313) (239) (117) (1,019) (102) (94) (171) (367) Proceeds from Sales of Assets 9 10 - 4 23 12 4 5 21 Changes in Components of Working Capital Associated with Investing Activities 229 127 (59) 85 382 41 8 159 208 Net Cash Used in Investing Activities (1,597) (1,533) (1,561) (1,276) (5,967) (1,430) (1,781) (5,963) (9,174) Financing Cash Flows Long-Term Debt Borrowings - - - 985 985 - - 3,472 3,472 Long-Term Debt Repayments - - - - - - (500) (1,266) (1,766) Dividends Paid (525) (520) (533) (509) (2,087) (538) (528) (545) (1,611) Treasury Stock Purchased (759) (699) (795) (993) (3,246) (806) (602) (479) (1,887) Proceeds from Stock Options Exercised and Employee Stock Purchase Plan - 11 - 11 22 - 11 - 11 Debt Issuance and Other Financing Costs - - - (2) (2) - (7) (7) (14) Repayment of Finance Lease Liabilities (8) (9) (8) (8) (33) (8) (9) (8) (25) Net Cash Used in Financing Activities (1,292) (1,217) (1,336) (516) (4,361) (1,352) (1,635) 1,167 (1,820) Effect of Exchange Rate Changes on Cash - - - (1) (1) - 1 (1) - Increase (Decrease) in Cash and Cash Equivalents 14 139 691 970 1,814 (493) (1,383) (1,686) (3,562) Cash and Cash Equivalents at Beginning of Period 5,278 5,292 5,431 6,122 5,278 7,092 6,599 5,216 7,092 Cash and Cash Equivalents at End of Period 5,292 5,431 6,122 7,092 7,092 6,599 5,216 3,530 3,530 Non-GAAP Financial Measures To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Adjusted Cash Flow from Operations, Free Cash Flow, Net Debt and related statistics. A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com. As further discussed in the tables on the following pages, EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance. EOG believes that the non-GAAP measures presented, when viewed in combination with its financial results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial performance with the financial performance of other companies in the industry and (ii) analyzing EOG's financial performance across periods. The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP. In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time - for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. Direct ATROR The calculation of EOG's direct after-tax rate of return (ATROR) is based on EOG's net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG's direct net costs incurred in drilling or acquiring such well(s). As such, EOG's direct ATROR for a particular well(s) or play cannot be calculated from EOG's consolidated financial statements. Adjusted Net Income In millions of USD, except share data (in millions) and per share data (Unaudited) The following tables adjust reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the net unrealized mark-to-market (gains) losses from these and other derivativetransactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets(which are generally (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets)), to add back costs associatedwith the Encino acquisition and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. 3Q 2025 Before Tax Income Tax Impact After Tax Diluted Earnings per Share Reported Net Income (GAAP) 1,824 (353) 1,471 2.70 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (116) 25 (91) (0.16) Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 27 (5) 22 0.04 Add: Losses on Asset Dispositions, Net 18 (6) 12 0.02 Add: Acquisition-related costs (2) 68 (10) 58 0.11 Adjustments to Net Income (3) 4 1 0.01 Adjusted Net Income (Non-GAAP) 1,821 (349) 1,472 2.71 Average Number of Common Shares Basic 541 Diluted 544 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2025, such amount was $27 million. (2) Consists of Encino acquisition-related G&A costs ($68 million). Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 2Q 2025 Before Tax Income Tax Impact After Tax DilutedEarnings per Share Reported Net Income (GAAP) 1,751 (406) 1,345 2.46 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (107) 23 (84) (0.16) Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (24) 5 (19) (0.03) Add: Certain Impairments 11 - 11 0.02 Add: Acquisition-related costs (2) 18 (3) 15 0.03 Adjustments to Net Income (102) 25 (77) (0.14) Adjusted Net Income (Non-GAAP) 1,649 (381) 1,268 2.32 Average Number of Common Shares Basic 543 Diluted 546 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2025, such amount was $24 million. (2) Consists of Encino acquisition-related G&A costs ($12 million) and financing commitment costs ($6 million). Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 1Q 2025 Before Tax Income TaxImpact After Tax Diluted Earnings per Share Reported Net Income (GAAP) 1,877 (414) 1,463 2.65 Adjustments: Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 191 (41) 150 0.26 Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (38) 8 (30) (0.05) Add: Losses on Asset Dispositions, Net 1 2 3 0.01 Adjustments to Net Income 154 (31) 123 0.22 Adjusted Net Income (Non-GAAP) 2,031 (445) 1,586 2.87 Average Number of Common Shares Basic 550 Diluted 553 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2025, such amount was $38 million. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 4Q 2024 Before Tax Income TaxImpact After Tax Diluted Earningsper Share Reported Net Income (GAAP) 1,624 (373) 1,251 2.23 Adjustments: Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 65 (14) 51 0.10 Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 19 (4) 15 0.03 Add: Losses on Asset Dispositions, Net 23 (4) 19 0.03 Add: Certain Impairments 254 (55) 199 0.35 Adjustments to Net Income 361 (77) 284 0.51 Adjusted Net Income (Non-GAAP) 1,985 (450) 1,535 2.74 Average Number of Common Shares Basic 557 Diluted 561 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2024, such amount was $19 million. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) 3Q 2024 Before Tax Income Tax Impact After Tax DilutedEarningsper Share Reported Net Income (GAAP) 2,134 (461) 1,673 2.95 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (79) 17 (62) (0.11) Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 61 (13) 48 0.08 Add: Losses on Asset Dispositions, Net 7 (2) 5 0.01 Less: Severance Tax Refund (31) 7 (24) (0.04) Add: Severance Tax Consulting Fees 10 (2) 8 0.01 Less: Interest on Severance Tax Refund (5) 1 (4) (0.01) Adjustments to Net Income (37) 8 (29) (0.06) Adjusted Net Income (Non-GAAP) 2,097 (453) 1,644 2.89 Average Number of Common Shares Basic 564 Diluted 568 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2024, such amount was $61 million. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2024 Before Tax Income TaxImpact After Tax DilutedEarnings per Share Reported Net Income (GAAP) 8,218 (1,815) 6,403 11.25 Adjustments: Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net (204) 44 (160) (0.28) Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 214 (46) 168 0.30 Less: Gains on Asset Dispositions, Net (16) 3 (13) (0.02) Add: Certain Impairments 291 (57) 234 0.41 Less: Severance Tax Refund (31) 7 (24) (0.04) Add: Severance Tax Consulting Fees 10 (2) 8 0.01 Less: Interest on Severance Tax Refund (5) 1 (4) (0.01) Adjustments to Net Income 259 (50) 209 0.37 Adjusted Net Income (Non-GAAP) 8,477 (1,865) 6,612 11.62 Average Number of Common Shares Basic 566 Diluted 569 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was $214 million. Adjusted Net Income (Continued) In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2023 Before Tax Income Tax Impact After Tax DilutedEarnings perShare Reported Net Income (GAAP) 9,689 (2,095) 7,594 13.00 Adjustments: Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net (818) 176 (642) (1.09) Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (112) 24 (88) (0.15) Less: Gains on Asset Dispositions, Net (95) 20 (75) (0.13) Add: Certain Impairments 42 (6) 36 0.06 Adjustments to Net Income (983) 214 (769) (1.31) Adjusted Net Income (Non-GAAP) 8,706 (1,881) 6,825 11.69 Average Number of Common Shares Basic 581 Diluted 584 (1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2023, such amount was $112 million. Net Income per Share In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) 2Q 2025 Net Income per Share (GAAP) - Diluted 2.46 Realized Prices 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 38.05 Less: 2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (39.80) Subtotal (1.75) Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Total Change in Revenue (209) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 46 Change in Net Income (163) Change in Diluted Earnings per Share (0.30) Volumes 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Less: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe) (103.2) Subtotal 16.5 Multiplied by: 3Q 2025 Composite Average Margin per Boe (GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below) 13.42 Change in Margin 221 Less: Income Tax Benefit (Provision) Imputed (based on 22%) (49) Change in Net Income 172 Change in Diluted Earnings per Share 0.32 Certain Operating Costs per Boe 2Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.25 Less: 3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.27) Subtotal (0.02) Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Change in Before-Tax Net Income (2) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 1 Change in Net Income (1) Change in Diluted Earnings per Share 0.00 Net Income Per Share (Continued) In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net 3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 116 Less: Income Tax Benefit (Provision) (25) After Tax - (a) 91 Less: 2Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 107 Less: Income Tax Benefit (Provision) (23) After Tax - (b) 84 Change in Net Income - (a) - (b) 7 Change in Diluted Earnings per Share 0.01 Other (1) 0.21 3Q 2025 Net Income per Share (GAAP) - Diluted 2.70 3Q 2025 Average Number of Common Shares - Diluted 544 (1) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares. Adjusted Net Income Per Share In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) 2Q 2025 Adjusted Net Income per Share (Non-GAAP) - Diluted 2.32 Realized Prices 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe 38.05 Less: 2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe (39.80) Subtotal (1.75) Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Total Change in Revenue (209) Add: Income Tax Benefit (Provision) Imputed (based on 22%) 46 Change in Net Income (163) Change in Diluted Earnings per Share (0.30) Volumes 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Less: 2Q 2025 Crude Oil Equivalent Volumes (MMBoe) (103.2) Subtotal 16.5 Multiplied by: 3Q 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below) 13.99 Change in Margin 231 Less: Income Tax Benefit (Provision) Imputed (based on 22%) (51) Change in Net Income 180 Change in Diluted Earnings per Share 0.33 Certain Operating Costs per Boe 2Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.14 Less: 3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (19.70) Subtotal 0.44 Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe) 119.7 Change in Before-Tax Net Income 53 Add: Income Tax Benefit (Provision) Imputed (based on 22%) (12) Change in Net Income 41 Change in Diluted Earnings per Share 0.08 Adjusted Net Income Per Share (Continued) In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 3Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts 27 Less: Income Tax Benefit (Provision) (5) After Tax - (a) 22 Less: 2Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts (24) Less: Income Tax Benefit (Provision) 5 After Tax - (b) (19) Change in Net Income - (a) - (b) 41 Change in Diluted Earnings per Share 0.08 Other (1) 0.20 3Q 2025 Adjusted Net Income per Share (Non-GAAP) 2.71 3Q 2025 Average Number of Common Shares - Diluted 544 (1) Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares. Cash Flow from Operations and Free Cash Flow In millions of USD (Unaudited) The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Adjusted Cash Flow from Operations (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with InvestingActivities (or Investing and Financing Activities, as applicable) and certain other adjustments to exclude certain non-recurring items and other items asfurther described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Adjusted Cash Flow from Operations (Non-GAAP) (see belowreconciliation) for such period less the Total Capital Expenditures (Non-GAAP) (see below reconciliation) during such period, as is illustrated below. EOGmanagement uses this information for comparative purposes within the industry. As indicated in the tables below, EOG is (1) in addition to its customaryworking capital-related adjustments, adjusting Net Cash Provided by Operating Activities (GAAP) to add back certain non-recurring acquisition-related costs incurred during the second and third quarters of 2025 and (2) now presenting such adjusted measure as "Adjusted Cash Flow from Operations (Non-GAAP)" (instead of "Cash Flow from Operations Before Changes in Working Capital (Non-GAAP)" as reported in prior periods); the presentation below with respect to the second and third quarters of 2025 and the prior periods shown has been conformed. 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Net Cash Provided by Operating Activities (GAAP) 2,903 2,889 3,588 2,763 12,143 2,289 2,032 3,111 7,432 Adjustments: Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable (58) (33) (109) 99 (101) (48) (122) (133) (303) Inventories (117) (75) (30) (37) (259) (76) 45 (4) (35) Accounts Payable 58 (29) 159 (152) 36 129 107 (5) 231 Accrued Taxes Payable (319) 185 (256) (151) (541) 339 321 (28) 632 Other Assets 161 (42) (197) 34 (44) 43 43 28 114 Other Liabilities 71 20 (108) (6) (23) 96 52 (155) (7) Changes in Components of Working Capital Associated with Investing Activities 229 127 (59) 85 382 41 8 159 208 Add: Acquisition-Related Costs (1), Net of Tax - - - - - - 10 58 68 Adjusted Cash Flow from Operations (Non- GAAP) 2,928 3,042 2,988 2,635 11,593 2,813 2,496 3,031 8,340 Less: Total Capital Expenditures (Non-GAAP) (2) (1,703) (1,668) (1,497) (1,358) (6,226) (1,484) (1,523) (1,648) (4,655) Free Cash Flow (Non-GAAP) 1,225 1,374 1,491 1,277 5,367 1,329 973 1,383 3,685 (1) Consists of Encino acquisition-related G&A costs of $12 million and $68 million (each before tax) for the three months ended June 30, 2025 and three months ended September 30, 2025, respectively. (2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): 2024 2025 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Total Expenditures (GAAP) 1,952 1,682 1,573 1,446 6,653 1,546 1,883 8,544 11,973 Less: Asset Retirement Costs (21) 60 (11) (26) 2 (13) (14) (86) (113) Non-Cash Leasehold Acquisition Costs (3) (31) (34) (17) (3) (85) (9) (2) (3) (14) Acquisition Costs of Properties (3) (21) (5) - (7) (33) 1 (270) (6,736) (7,005) Acquisition Costs of Other Property, Plant and Equipment (131) (1) (5) - (137) - - - - Exploration Costs (45) (34) (43) (52) (174) (41) (74) (71) (186) Total Capital Expenditures (Non-GAAP) 1,703 1,668 1,497 1,358 6,226 1,484 1,523 1,648 4,655 Cash Flow from Operations and Free Cash Flow (Continued) In millions of USD (Unaudited) FY 2023 FY 2022 Net Cash Provided by Operating Activities (GAAP) 11,340 11,093 Adjustments: Changes in Components of Working Capital and Other Assets and Liabilities Accounts Receivable 38 347 Inventories 231 534 Accounts Payable 119 (90) Accrued Taxes Payable (61) 113 Other Assets (39) 364 Other Liabilities (184) 266 Changes in Components of Working Capital Associated with Investing Activities (295) (375) Adjusted Cash Flow from Operations (Non-GAAP) 11,149 12,252 Less: Total Capital Expenditures (Non-GAAP) (a) (6,041) (4,607) Free Cash Flow (Non-GAAP) 5,108 7,645 (a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): Total Expenditures (GAAP) 6,818 5,610 Less: Asset Retirement Costs (257) (298) Non-Cash Development Drilling (90) - Non-Cash Leasehold Acquisition Costs (3) (99) (127) Acquisition Costs of Properties (3) (16) (419) Acquisition Costs of Other Property, Plant and Equipment (134) - Exploration Costs (181) (159) Total Capital Expenditures (Non-GAAP) 6,041 4,607 (3) Line item descriptions revised (from descriptions shown in EOG's previously published tables) to more accurately describe the costs reflected therein; previously reported cost amounts not impacted by such changes in presentation. Net Debt-to-Total Capitalization Ratio In millions of USD, except ratio data (Unaudited) The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated withinternational subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors whofollow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. September 30, 2025 June 30, 2025 March 31, 2025 December 31,2024 September 30, 2024 Total Stockholders' Equity - (a) 30,285 29,238 29,516 29,351 29,574 Current and Long-Term Debt (GAAP) - (b) 7,694 4,236 4,744 4,752 3,776 Less: Cash (3,530) (5,216) (6,599) (7,092) (6,122) Net Debt (Non-GAAP) - (c) 4,164 (980) (1,855) (2,340) (2,346) Total Capitalization (GAAP) - (a) + (b) 37,979 33,474 34,260 34,103 33,350 Total Capitalization (Non-GAAP) - (a) + (c) 34,449 28,258 27,661 27,011 27,228 Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 20.3 % 12.7 % 13.8 % 13.9 % 11.3 % Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] 12.1 % -3.5 % -6.7 % -8.7 % -8.6 % Revenues, Costs and Margins Per Barrel of Oil Equivalent In millions of USD, except Boe and per Boe amounts (Unaudited) EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groupsof components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with thefinancial performance of other companies in the industry. 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Volume - Million Barrels of Oil Equivalent - (a) 119.7 103.2 98.1 100.8 99.0 Total Operating Revenues and Other - (b) 5,847 5,478 5,669 5,585 5,965 Total Operating Expenses - (c) 4,011 3,731 3,810 3,993 3,876 Operating Income - (d) 1,836 1,747 1,859 1,592 2,089 Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas Crude Oil and Condensate 3,243 2,974 3,293 3,261 3,488 Natural Gas Liquids 604 534 572 554 524 Natural Gas 707 600 637 494 372 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e) 4,554 4,108 4,502 4,309 4,384 Operating Costs Lease and Well 431 396 401 394 392 Gathering, Processing and Transportation Costs (1) 587 455 440 441 445 General and Administrative (GAAP) 239 186 171 189 167 Less: Certain Items (see Endnotes 2 & 3 to 3Q 2025 earnings release) (68) (12) - - (10) General and Administrative (Non-GAAP) (2) 171 174 171 189 157 Taxes Other Than Income (GAAP) 309 301 341 291 283 Add: Severance Tax Refund - - - - 31 Taxes Other Than Income (Non-GAAP) (3) 309 301 341 291 314 Interest Expense, Net 71 51 47 38 31 Less: Acquisition-Related Financing Commitment Costs - (6) - - - Interest Expense, Net (Non-GAAP) (4) 71 45 47 38 31 Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f) 1,637 1,389 1,400 1,353 1,318 Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g) 1,569 1,371 1,400 1,353 1,339 Depreciation, Depletion and Amortization (DD&A) 1,169 1,053 1,013 1,019 1,031 Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 2,806 2,442 2,413 2,372 2,349 Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 2,738 2,424 2,413 2,372 2,370 Exploration Costs 71 74 41 52 43 Dry Hole Costs - 11 34 8 - Impairments 71 39 44 276 15 Total Exploration Costs (GAAP) 142 124 119 336 58 Less: Certain Impairments (5) - (11) - (254) - Total Exploration Costs (Non-GAAP) 142 113 119 82 58 Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 2,948 2,566 2,532 2,708 2,407 Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k) 2,880 2,537 2,532 2,454 2,428 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) 1,606 1,542 1,970 1,601 1,977 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) 1,674 1,571 1,970 1,855 1,956 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 3Q 2025 2Q 2025 1Q 2025 4Q 2024 3Q 2024 Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) Composite Average Operating Revenues and Other per Boe - (b) / (a) 48.85 53.08 57.79 55.41 60.25 Composite Average Operating Expenses per Boe - (c) / (a) 33.51 36.15 38.84 39.62 39.15 Composite Average Operating Income per Boe - (d) / (a) 15.34 16.93 18.95 15.79 21.10 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a) 38.05 39.80 45.88 42.74 44.31 Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a) 13.67 13.46 14.26 13.42 13.32 Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)] 24.38 26.34 31.62 29.32 30.99 Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 23.44 23.66 24.58 23.53 23.74 Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)] 14.61 16.14 21.30 19.21 20.57 Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 24.63 24.86 25.79 26.86 24.33 Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)] 13.42 14.94 20.09 15.88 19.98 Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a) 13.10 13.30 14.26 13.42 13.53 Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)] 24.95 26.50 31.62 29.32 30.78 Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 22.87 23.50 24.58 23.53 23.95 Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)] 15.18 16.30 21.30 19.21 20.36 Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 24.06 24.59 25.79 24.34 24.54 Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)] 13.99 15.21 20.09 18.40 19.77 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022 Volume - Million Barrels of Oil Equivalent - (a) 388.7 359.4 331.5 Total Operating Revenues and Other - (b) 23,698 24,186 25,702 Total Operating Expenses - (c) 15,616 14,583 15,736 Operating Income (Loss) - (d) 8,082 9,603 9,966 Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas Crude Oil and Condensate 13,921 13,748 16,367 Natural Gas Liquids 2,106 1,884 2,648 Natural Gas 1,551 1,744 3,781 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e) 17,578 17,376 22,796 Operating Costs Lease and Well 1,572 1,454 1,331 Gathering, Processing and Transportation Costs (1) 1,722 1,620 1,587 General and Administrative (GAAP) 669 640 570 Less: Severance Tax Consulting Fees (10) - (16) General and Administrative (Non-GAAP) (2) 659 640 554 Taxes Other Than Income (GAAP) 1,249 1,284 1,585 Add: Severance Tax Refund 31 - 115 Taxes Other Than Income (Non-GAAP) (3) 1,280 1,284 1,700 Interest Expense, Net 138 148 179 Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f) 5,350 5,146 5,252 Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g) 5,371 5,146 5,351 Depreciation, Depletion and Amortization (DD&A) 4,108 3,492 3,542 Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h) 9,458 8,638 8,794 Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i) 9,479 8,638 8,893 Exploration Costs 174 181 159 Dry Hole Costs 14 1 45 Impairments 391 202 382 Total Exploration Costs (GAAP) 579 384 586 Less: Certain Impairments (5) (291) (42) (113) Total Exploration Costs (Non-GAAP) 288 342 473 Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j) 10,037 9,022 9,380 Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k) 9,767 8,980 9,366 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) 7,541 8,354 13,416 Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) 7,811 8,396 13,430 Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022 Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) Composite Average Operating Revenues and Other per Boe - (b) / (a) 60.97 67.30 77.53 Composite Average Operating Expenses per Boe - (c) / (a) 40.18 40.58 47.47 Composite Average Operating Income (Loss) per Boe - (d) / (a) 20.79 26.72 30.06 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a) 45.22 48.34 68.77 Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a) 13.76 14.31 15.84 Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)] 31.46 34.03 52.93 Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a) 24.33 24.03 26.53 Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)] 20.89 24.31 42.24 Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a) 25.82 25.10 28.30 Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)] 19.40 23.24 40.47 Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a) 13.82 14.31 16.14 Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)] 31.40 34.03 52.63 Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a) 24.39 24.03 26.83 Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)] 20.83 24.31 41.94 Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a) 25.13 24.98 28.26 Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)] 20.09 23.36 40.51 (1) Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. (2) EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring. (3) EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring. (4) EOG believes excluding the above-referenced items from Interest Expense, Net is appropriate and provides useful information to investors, as EOG views such items as non-recurring. (5) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Additional Key Financial Information (Unaudited) See "Endnotes" below for related discussion and definitions. 2024 Actual 2023 Actual 2022 Actual Crude Oil and Condensate Volumes (MBod) United States 490.6 475.2 460.7 Trinidad 0.8 0.6 0.6 Total 491.4 475.8 461.3 Natural Gas Liquids Volumes (MBbld) Total 245.9 223.8 197.7 Natural Gas Volumes (MMcfd) United States 1,728 1,551 1,315 Trinidad 220 160 180 Total 1,948 1,711 1,495 Crude Oil Equivalent Volumes (MBoed) United States 1,024.5 957.5 877.5 Trinidad 37.6 27.3 30.7 Total 1,062.1 984.8 908.2 Benchmark Price Oil (WTI) ($/Bbl) 75.72 77.61 94.23 Natural Gas (HH) ($/Mcf) 2.27 2.74 6.64 Crude Oil and Condensate - above (below) WTI1 ($/Bbl) United States 1.70 1.57 2.99 Trinidad (11.29) (9.03) (8.07) Natural Gas Liquids - Realizations as % of WTI Total 30.9 % 29.7 % 39.0 % Natural Gas - above (below) NYMEX Henry Hub2 ($/Mcf) United States (0.28) (0.04) 0.63 Natural Gas Realizations3 ($/Mcf) Trinidad 3.65 3.65 4.43 Total Expenditures (GAAP) ($MM) 6,653 6,818 5,610 Capital Expenditures4 (non-GAAP) ($MM) 6,226 6,041 4,607 Operating Unit Costs ($/Boe) Lease and Well 4.04 4.05 4.02 Gathering, Processing and Transportation Costs5 4.43 4.50 4.78 General and Administrative (GAAP) 1.72 1.78 1.72 General and Administrative (non-GAAP)6 1.70 1.78 1.67 Cash Operating Costs (GAAP) 10.19 10.33 10.52 Cash Operating Costs (non-GAAP)6 10.17 10.33 10.47 Depreciation, Depletion and Amortization 10.57 9.72 10.69 Expenses ($MM) Exploration and Dry Hole 188 182 204 Impairment (GAAP) 391 202 382 Impairment (excluding certain impairments (non-GAAP))7 100 160 269 Capitalized Interest 45 33 36 Net Interest 138 148 179 TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (GAAP) 7.1 % 7.4 % 7.0 % (non-GAAP)6 7.3 % 7.4 % 7.5 % Income Taxes Effective Rate 22.1 % 21.6 % 21.7 % Current Tax Expense ($MM) 1,348 1,415 2,208 Additional Key Information (Continued) Endnotes 1) EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. 2) EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. 3) The full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited. 4) Capital Expenditures includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. Capital Expenditures excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses. 5) Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. 6) Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non-GAAP) and G&A (non-GAAP) for fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for fiscal year 2024 and fiscal year 2022 was $(0.02) and $(0.05), respectively. 7) In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-third-quarter-2025-results-302607496.html SOURCE EOG Resources, Inc.
Baker Hughes Secures Additional Order for Rio Grande LNG Expansion
Baker Hughes Secures Additional Order for Rio Grande LNG Expansion Award from Bechtel includes supply of the primary liquefaction equipment for NextDecade's Rio Grande LNG Train 5Order includes Frame 7 gas turbines and centrifugal compressors, replicating proven solutions from previous trainsTechnology will enable an additional LNG production capacity of approximately 6 MTPA HOUSTON and LONDON, Nov. 06, 2025 (GLOBE NEWSWIRE) -- Baker Hughes (NASDAQ: BKR), an energy technology company, announced Thursday an award from engineering company Bechtel Energy Inc. (Bechtel) to supply primary liquefaction equipment for Train 5 of NextDecade's Rio Grande LNG Facility in the Port of Brownsville, Texas. The award follows a recent order for Train 4 and is part of a previously established framework agreement covering a variety of Baker Hughes equipment and associated contractual services for Trains 4 through 8. "Our continued collaboration with Baker Hughes on the Rio Grande LNG project highlights their consistent delivery of industry-leading technology and expertise," said Bhupesh Thakkar, Bechtel's general manager for its LNG business. "We value Baker Hughes' ongoing support as we progress this significant expansion, which will be vital for meeting growing global energy demand." "Securing this order for the fifth train of the Rio Grande LNG project underscores the confidence in our proven technology and the dedication of our teams," said Baker Hughes Chairman and CEO Lorenzo Simonelli. "We are pleased to extend our collaboration with Bechtel and NextDecade, providing efficient and reliable technology solutions for LNG infrastructure that is critical to sustainable energy development." Mirroring the proven technology solution deployed in previous trains, the Train 5 order includes two Frame 7 gas turbines, known for their proven reliability and energy efficiency, and six centrifugal compressors. These advanced solutions, designed to deliver efficiency and lower emissions, will support an additional LNG capacity of approximately 6 MTPA at the facility. In addition, Baker Hughes is also providing an additional digital solution for Rio Grande's Trains 1 to 3 through the deployment of Cordant Asset Health. Next Decade will utilize Cordant to support its equipment monitoring and failure diagnostics for critical rotating equipment, as well as its cloud-based visualization solution for offline vibration data. Aboutâ¯Baker Hughes Baker Hughesâ¯(NASDAQ: BKR) is an energy technology company that provides solutions to energy and industrial customers worldwide. Built on a century of experience and conducting business in over 120 countries, our innovative technologies and services are taking energy forward making it safer, cleaner and more efficient for people and the planet. Visit us atâ¯bakerhughes.com. For more information, please contact: Media Relations Chiara Toniato +39 3463823419 chiara.toniato@bakerhughes.com Investor Relations Chase Mulvehill +1 346-297-2561 investor.relations@bakerhughes.com
Brookfield Business Partners Reports Third Quarter 2025 Results
Brookfield Business Partners Reports Third Quarter 2025 Results BROOKFIELD, NEWS, Nov. 06, 2025 (GLOBE NEWSWIRE) -- Brookfield Business Partners (NYSE: BBU, BBUC; TSX:BBUN,BBUC.CA) announced today financial results for the quarter ended September 30, 2025. "We made excellent progress in our business over the past few months, completing the acquisition of a Canadian residential and multi-family mortgage lender, generating $180 million from our capital recycling initiatives and announcing the simplification of our corporate structure," said Anuj Ranjan, CEO of Brookfield Business Partners. "Our plan to convert into a single listed corporation has been well received by our investors and continuing to execute on our strategy should support continued growth in the intrinsic value of our business." Net loss attributable to Unitholders for the three months ended September 30, 2025 was $59 million (loss of $0.28 per limited partnership unit), compared to net income of $301 million (income of $1.39 per limited partnership unit) in the prior period. Prior year net income attributable to Unitholders included $296 million of tax recoveries at our advanced energy storage operation compared to $77 million in the current period and included $131 million of net gains on dispositions compared to $16 million in the current period. Operational Update The following table presents Adjusted EBITDA by segment: Adjusted EBITDA for the three months ended September 30, 2025 was $575 million, compared to $844 million in the prior period. Current period Adjusted EBITDA included $77 million of tax recoveries and reflects the impact of lower ownership in three businesses from the partial sale of interests to a new Brookfield managed evergreen private equity fund. Prior period results included $296 million of tax recoveries and $47 million of contribution from disposed operations. Industrials segment Adjusted EBITDA was $316 million for the three months ended September 30, 2025, an increase of 17% compared to the prior period excluding the impact of tax recoveries. Results include contribution from recent acquisitions including our electric heat tracing systems manufacturer acquired in January 2025. Strong performance at our advanced energy storage operation was driven by higher volumes, continued positive mix shift toward higher margin advanced batteries combined with ongoing operational and commercial improvements. Adjusted EBITDA at our engineered components manufacturer increased on a same store basis compared to the prior period, driven by recent commercial actions and increased volumes from customer wins. Business Services segment Adjusted EBITDA was $188 million for the three months ended September 30, 2025 and included the impact from the sale of a partial interest in our dealer software and technology services operation in July 2025. Performance at our residential mortgage insurer continues to benefit from resilient demand across the business' served market segment, including first-time homebuyers. While continued renewal activity at our dealer software and technology services operation supported stable bookings during the quarter, results include the impact of ongoing costs related to technology upgrades. Our Infrastructure Services segment Adjusted EBITDA was $104 million for the three months ended September 30, 2025. Results reflect the impact of the disposition of our offshore oil services' shuttle tanker operation in January 2025 and the sale of a partial interest in our work access services operation in July 2025. Stable performance at our modular building leasing services operation benefited from increased sales of value added products and services despite weak end market conditions. Improved margins and productivity gains at our lottery services operation contributed to results during the quarter, offset by the impact of lower terminal deliveries compared to the prior period. The following table presents Adjusted EFO4 by segment: Adjusted EFO included the benefit of lower current taxes at our advanced energy storage operation and lower interest expense as a result of a reduction in our corporate borrowings compared to the prior period. Adjusted EFO in the current period included $16 million of after-tax net gains primarily related to the disposition of our Indian non-bank financial services' non-core home financing operation. Adjusted EFO in the prior period included $131 million of net gains primarily related to the disposition of our road fuels operation and the deconsolidation of our payment processing services operation. Strategic Initiatives Capital RecyclingIn September, our offshore oil services operation entered into an agreement to sell its Floating Production, Storage, and Offloading (FPSO) operation. Expected proceeds from the sale, combined with proceeds from prior asset sales and distributions, should provide BBU with a path to recover the majority of its invested capital in the business. The sale is expected to close in the first half of 2026, subject to closing conditions.Capital DeploymentIn October, we completed the previously announced privatization of First National Financial Corporation, a leading Canadian residential and multi-family mortgage lender for $2.6 billion. BBU invested $146 million for its 11% interest.Corporate ReorganizationIn connection with our previously announced plans to simplify our corporate structure, we have entered into an arrangement agreement (the "Arrangement") by which all BBU limited partnership units, BBUC class A exchangeable shares and redemption-exchange units will be exchanged for newly issued class A shares of a publicly traded Canadian corporation (the "Corporation") on a one-for-one basis.The Arrangement will be implemented pursuant to a court-approved plan of arrangement and completion of the Arrangement is subject to a number of conditions, including BBU and BBUC security holder approvals, approval by the British Columbia Supreme Court and customary regulatory approvals for a transaction of this nature. A special meeting of BBU unitholders and a special meeting of BBUC shareholders have been called for January 13, 2026 and security holders of record as of the close of business on November 25, 2025 will be entitled to vote at the meetings.Special Committees of directors of the general partner of BBU and of BBUC (collectively, the "Boards") have unanimously determined that the Arrangement is in the best interests of BBU and BBUC, respectively, and have recommended that the Boards approve the Arrangement and recommend that BBU unitholders and BBUC shareholders vote in favor of the Arrangement. The Boards, on the recommendation of the Special Committees, have determined that the Arrangement is in the best interests of BBU and BBUC, respectively, and have unanimously resolved to approve the Arrangement and recommend that BBU unitholders and BBUC shareholders vote in favor of the Arrangement. In making their determinations, the Special Committees and the Boards considered, among other factors, the fairness opinion of the Special Committees' financial advisor, Origin Merchant Partners to the effect that, as of November 4, 2025 and subject to the assumptions, limitations and qualifications described therein, the consideration to be received by public holders of BBU units and BBUC exchangeable shares is fair, from a financial point of view, to such holders.Further information regarding the Arrangement will be contained in a joint management information circular of BBU and BBUC. Subject to the satisfaction or waiver of all closing conditions, it is anticipated that the Arrangement will be completed in the first quarter of 2026.Copies of the joint management information circular, the arrangement agreement, the plan of arrangement and certain related documents will be filed with the applicable Canadian securities regulators and with the United States Securities and Exchange Commission and will be available on SEDAR+ at https://sedarplus.ca and on EDGAR at https://sec.gov. Liquidity We ended the quarter with approximately $2.3 billion of liquidity at the corporate level, including $2.2 billion of availability on our credit facilities. Pro forma for announced and recently closed transactions, corporate liquidity is approximately $2.9 billion. Distribution The Board of Directors has declared a quarterly distribution in the amount of $0.0625 per unit, payable on December 31, 2025 to unitholders of record as at the close of business on November 28, 2025. Additional Information The Board has reviewed and approved this news release, including the summarized unaudited interim condensed consolidated financial statements contained herein. Brookfield Business Partners' Letter to Unitholders and the Supplemental Information are available on our website https://bbu.brookfield.com under Reports & Filings. Notes: Attributable to limited partnership unitholders, general partnership unitholders, redemption-exchange unitholders, special limited partnership unitholders and BBUC exchangeable shareholders.Net income (loss) per limited partnership unit calculated as net income (loss) attributable to limited partners divided by the average number of limited partnership units outstanding for the three and nine months ended September 30, 2025 which were 88.8 million and 85.9 million, respectively (September 30, 2024: 74.3 million and 74.3 million, respectively).Adjusted EBITDA is a non-IFRS measure of operating performance presented as net income and equity accounted income at the partnership's economic ownership interest in consolidated subsidiaries and equity accounted investments, respectively, excluding the impact of interest income (expense), net, income taxes, depreciation and amortization expense, gains (losses) on dispositions, net, transaction costs, restructuring charges, revaluation gains or losses, impairment expenses or reversals, other income or expenses, and preferred equity distributions. The partnership's economic ownership interest in consolidated subsidiaries and equity accounted investments excludes amounts attributable to non-controlling interests consistent with how the partnership determines net income attributable to non-controlling interests in its unaudited interim condensed consolidated statements of operating results. The partnership believes that Adjusted EBITDA provides a comprehensive understanding of the ability of its businesses to generate recurring earnings which allows users to better understand and evaluate the underlying financial performance of the partnership's operations and excludes items that the partnership believes do not directly relate to revenue earning activities and are not normal, recurring items necessary for business operations. Please refer to the reconciliation of net income (loss) to Adjusted EBITDA included in this news release.Adjusted EFO is the partnership's segment measure of profit or loss and is presented as net income and equity accounted income at the partnership's economic ownership interest in consolidated subsidiaries and equity accounted investments, respectively, excluding the impact of depreciation and amortization expense, deferred income taxes, transaction costs, restructuring charges, unrealized revaluation gains or losses, impairment expenses or reversals and other income or expense items that are not directly related to revenue generating activities. The partnership's economic ownership interest in consolidated subsidiaries excludes amounts attributable to non-controlling interests consistent with how the partnership determines net income attributable to non-controlling interests in its unaudited interim condensed consolidated statements of operating results. In order to provide additional insight regarding the partnership's operating performance over the lifecycle of an investment, Adjusted EFO includes the impact of preferred equity distributions and realized disposition gains or losses recorded in net income, other comprehensive income, or directly in equity, such as ownership changes. Adjusted EFO does not include legal and other provisions that may occur from time to time in the partnership's operations and that are one-time or non-recurring and not directly tied to the partnership's operations, such as those for litigation or contingencies. Adjusted EFO includes expected credit losses and bad debt allowances recorded in the normal course of the partnership's operations. Adjusted EFO allows the partnership to evaluate its segments on the basis of return on invested capital generated by its operations and allows the partnership to evaluate the performance of its segments on a levered basis. Brookfield Business Partners is a global business services and industrials company focused on owning and operating high-quality businesses that provide essential products and services and benefit from a strong competitive position. Investors have flexibility to invest in our company either through Brookfield Business Partners L.P. (NYSE: BBU; TSX:BBUN.CA), a limited partnership or Brookfield Business Corporation (NYSE, TSX:BBUC.CA), a corporation. For more information, please visit https://bbu.brookfield.com. Brookfield Business Partners is the flagship listed vehicle of Brookfield Asset Management's Private Equity Group. Brookfield Asset Management is a leading global alternative asset manager with over $1 trillion of assets under management. Please note that Brookfield Business Partners' previous audited annual and unaudited quarterly reports have been filed on SEDAR+ and EDGAR, and are available at https://bbu.brookfield.com under Reports & Filings. Hard copies of the annual and quarterly reports can be obtained free of charge upon request. For more information, please contact: Conference Call and Quarterly Earnings Webcast Details Investors, analysts and other interested parties can access Brookfield Business Partners' third quarter 2025 results as well as the Letter to Unitholders and Supplemental Information on our website https://bbu.brookfield.com under Reports & Filings. The results call can be accessed via webcast on November 6, 2025 at 9:00 a.m. Eastern Time at BBU2025Q3Webcast or participants can preregister at BBU2025Q3ConferenceCall. Upon registering, participants will be emailed a dial-in number and unique PIN. A replay of the webcast will be available at https://bbu.brookfield.com. Notes: Other income (expense), net corresponds to amounts that are not directly related to revenue earning activities and are not normal, recurring income or expenses necessary for business operations. The components of other income (expense), net include $187 million of expenses for employee incentive payments linked to the realization of value at our operations, $115 million of net losses on debt modification and extinguishment, $56 million of net revaluation losses, $43 million of business separation expenses, stand-up costs and restructuring charges, $14 million of loss recognized on the partial sale of an interest in our work access services operation and $47 million of other expenses.Equity accounted Adjusted EBITDA corresponds to the Adjusted EBITDA attributable to the partnership that is generated by its investments in associates and joint ventures accounted for using the equity method.Amounts attributable to non-controlling interests are calculated based on the economic ownership interests held by the non-controlling interests in consolidated subsidiaries. Notes: Other income (expense), net corresponds to amounts that are not directly related to revenue earning activities and are not normal, recurring income or expenses necessary for business operations. The components of other income (expense), net include $383 million of expenses for employee incentive payments linked to the realization of value at our operations, $236 million of net gain recognized upon the deconsolidation of our healthcare services operation, $179 million of business separation expenses, stand-up costs and restructuring charges, $165 million of net revaluation losses, $137 million of net losses on debt modification and extinguishment, $125 million of unrealized gains recorded on reclassification of property, plant and equipment to finance leases at our offshore oil services operation, $40 million of transaction costs, $14 million of loss recognized on the partial sale of an interest in our work access services operation and $91 million of other expenses.Equity accounted Adjusted EBITDA corresponds to the Adjusted EBITDA attributable to the partnership that is generated by our investments in associates and joint ventures accounted for using the equity method.Amounts attributable to non-controlling interests are calculated based on the economic ownership interests held by the non-controlling interests in consolidated subsidiaries. Notes: Other income (expense), net corresponds to amounts that are not directly related to revenue earning activities and are not normal, recurring income or expenses necessary for business operations. The components of other income (expense), net include $112 million related to provisions recorded at our construction operation primarily related to a legacy receivable balance from wound up Middle East operations, $44 million of business separation expenses, stand-up costs and restructuring charges, $27 million of net revaluation losses, $13 million of net losses on debt modification and extinguishment, $3 million of transaction costs, $2 million of expenses for employee incentive payments linked to the realization of value at our operations and $28 million of other expenses.Equity accounted Adjusted EBITDA corresponds to the Adjusted EBITDA attributable to the partnership that is generated by our investments in associates and joint ventures accounted for using the equity method.Amounts attributable to non-controlling interests are calculated based on the economic ownership interests held by the non-controlling interests in consolidated subsidiaries. Notes: Other income (expense), net corresponds to amounts that are not directly related to revenue earning activities and are not normal, recurring income or expenses necessary for business operations. The components of other income (expense), net include $194 million related to provisions recorded at our construction operation, $152 million of net revaluation gains, $105 million of business separation expenses, stand-up costs and restructuring charges, $50 million of other income related to a distribution at our entertainment operation, $32 million of transaction costs, $25 million of net gains on debt modification and extinguishment, $14 million of expenses for employee incentive payments linked to the realization of value at our operations and $95 million of other expenses.Equity accounted Adjusted EBITDA corresponds to the Adjusted EBITDA attributable to the partnership that is generated by our investments in associates and joint ventures accounted for using the equity method.Amounts attributable to non-controlling interests are calculated based on the economic ownership interests held by the non-controlling interests in consolidated subsidiaries. Brookfield, News, November 6, 2025 - Brookfield Business Corporation (NYSE, TSX: BBUC) announced today its net income (loss) for the quarter ended September 30, 2025. Net loss attributable to Brookfield Business Partners for the three months ended September 30, 2025 was $500 million, compared to net loss of $466 million during the same period in 2024. Current period results included $468 million of remeasurement loss on our exchangeable and class B shares that are classified as liabilities under IFRS. As at September 30, 2025, the exchangeable and class B shares were remeasured to reflect the closing price of $32.61 per unit. Dividend The Board of Directors has declared a quarterly dividend in the amount of $0.0625 per share, payable on December 31, 2025 to shareholders of record as at the close of business on November 28, 2025. Additional Information Each exchangeable share of Brookfield Business Corporation has been structured with the intention of providing an economic return equivalent to one unit of Brookfield Business Partners L.P. Each exchangeable share will be exchangeable at the option of the holder for one unit. Brookfield Business Corporation will target that dividends on its exchangeable shares be declared and paid at the same time as distributions are declared and paid on the Brookfield Business Partners' units and that dividends on each exchangeable share will be declared and paid in the same amount as distributions are declared and paid on each unit to provide holders of exchangeable shares with an economic return equivalent to holders of units. In addition to carefully considering the disclosures made in this news release in its entirety, shareholders are strongly encouraged to carefully review the Letter to Unitholders, Supplemental Information and other continuous disclosure filings which are available at https://bbu.brookfield.com. Please note that Brookfield Business Corporation's previous audited annual and unaudited quarterly reports have been filed on SEDAR+ and EDGAR and are available at https://bbu.brookfield.com/bbuc under Reports & Filings. Hard copies of the annual and quarterly reports can be obtained free of charge upon request. This news release does not constitute an offer to sell or a solicitation of an offer to buy any securities of BBU, BBUC or the Corporation or any other securities, and shall not constitute an offer, solicitation or sale in any state or jurisdiction in which such an offer, solicitation or sale would be unlawful. Any securities of the Corporation to be issued in the Arrangement will not be registered under the United States Securities Act of 1933, as amended (the "U.S. Securities Act"), or the securities laws of any state of the United States, and any securities issued in connection with the Arrangement are anticipated to be issued in reliance upon the exemption from the registration requirements of the U.S. Securities Act provided for by Section 3(a)(10) thereof and in accordance with applicable state securities laws. Cautionary Statement Regarding Forward-looking Statements and Information Note: This news release contains "forward-looking information" within the meaning of Canadian provincial securities laws and "forward-looking statements" within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements include statements that are predictive in nature, depend upon or refer to future events or conditions, include statements regarding the operations, business, financial condition, expected financial results, performance, prospects, opportunities, priorities, targets, goals, ongoing objectives, strategies and outlook of Brookfield Business Partners, as well as regarding recently completed and proposed acquisitions, dispositions, and other transactions, and the outlook for North American and international economies for the current fiscal year and subsequent periods, and include words such as "expects", "anticipates", "plans", "believes", "estimates", "seeks", "intends", "targets", "projects", "forecasts", "views", "potential", "likely" or negative versions thereof and other similar expressions, or future or conditional verbs such as "may", "will", "should", "would" and "could". Although we believe that our anticipated future results, performance or achievements expressed or implied by the forward-looking statements and information are based upon reasonable assumptions and expectations, investors and other readers should not place undue reliance on forward-looking statements and information because they involve assumptions, known and unknown risks, uncertainties and other factors, many of which are beyond our control, which may cause the actual results, performance or achievements of Brookfield Business Partners to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements and information. These beliefs, assumptions and expectations can change as a result of many possible events or factors, not all of which are known to us or are within our control. If a change occurs, our business, financial condition, liquidity and results of operations and our plans and strategies may vary materially from those expressed in the forward-looking statements and forward-looking information herein. Factors that could cause actual results to differ materially from those contemplated or implied by forward-looking statements include, but are not limited to, the following: the cyclical nature of our operating businesses and general economic conditions and risks relating to the economy, including unfavorable changes in interest rates, foreign exchange rates, inflation, commodity prices and volatility in the financial markets; the ability to complete and effectively integrate acquisitions into existing operations and the ability to attain expected benefits; business competition, including competition for acquisition opportunities; our ability to complete strategic actions including the Arrangement and our corporate transactions, dispositions and achieve the anticipated benefits therefrom; global equity and capital markets and the availability of equity and debt financing and refinancing within these markets; changes to U.S. laws or policies, including changes in U.S. domestic and economic policies as well as foreign trade policies and tariffs; technological change; litigation; cybersecurity incidents; the possible impact of international conflicts, wars and related developments including terrorist acts and cyber terrorism; operational, or business risks that are specific to any of our business services operations, infrastructure services operations or industrials operations; changes in government policy and legislation; catastrophic events, such as earthquakes, hurricanes and pandemics/epidemics; changes in tax law and practice; and other risks and factors detailed from time to time in our documents filed with the securities regulators in Canada and the United States including those set forth in the "Risk Factors" section in our annual report for the year ended December 31, 2024 filed on Form 20-F. Certain risks and uncertainties specific to the proposed Arrangement will be further described in the joint management information circular of BBU and BBUC to be delivered to such security holders in advance of the special meetings. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described herein can be profitably produced in the future. We qualify any and all of our forward-looking statements by these cautionary factors. We caution that the foregoing list of important factors that may affect future results is not exhaustive. When relying on our forward-looking statements and information, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements or information, whether written or oral, that may be as a result of new information, future events or otherwise. Cautionary Statement Regarding the Use of a Non-IFRS Measure This news release contains references to a Non-IFRS measure. Adjusted EBITDA is not a generally accepted accounting measure under IFRS and therefore may differ from definitions used by other entities. We believe this is a useful supplemental measure that may assist investors in assessing the financial performance of Brookfield Business Partners and its subsidiaries. However, Adjusted EBITDA should not be considered in isolation from, or as a substitute for, analysis of our financial statements prepared in accordance with IFRS. References to Brookfield Business Partners are to Brookfield Business Partners L.P. together with its subsidiaries, controlled affiliates and operating entities. Unitholders' results include limited partnership units, redemption-exchange units, general partnership units, BBUC exchangeable shares and special limited partnership units. More detailed information on certain references made in this news release will be available in our Management's Discussion and Analysis of Financial Condition and Results of Operations in our interim report for the third quarter ended September 30, 2025 furnished on Form 6-K.
Canadian Natural Resources Limited Announces Quarterly Dividend
Canadian Natural Resources Limited Announces Quarterly Dividend Calgary, Alberta--(Newsfile Corp. - November 6, 2025) - Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) announces that its Board of Directors has declared a quarterly cash dividend on its common shares of C$0.5875 (fifty-eight and three quarter cents). The dividend will be payable on January 6, 2026 to shareholders of record at the close of business on December 12, 2025.Canadian Natural's growing and sustainable dividend demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base. The Company's leading track record of growing and sustainable dividend continues, with 2025 being the 25th consecutive year of dividend increases with a compound annual growth rate ("CAGR") of 21% over that time.Canadian Natural is a senior crude oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.CANADIAN NATURAL RESOURCES LIMITEDT (403) 517-6700 F (403) 517-7350 E ir@cnrl.com2100, 855 - 2 Street S.W. Calgary, Alberta, T2P 4J8www.cnrl.com_________________________________________________________SCOTT G. STAUTHPresidentVICTOR C. DARELChief Financial OfficerLANCE J. CASSONManager, Investor RelationsTrading Symbol - CNQToronto Stock ExchangeNew York Stock ExchangeCertain information regarding the Company contained herein may constitute forward-looking statements under applicable securities laws. Such statements are subject to known or unknown risks and uncertainties that may cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The Company does not undertake to update forward-looking statements except as required by applicable securities laws. Refer to our website for detailed forward-looking statements and notes regarding Non-GAAP and Other Financial Measures at www.cnrl.com.To view the source version of this press release, please visit https://www.newsfilecorp.com/release/273344
NESR to Release Third Quarter 2025 Financial Results on November 13th
NESR to Release Third Quarter 2025 Financial Results on November 13th HOUSTON, TX / ACCESS Newswire / November 6, 2025 / National Energy Services Reunited Corp. ("NESR" or the "Company") (Nasdaq:NESR) an international, industry-leading provider of integrated energy services in the Middle East and North Africa ("MENA") region, today announced that it will release its financial results for the third quarter of 2025 on Thursday, November 13, 2025.A conference call is scheduled for 8:00 AM ET on November 13, 2025, to discuss the financial results. Investors, analysts and members of the media interested in listening to the conference call are encouraged to participate by dialling in to the U.S. toll-free line at 1-877-407-0890 or the international line at 1-201-389-0918, approximately 10 minutes prior to the start of the call.A live, listen-only earnings webcast will also be broadcast simultaneously under the "Investors" section of the Company's website at www.nesr.com. Following the end of the conference call, a replay will be available after the event under the "Investors" section of the Company's website.Cautionary Statement Regarding Forward-Looking StatementsStatements contained in this press release that are not historical fact may be forward-looking within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, each as amended. Such forward-looking statements do not constitute guarantees of future performance and are subject to a variety of risks and uncertainties. Additional factors that could cause actual results to differ materially from those projected or suggested in any forward-looking statements are contained in our filings with the SEC, including those factors discussed under the caption "Risk Factors" in such filings.You are cautioned not to place undue reliance on forward-looking statements because of the risks and uncertainties related to them and to the risk factors. The Company disclaims any obligation to update any forward-looking statements to reflect any new information or future events or circumstances or otherwise, except as required by law. You should read this communication in conjunction with other documents which the Company may file or furnish from time to time with the SEC.About National Energy Services Reunited Corp.Founded in 2017, NESR is one of the largest national oilfield services providers in the MENA and Asia Pacific regions. With over 6,000 employees, representing more than 60 nationalities in 16 countries, the Company helps its customers unlock the full potential of their reservoirs by providing Production Services such as Hydraulic Fracturing, Cementing, Coiled Tubing, Filtration, Completions, Stimulation, Pumping and Nitrogen Services. The Company also helps its customers to access their reservoirs in a smarter and faster manner by providing Drilling and Evaluation Services such as Drilling Downhole Tools, Directional Drilling, Fishing Tools, Testing Services, Wireline, Slickline, Drilling Fluids and Rig Services.For media inquiries, please contact:Lubna HamdanNational Energy Services Reunited Corp.971502670225lubna@nesr.comFor inquiries regarding NESR, or for investor queries, please contact:Blake GendronNational Energy Services Reunited Corp.832-925-3777investors@nesr.comSOURCE: National Energy Services Reunited CorpView the original press release on ACCESS Newswire
Enerflex Ltd. Announces Third Quarter 2025 Financial and Operational Results and Increased Dividend
Enerflex Ltd. Announces Third Quarter 2025 Financial and Operational Results and Increased Dividend RECORD ADJUSTED EBITDA AND RETURN ON CAPITAL EMPLOYED FREE CASH FLOW OF $43 MILLION STRONG OPERATIONAL VISIBILITY WITH ES AND EI BACKLOG OF $1.1 BILLION AND $1.4 BILLION, RESPECTIVELY QUARTERLY DIVIDEND INCREASE TO CAD$0.0425 PER SHARE SUPPORTS DIRECT SHAREHOLDER RETURNS CALGARY, Alberta, Nov. 06, 2025 (GLOBE NEWSWIRE) -- Enerflex Ltd. (TSX: EFX) (NYSE: EFXT) ("Enerflex" or the "Company") today reported its financial and operational results for the three and nine months ended September 30, 2025. All amounts presented are in U.S. Dollars unless otherwise stated. Q3/25 FINANCIAL OVERVIEW Generated revenue of $777 million compared to $601 million in Q3/24 and $615 million in Q2/25. Higher revenue is primarily attributable to commencement of the Block 60 Bisat-C Expansion Facility ("Bisat-C Expansion") located in the Eastern Hemisphere segment ("EH") which contributed $116 million in revenue to the Engineered Systems ("ES") product line, resulting in a corresponding reduction in the ES backlog for the period. Revenue also reflects strong execution of ES projects and a high level of operational activity, which led to certain project milestones being achieved earlier than expected. This resulted in revenue being realized in Q3/25 that was originally anticipated in later periods. Recorded gross margin before depreciation and amortization of $206 million, or 27% of revenue including $14 million related to the Bisat-C Expansion, compared to $176 million, or 29% of revenue in Q3/24 and $175 million, or 29% of revenue during Q2/25. Higher gross margin before depreciation and amortization is primarily attributable to strong ES activity and project execution.Energy Infrastructure ("EI") and After-Market Services ("AMS") product lines generated 58% of consolidated gross margin before depreciation and amortization during Q3/25 down from 65% during Q3/24 due to the contribution from the Bisat-C Expansion in the third quarter as well as strong ES activity.ES gross margin before depreciation and amortization decreased to 17% in Q3/25 compared to 19% in Q3/24, primarily due to lower margin recognized with the Bisat-C Expansion. SG&A was $71 million for the three months ended September 30, 2025, down $11 million from the prior year period, driven by cost-saving initiatives, improved operational efficiencies, and the absence of one-time integration costs incurred in Q3/24 partially offset by higher share-based compensation.Adjusted earnings before finance costs, income taxes, depreciation, and amortization ("adjusted EBITDA") of $145 million is a new quarterly record for Enerflex and compares to $120 million in Q3/24 and $130 million during Q2/25. Adjusted EBITDA benefitted from higher gross margin before depreciation and amortization, cost-saving initiatives, and operational efficiencies.Cash provided by operating activities before working capital increased to $115 million compared to $63 million in Q3/24 and $89 million in Q2/25, a function of higher adjusted EBITDA. Free cash flow decreased to $43 million in Q3/25 compared to $78 million during Q3/24 due to working capital investments related to the execution of projects in the ES business and higher growth capital spend offset partially by proceeds from the sale of EI assets in Latin America ("LATAM").Return on capital employed ("ROCE")1 increased to 16.9% in Q3/25, a new record for the Company, compared to 4.5% in Q3/24 and 16.4% in Q2/25. Higher ROCE is a function of the increase in trailing 12-month EBIT and lower average capital employed, predominantly due to a decline in net debt.Net earnings of $37 million or $0.30 per share in Q3/25 compared to $30 million or $0.24 per share in Q3/24 and $60 million or $0.49 per share in Q2/25. Compared to Q3/24, profitability benefitted from higher gross margin, lower SG&A expenses and lower net finance costs, partially offset by higher income tax expense and a $16 million unrealized loss on redemption options related to the Senior Secured Notes (the "Notes") compared to unrealized gains in the comparative periods.Invested $47 million in the business, consisting of $33 million in capital expenditures ($15 million for growth) and $14 million primarily related to the Bisat-C Expansion in the EH region. STRATEGIC AND OPERATIONAL HIGHLIGHTS Paul E. Mahoney joined Enerflex as President, Chief Executive Officer, and a Director on September 29, 2025. Mr. Mahoney has a distinguished track record leading global organizations across the industrial and energy sectors, delivering value through effective strategy development and execution coupled with strong culture and talent management. He most recently served as Group President, Production & Automation Technologies at ChampionX Corporation, a leading provider of production technologies for the upstream and midstream oil and gas markets.ES backlog as at September 30, 2025 of $1.1 billion provides strong visibility into future revenue generation and business activity levels. Bookings of $339 million during Q3/25 compared to $349 million in Q3/24, $365 million in Q2/25 and a trailing eight quarter average of $322 million. ES book-to-bill ratio (calculated as bookings divided by revenue), normalized for the Bisat-C Expansion, was 0.9x during Q3/25 and 1.0x on a trailing eight quarter average, 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. Utilization remained stable at 94% across a fleet size of approximately 470,000 horsepower. Enerflex is on track to grow its North American contract compression fleet to approximately 485,000 horsepower by the end of 2025.In the U.S., Enerflex was awarded a contract to deliver a 200 mmscf/d cryogenic gas processing facility and associated natural gas compression. The project will be executed by the Engineered Systems business line, working with a strategic client partner in the Permian basin, and is scheduled for delivery during 2026.The Company continues to broaden and strengthen relationships with midstream client partners in the U.S., which includes strategic alliances and further developing relationships established through the acquisition of Exterran. During Q3/25, this resulted in Enerflex securing multiple orders for large compression equipment.In Oman, Enerflex successfully completed the construction and start-up of the Bisat-C Expansion for its client partner, OQ Exploration and Production ("OQEP"). The Bisat-C Expansion marks a strategic enhancement to OQEP's upstream portfolio, with the facility designed to handle additional gross fluids capacity of 447,000 barrels per day. The project was delivered ahead of schedule and achieved first crude oil in less than 18 months. Enerflex's investment is supported by a long-term contract and reported as a finance lease.In Argentina, Enerflex delivered a state-of-the-art all-electric gas compression station for a long-standing client partner in the Vaca Muerta shale play.Enerflex received the prestigious Export-Import Bank of the U.S. (EXIM) "Deal of the Year" award for its collaboration on a gas-to-energy project in Guyana. A first-of-its-kind in Guyana, Enerflex provided the natural gas conditioning and cryogenic infrastructure for this project, which will generate 300 MW of power, reduce the country's dependence on imported fuels and expand access to power in underserved communities. SHAREHOLDER RETURNS Enerflex's Board of Directors has increased the Company's quarterly dividend by 13% to CAD$0.0425 per common share, effective with the dividend payable in December 2025.Enerflex repurchased 777,000 Common Shares at an average price of CAD$12.98 per share during Q3/25 and a total of 2,676,200 Common Shares at an average price of CAD$10.93 since its normal course issuer bid ("NCIB") commenced on April 1, 2025 (as at September 30, 2025). Under the NCIB, which expires March 31, 2026, 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. BALANCE SHEET AND LIQUIDITY Enerflex exited Q3/25 with net debt of $584 million, which included $64 million of cash and cash equivalents, a reduction of $108 million compared to Q3/24, and $24 million compared to the second quarter of 2025.Enerflex's bank-adjusted net debt-to-EBITDA ratio was approximately 1.2x at the end of Q3/25, down from 1.9x at the end of Q3/24 and 1.3x at the end of Q2/25. MANAGEMENT COMMENTARY Paul Mahoney, Enerflex's President and Chief Executive Officer stated: "I am pleased to join Enerflex at an exciting time for the Company. The strength of Enerflex's people, culture, and position as a global leader have been evident during my initial few weeks. Looking ahead, my focus is clear: to build on Enerflex's strengths, continue to sharpen our strategic priorities and investments, and ensure we stay true to the values that have guided Enerflex for decades. I believe the Company is well positioned to take advantage of growing global natural gas demand and am looking forward to working to deliver on our goals for the benefit of our shareholders, client partners, employees, and communities. Financial results and operational performance in Q3/25 reflect continued strength and stability across our global platform. The Energy Infrastructure and After-Market Services business lines continue to be the foundation of our results and contributed 58% of our gross margin before depreciation and amortization during the third quarter. The Engineered Systems business line benefitted from favorable project sequencing and strong execution to generate the highest quarterly operating revenue in its history (net of the impact from the Bisat-C Expansion). Visibility for the Engineered Systems business line remains solid, supported by a $1.1 billion backlog at the end of Q3/25 and healthy bidding prospects. The Board's decision to increase our dividend for a second consecutive year reflects confidence in our business and Enerflex's strong financial position and aligns with our priority to provide meaningful direct shareholder returns." Preet S. Dhindsa, Enerflex's Senior Vice President and Chief Financial Officer, added: "Enerflex generated solid free cash flow in the third quarter, which supported the continued investment in our U.S. contract compression fleet and $11 million of shareholder returns through dividends and share repurchases. Enerflex's financial position continued to strengthen, with a bank adjusted leverage ratio of 1.2x and liquidity of $658 million at the end of the third quarter. We remain focused on enhancing profitability of our core operations, growing our business in a disciplined and structured way, and ensuring Enerflex generates sustained, attractive returns for shareholders." SUMMARY RESULTS 1EBITDA is defined as earnings before finance costs, income taxes, depreciation and amortization. EBIT is defined as earnings before finance costs and income taxes. 2 Net debt is defined as total long-term debt less cash and cash equivalent as presented in the Financial Statements. 3 Refer 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 September 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 $1.4 billion of revenue over their remaining terms. Performance for the ES product line remains solid, with revenue and profitability during the third quarter benefitting from favorable project sequencing and strong execution. The outlook for this business line is supported by a backlog of approximately $1.1 billion, as of September 30, 2025, and healthy bidding activity, with visibility extending into the second half of 2026. Notwithstanding, Enerflex continues to closely monitor near-term risks, including tariffs and commodity price volatility, and will proactively manage this business line. Activity levels for the ES product line during Q4/25 are expected to reflect a "pull forward" of certain projects into the third quarter. ES results during Q3/25 also benefitted from the Bisat-C Expansion, which contributed revenue of $116 million and $14 million in gross margin. Enerflex continues to expect gross margin for the ES business line, in coming quarters, 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 continues to target a disciplined capital program in 2025, with total capital expenditures of approximately $120 million. This includes a total of approximately $60 million for maintenance and property, plant and equipment ("PP&E") capital expenditures and approximately $60 million allocated to growth opportunities. Disciplined capital spending will focus on customer supported opportunities primarily in the U.S. Notably, the fundamentals for contract compression in the U.S. remain strong, led by expected increases in natural gas production in the Permian basin and capital spending discipline from market participants. Enerflex will continue to make selective customer supported growth investments in this business. Providing meaningful direct shareholder returns is a priority for Enerflex. During the first three quarters of 2025, Enerflex returned $35 million to shareholders through dividend ($13 million) and share repurchases ($22 million). Reflecting confidence in Enerflex's business and strong financial position, the Board of Directors has increased the Company's quarterly dividend by 13% to CAD$0.0425 per common share. The 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. Since the NCIB commenced on April 1, 2025, Enerflex has repurchased 2,676,200 Common Shares at an average price of CAD$10.93 (as at September 30, 2025). 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 CAD$0.0425 per share, payable on December 1, 2025, to shareholders of record on November 17, 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, November 6, 2025 at 8:00 a.m. (MST), 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/BI00ab0f2d2a4b45fc9629edf15ae60d83. 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/ye8k98ud. 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 September 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. ADJUSTED EBITDA 1The Company included net earnings, income taxes, and net finance costs on a consolidated basis to reconcile to EBIT.2Net finance costs are considered corporate expenditure and therefore have not been allocated to reporting segments.3EBIT includes $16 million unrealized loss 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.3EBIT includes $19 million unrealized gain on redemption options associated with the Notes. Debt is managed within Corporate and is not 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 Enerflex defines bank-adjusted net debt to EBITDA as borrowings under the Revolving Credit Facility ("RCF") and Notes less cash and cash equivalents, divided by EBITDA for the trailing 12-months, as defined by the Company's lenders. In assessing the Company's compliance with financial covenants related to its debt, certain adjustments are made to 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 approximately 485,000 horsepower by the end of 2025;expectations that a 200 mmscf/d cryogenic gas processing facility and associated natural gas compression will be executed and delivered on schedule, if at all; Enerflex is well positioned to take advantage of growing global natural gas demand;Enerflex's ability to enhance the profitability of its core operations, grow its business, and generate sustained, attractive returns for shareholders, 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 $1.4 billion of revenue over their remaining terms; activity levels during the fourth quarter of 2025 for the ES product line are expected to be reduced by a "pull forward" of certain projects into the third quarter;ES gross margins are expected to align, in the coming quarters, more closely with historical averages;supply of natural gas and associated liquids 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 a total of approximately $60 million for maintenance and PP&E expenditures and approximately $60 million allocated to growth opportunities;continued strength in the fundamentals for contract compression in the U.S., led by expected increases in natural gas production in the Permian basin and capital spending discipline from market participants;selective customer supported growth investments continuing to be made in the US contract compression business;the ability of Enerflex to continue to make meaningful direct shareholder returns, including its ability to pay a sustainable quarterly cash dividend; andconsiderations 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; using 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 proactively manage the ES business line in response near-term risks and uncertainties, including 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;risks related to lawsuits, arbitrations or other legal proceedings;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;the Company's backlog providing strong visibility into future revenue generation and business activity levels in the ES business line;a continuing healthy pipeline of bidding opportunities in the ES product line;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 September 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: Paul MahoneyPresident and Chief Executive OfficerE-mail: PMahoney@enerflex.com Preet S. DhindsaSenior Vice President and Chief Financial OfficerE-mail: PDhindsa@enerflex.com Jeff FetterlyVice President, Corporate Development and Capital MarketsE-mail: JFetterly@enerflex.com
Vermilion Energy Inc. Announces $0.13 CDN Cash Dividend for December 31, 2025 Payment Date
Vermilion Energy Inc. Announces $0.13 CDN Cash Dividend for December 31, 2025 Payment Date CALGARY, AB, Nov. 5, 2025 /CNW/ - Vermilion Energy Inc. ("Vermilion") (TSX: VET) (NYSE: VET) is pleased to announce a cash dividend of $0.13 CDN per common share, payable on December 31, 2025 to all shareholders of record on December 15, 2025. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada). About Vermilion Vermilion is a global gas producer that seeks to create value through the acquisition, exploration and development of liquids-rich natural gas in Canada and conventional natural gas in Europe while optimizing low-decline oil assets. This diversified portfolio delivers outsized free cash flow through direct exposure to global commodity prices and enhanced capital allocation optionality. Vermilion's priorities are health and safety, the environment, and profitability, in that order. Nothing is more important than the safety of the public and those who work with Vermilion, and the protection of the natural surroundings. In addition, the Company emphasizes strategic community investment in each of its operating areas. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET. View original content to download multimedia:https://www.prnewswire.com/news-releases/vermilion-energy-inc-announces-0-13-cdn-cash-dividend-for-december-31--2025-payment-date-302606035.html SOURCE Vermilion Energy Inc. View original content to download multimedia: http://www.newswire.ca/en/releases/archive/November2025/05/c8995.html
Sunoco LP Announces Expiration and Final Results of Private Exchange Offers and Consent Solicitations for Outstanding Notes of Parkland Corporation
Sunoco LP Announces Expiration and Final Results of Private Exchange Offers and Consent Solicitations for Outstanding Notes of Parkland Corporation DALLAS, Nov. 5, 2025 /PRNewswire/ -- Sunoco LP (NYSE: SUN) ("Sunoco") today announced the expiration and final results of its previously announced private exchange offers of outstanding Canadian dollar denominated notes (collectively, "PKI CAD Notes") and U.S. dollar denominated notes (collectively, "PKI USD Notes" and, together with the PKI CAD Notes, the "PKI Notes") previously issued by Parkland Corporation ("Parkland") for new notes to be issued by Sunoco (the "New Notes") and cash (collectively, the "Exchange Offers") and related consent solicitations (collectively, the "Consent Solicitations") to adopt the Proposed Amendments (as defined below) to the PKI Indentures (as defined below), commenced by Sunoco on October 6, 2025. The Exchange Offers and Consent Solicitations expired at 5:00 p.m., New York City time, on November 4, 2025. The below tables reflect that C$1,474,777,000 in aggregate principal amount of the PKI CAD Notes, representing approximately 92.2% of the total outstanding principal amount of the PKI CAD Notes and at least a majority of each series of PKI CAD Notes outstanding, and US$2,579,839,000 in aggregate principal amount of the PKI USD Notes, representing approximately 99.2% of the total outstanding principal amount of the PKI USD Notes and at least a majority of each series of PKI USD Notes outstanding, have been validly tendered and not validly withdrawn: Title of Series of PKI CAD Notes CUSIP No. Principal Amount Tendered Percentage of Aggregate Principal Amount Tendered 3.875% Senior Notes due 2026 70137WAJ7 (Unrestricted) 70137WAK4 (Restricted) C$549,406,000 91.6 % 6.000% Senior Notes due 2028 70137WAB4 (Unrestricted) 70137WAA6 (Restricted) C$380,785,000 95.2 % 4.375% Senior Notes due 2029 70137WAF5 (Unrestricted) 70137WAE8 (Restricted) C$544,586,000 90.8 % Total: C$1,474,777,000 92.2 % Title of Series of PKI USD Notes CUSIP No. Principal Amount Tendered Percentage of Aggregate Principal Amount Tendered 5.875% Senior Notes due 2027 70137TAP0 (144A) C71968AB4 (Reg. S) US$498,854,000 99.8 % 4.500% Senior Notes due 2029 70137WAG3 (144A) C7196GAA8 (Reg. S) US$789,974,000 98.8 % 4.625% Senior Notes due 2030 70137WAL2 (144A) C7196GAB6 (Reg. S) US$798,252,000 99.8 % 6.625% Senior Notes due 2032 70137WAN8 (144A) C7196GAC4 (Reg. S) US$492,759,000 98.6 % Total: US$2,579,839,000 99.2 % As previously announced on October 21, 2025, as of 5:00 p.m., New York City time, on October 20, 2025, Sunoco received the requisite consents from Eligible Holders (as defined below) of each series of PKI Notes to amend the PKI Notes of each series and related indenture and supplemental indentures under which they were issued (as supplemented, collectively, the "PKI Indentures" and each, a "PKI Indenture"). As previously announced, on October 31, 2025, Sunoco completed its acquisition of all of the issued and outstanding common shares of Parkland. As a result, Parkland is now a wholly owned subsidiary of Sunoco. Parkland is expected to enter into supplemental indentures to the PKI Indentures (collectively, the "PKI Amending Supplemental Indentures") implementing certain proposed amendments to, among other things, eliminate from each PKI Indenture, as it relates to each series of PKI Notes (i) substantially all of the restrictive covenants, (ii) certain of the events which may lead to an "Event of Default," (iii) the financial reporting covenant and (iv) the offer to purchase notes upon a "Change of Control" (collectively, the "Proposed Amendments"). The PKI Amending Supplemental Indentures will be effective upon execution but will only become operative upon the Settlement Date (as defined below) of the applicable Exchange Offer. PKI Notes validly tendered and not validly withdrawn and that are accepted for exchange will be exchanged for New Notes on the Settlement Date, and the applicable consideration will be paid to the Eligible Holders of such PKI Notes on such date. Withdrawal rights for the Exchange Offers and Consent Solicitations expired at 5:00 p.m., New York City time, on October 20, 2025. Holders may no longer withdraw tendered PKI Notes or revoke consents, except as required by applicable law. The Exchange Offers and Consent Solicitations were made pursuant to the terms and subject to the conditions set forth in the confidential exchange offer memorandum and consent solicitation statement for the PKI CAD Notes, dated as of October 6, 2025 (the "CAD Exchange Offer Memorandum"), and the confidential exchange offer memorandum and consent solicitation statement for the PKI USD Notes, dated as of October 6, 2025 (the "USD Exchange Offer Memorandum" and together with the CAD Exchange Offer Memorandum, each an "Exchange Offer Memorandum" and collectively, the "Exchange Offer Memoranda"), each as amended by Sunoco's press release dated October 21, 2025. The settlement date of the Exchange Offers and Consent Solicitations (the "Settlement Date") is expected to occur on November 7, 2025. Each series of New Notes will have substantially identical interest rates, interest payment dates, maturity dates and redemption terms as the corresponding series of PKI Notes. The first interest payment on any New Notes will include the accrued and unpaid interest on the PKI Notes tendered in exchange therefor so that a tendering Eligible Holder will receive the same interest payment it would have received had its PKI Notes not been tendered in the Exchange Offers and Consent Solicitations; provided that the amount of accrued and unpaid interest shall only be equal to the accrued and unpaid interest on the principal amount of PKI Notes equal to the aggregate principal amount of New Notes an Eligible Holder receives. This news release is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful prior to the registration or qualification under the securities laws of any such state or jurisdiction. The New Notes offered in the Exchange Offers have not been registered with the U.S. Securities and Exchange Commission (the "SEC") under the Securities Act of 1933, as amended (the "Securities Act"), or any state or foreign securities laws and no prospectus will be filed under applicable securities laws in any of the provinces or territories of Canada. Accordingly, the New Notes will be subject to restrictions on transferability and resale and may not be transferred or resold except as permitted under the Securities Act and other applicable securities laws, pursuant to registration or exemption therefrom. The New Notes may not be offered or sold in the United States or to any "U.S. persons" (as such term is defined in Rule 902 under the Securities Act in offshore transactions in compliance with Regulation S under the Securities Act) except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act. Only persons who properly complete and return the eligibility certification (the "Eligibility Letter"), which is available from the Information Agent (as defined below), certifying that they are (i) if such person is located in the United States, a "qualified institutional buyers" within the meaning of Rule 144A under the Securities Act ("QIBs") or (ii) if such person is located outside of the United States, such person is not a U.S. person and (if a resident in Canada) a "non-U.S. qualified offeree" (such persons, "USD Exchange Eligible Holders") are authorized to receive and review the respective USD Exchange Offer Memorandum. Only USD Exchange Eligible Holders who have completed and returned an Eligibility Letter, available from the Information Agent, are authorized to receive or review the USD Exchange Offer Memorandum or to participate in the Exchange Offers and Consent Solicitations applicable to the PKI USD Notes. Only (i) QIBs, (ii) non-U.S. persons that are outside of the United States within the meaning of Regulation S under the Securities Act or (iii) non-U.S. persons that are resident in Canada and an "accredited investor" (as such term is defined in National Instrument 45-106 - Prospectus Exemptions) and, in the case of a purchaser resident in Ontario, subsection 73.3(1) of the Securities Act (Ontario), without being an individual unless such individual is also a "permitted client" as such term is defined in National Instrument 31-103 - 0x200ERegistration Requirements, Exemptions, and Ongoing Registrant Obligations (such persons, the "CAD Exchange Eligible Holders" and, together with the USD Exchange Eligible Holders, the "Eligible Holders") are eligible to participate in the Exchange Offers and Consent Solicitations applicable to the PKI CAD Notes. Holders who desire to obtain a copy of the Eligibility Letter should contact D.F. King & Co., Inc., the information and exchange agent for the Exchange Offers and Consent Solicitations (the "Information Agent"), at (800) 967-7635 (toll-free) or (212) 269-5550 (banks and brokers), at www.dfking.com/parkland or by email at parkland@dfking.com. D.F. King & Co., Inc. will also provide copies of the respective Exchange Offer Memorandum to Eligible Holders. Computershare Investor Services Inc. is the exchange and tabulation agent for the Exchange Offer and Consent Solicitation relating to the PKI CAD Notes, and can be reached at +1(604) 661-9400. Questions concerning the terms of the Exchange Offers or the Consent Solicitations should be directed to the dealer managers for the Exchange Offers and the solicitation agents for the Consent Solicitations: Citigroup Global Markets Inc. 388 Greenwich Street, 4th Floor Trading New York, New York 10013 Attn: Liability Management Group Collect: +1 (212) 723-6106 Toll free: +1 (800) 558-3745 E-mail: ny.liabilitymanagement@citi.com TD Securities (USA) LLC 1 Vanderbilt Avenue, 11th FloorNew York, New York 10017Attention: Liability Management Group Collect: +1 (212) 827-2842 Toll Free: +1 (866) 584-2096 Email: LM@tdsecurities.com The Exchange Offers and Consent Solicitations were made only pursuant to the Exchange Offer Memoranda. The Exchange Offer Memoranda and other documents relating to the Exchange Offers and Consent Solicitations were distributed only to Eligible Holders. The Exchange Offers were not made to holders of PKI Notes in any jurisdiction in which the making or acceptance thereof would not be in compliance with the securities, blue sky or other laws of such jurisdiction. The New Notes have not been approved or disapproved by any securities commission, stock exchange or other similar regulatory authority, nor has any such securities commission, stock exchange or other similar regulatory authority passed upon the accuracy or adequacy of the Exchange Offer Memoranda. None of Sunoco, Sunoco's subsidiaries, its and their respective directors or officers, the dealer managers and solicitation agents, the information and exchange agent, the exchange and tabulation agent, any trustee for the New Notes or the PKI Notes, their respective affiliates, or any other person is making any recommendation as to whether holders should tender their PKI Notes in the Exchange Offers or deliver consents in the Consent Solicitations. About Sunoco LP Sunoco LP (NYSE: SUN) is a leading energy infrastructure and fuel distribution master limited partnership operating across 32 countries and territories in North America, the Greater Caribbean, and Europe. Sunoco's midstream operations include an extensive network of approximately 14,000 miles of pipeline and over 160 terminals. This critical infrastructure complements Sunoco's fuel distribution operations, which distribute over 15 billion gallons annually to approximately 11,000 Sunoco and partner-branded retail locations, as well as independent dealers and commercial customers. Sunoco's general partner is owned by Energy Transfer LP (NYSE: ET). 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, including without limitation statements regarding the Exchange Offers and the expected Settlement Date. 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 are discussed in Sunoco's Annual Report on Form 10-K, any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and other documents filed from time to time with the SEC. Sunoco undertakes no obligation to update or revise any forward-looking statement to reflect new information or events. Contacts Scott GrischowTreasurer, Senior Vice President - Finance(214) 840-5660, scott.grischow@sunoco.com Brian BrungardtDirector - Investor Relations(214) 840-5437, brian.brungardt@sunoco.com View original content to download multimedia:https://www.prnewswire.com/news-releases/sunoco-lp-announces-expiration-and-final-results-of-private-exchange-offers-and-consent-solicitations-for-outstanding-notes-of-parkland-corporation-302606259.html SOURCE Sunoco LP
W&T Offshore Announces Third Quarter 2025 Results and Declares Dividend for Fourth Quarter of 2025
W&T Offshore Announces Third Quarter 2025 Results and Declares Dividend for Fourth Quarter of 2025 HOUSTON, Nov. 05, 2025 (GLOBE NEWSWIRE) -- W&T Offshore, Inc. (NYSE: WTI) ("W&T," the "Company," "we" or "us") today reported operational and financial results for the third quarter of 2025 and declared a fourth quarter 2025 dividend of $0.01 per share. This press release includes non-GAAP financial measures, including Adjusted Net Loss, Adjusted EBITDA, Free Cash Flow and Net Debt, which are described and reconciled to the most comparable GAAP measures in the accompanying tables to this press release under "Non-GAAP Information." Key highlights for the third quarter of 2025 and through the date of this press release include: Increased production to 35.6 thousand barrels of oil equivalent per day ("MBoe/d") (49% liquids), near the high end of guidance;Reduced lease operating expenses ("LOE") per barrel of oil equivalent ("Boe") by 8% compared with second quarter of 2025 to $23.27 per Boe, or an absolute cost of $76.2 million, near the midpoint of guidance;Reported net loss of $71.5 million, or $(0.48) per diluted share which was significantly impacted by a non-cash valuation allowance of $59.9 million against the Company's deferred tax assets; Adjusted Net Loss totaled $7.3 million, or $(0.05) per diluted share which excludes the valuation allowance and the unrealized loss on commodity derivatives and related tax effect; Grew Adjusted EBITDA by 11% over the second quarter of 2025 to $39.0 million;Generated net cash flow from operating activities of $26.5 million;Increased unrestricted cash and cash equivalents to $124.8 million and reported total debt of $350.4 million and Net Debt of $225.6 million at September 30, 2025;Paid eighth consecutive quarterly dividend of $0.01 per common share in August 2025; and Declared fourth quarter 2025 dividend of $0.01 per share, which will be payable on November 26, 2025 to stockholders of record on November 19, 2025. Tracy W. Krohn, W&T's Chairman of the Board and Chief Executive Officer, commented, "We remain committed to executing our strategic vision and are delivering strong results, including production growth of 6% and Adjusted EBITDA growth of 11% quarter-over-quarter. In addition, we continue to grow our cash position and reduce our Net Debt, which is down almost $60 million from year-end 2024. Operationally, we have seen strong production since bringing on the remaining two fields from the Cox acquisition, which has allowed us to increase production each quarter thus far in 2025. Acquisitions remain a key component of our success, and it is our ability to integrate and enhance the assets that we acquire that has allowed us to successfully operate for over 40 years. Our balance sheet has continued to strengthen in 2025 with the successful issuance of new 10.75% Notes, a new revolving credit facility and material cash additions through a non-core disposition and an insurance settlement. We have approximately $125 million in cash on our balance sheet and remain prepared to take advantage of potential acquisitions." Production, Prices and Revenue: Production for the third quarter of 2025 was 35.6 MBoe/d, near the high end of the Company's third quarter guidance, and an increase of 6% compared with 33.5 MBoe/d for the second quarter of 2025 and an increase of 15% compared with 31.0 MBoe/d for the corresponding period in 2024. Third quarter 2025 production was comprised of 14.3 thousand barrels per day ("MBbl/d") of oil (40%), 3.1 MBbl/d of natural gas liquids ("NGLs") (9%), and 111.6 million cubic feet per day ("MMcf/d") of natural gas (51%). Production has increased 17% from first quarter of 2025 to third quarter of 2025. This highlights the impact of the Cox fields coming online and W&T's inventory of high return workover projects on its existing assets. W&T's average realized price per Boe before realized derivative settlements was $38.33 per Boe in the third quarter of 2025, a decrease of 2% from $39.16 per Boe in the second quarter of 2025 and 9% from $41.92 per Boe in the third quarter of 2024. Third quarter 2025 oil, NGL and natural gas prices before realized derivative settlements were $64.62 per barrel of oil, $14.29 per barrel of NGL and $3.68 per Mcf of natural gas. Revenues for the third quarter of 2025 were $127.5 million, which was 4% higher than second quarter of 2025 revenues of $122.4 million due to higher production volumes, which were partially offset by lower realized prices. Third quarter 2025 revenues were higher by 5% compared to $121.4 million of revenues in the third quarter of 2024 due to higher production volumes offset by lower realized prices. Lease Operating Expenses: LOE, which includes base lease operating expenses, insurance premiums, workovers and facilities maintenance expenses, was $76.2 million in the third quarter of 2025, which was near the midpoint of the Company's guidance range. While LOE for the third quarter of 2025 was essentially flat with $76.9 million in the second quarter of 2025, on a per barrel basis, LOE was lower by 8%. LOE for the third quarter of 2025 was higher than the $72.4 million for the corresponding period in 2024 primarily due to higher base operating expenses, insurance premiums and workover expenses associated with increased production. On a component basis for the third quarter of 2025, base LOE and insurance premiums were $62.4 million, workovers were $2.6 million, and facilities maintenance and other expenses were $11.2 million. On a unit of production basis, LOE was $23.27 per Boe in the third quarter of 2025. This was lower than $25.20 per Boe for the second quarter of 2025 and $25.37 per Boe for the corresponding period in 2024. Gathering, Transportation Costs and Production Taxes: Gathering, transportation costs and production taxes totaled $5.8 million ($1.78 per Boe) in the third quarter of 2025, compared to $5.5 million ($1.80 per Boe) in the second quarter of 2025 and $6.1 million ($2.15 per Boe) in the third quarter of 2024. Depreciation, Depletion and Amortization ("DD&A"): DD&A was $8.73 per Boe in the third quarter of 2025. This compares to $8.67 per Boe and $11.99 per Boe for the second quarter of 2025 and the third quarter of 2024, respectively. The decrease in the DD&A rate per Boe for the third quarter of 2025 compared to the same period in 2024 was driven by the revaluation of W&T's underlying asset base associated with the mid-year 2025 reserve report. Asset Retirement Obligations Accretion: Asset retirement obligations accretion was $2.44 per Boe in the third quarter of 2025. This compares to $2.84 per Boe and $2.75 per Boe for the second quarter of 2025 and the third quarter of 2024, respectively. General & Administrative Expenses ("G&A"): G&A was $21.5 million ($18.0 million related to cash G&A) for the third quarter of 2025, which increased from $17.7 million in the second quarter of 2025 and $19.7 million in the third quarter of 2024. These increases between periods was primarily due to an increase in non-cash stock-based compensation expense after the grant in the second quarter of 2025 was fully realized in the third quarter of 2025. Cash G&A was relatively consistent on a quarter-over-quarter basis. On a unit of production basis, G&A was $6.57 per Boe in the third quarter of 2025 compared to $5.79 per Boe in the second quarter of 2025 and $6.91 per Boe in the corresponding period of 2024. Derivative Gain, net: In the third quarter of 2025, W&T recorded a net gain of $4.1 million related to commodity derivative contracts comprised of $9.7 million of realized gains, which includes $7.6 million of proceeds from the monetization of the Company's natural gas costless collar, and $5.6 million of unrealized loss related to the decrease in fair value of open contracts. W&T recognized a net gain of $12.0 million in the second quarter of 2025 and a net gain of $3.2 million in the third quarter of 2024 related to commodity derivative activities. A summary of the Company's outstanding derivative positions is provided in the investor presentation posted on W&T's website. Interest Expense: Net interest expense in the third quarter of 2025 was $9.0 million, flat with $9.0 million in the second quarter of 2025 and lower than $10.0 million in the third quarter of 2024. The decrease from the same period in 2024 reflects the impact of the Company's debt refinancing in January 2025. Income Tax Expense (Benefit): W&T recognized an income tax expense of $56.0 million in the third quarter of 2025 related to a $59.9 million valuation allowance against the Company's deferred tax assets. This compares to the recognition of an income tax benefit of $2.4 million in the second quarter of 2025 and $4.5 million in the third quarter of 2024. Balance Sheet and Liquidity: As of September 30, 2025, W&T had available liquidity of $174.8 million comprised of $124.8 million in unrestricted cash and cash equivalents and $50.0 million of borrowing availability under W&T's new revolving credit facility. As of September 30, 2025, the Company had total debt of $350.4 million and Net Debt of $225.6 million, which has decreased $58.6 million from $284.2 million at December 31, 2024. As of September 30, 2025, Net Debt to trailing twelve months Adjusted EBITDA was 1.6x. Capital Expenditures and Asset Retirement Obligation Settlements: Capital expenditures on an accrual basis in the third quarter of 2025 were $22.5 million, and asset retirement obligation settlement costs totaled $8.9 million. The increase in capital expenditures in the third quarter of 2025 was driven by recompletion and facility capital work to bring online and increase production at multiple fields related to the 2024 Cox acquisition. These capital expenditures contributed positively to W&T's production and aided in the quarter over quarter increase to production. For the nine months ended September 30, 2025, capital expenditures on an accrual basis totaled $41.5 million and asset retirement obligation settlement costs totaled $24.9 million. The Company's revised expectation for full year capital expenditures guidance is between $57 million and $63 million, which excludes potential acquisition opportunities. The forecasted increase in capital expenditures is mainly due to final investment decisions in the third quarter to lay new pipelines which are expected to lower future transportation costs and enhance production and value. Cash Dividend Policy The Company paid its third quarter 2025 dividend of $0.01 per share on August 25, 2025 to stockholders of record on August 18, 2025. The Board of Directors declared a fourth quarter 2025 dividend of $0.01 per share which is to be paid on November 26, 2025 to stockholders of record on November 19, 2025. OPERATIONS UPDATE Well Recompletions and Workovers During the third quarter of 2025, W&T performed five low cost, low risk workovers and three recompletions that exceeded expectations and positively impacted production and revenue for the quarter. W&T plans to continue performing these low cost and low risk short payout operations that impact both production and revenue. Fourth Quarter and Full Year 2025 Production and Expense Guidance The guidance for the fourth quarter and full year 2025 in the table below represents the Company's current expectations. Please refer to the section entitled "Forward-Looking and Cautionary Statements" below for risk factors that could impact guidance. In conjunction with the pipeline-related increase in capital expenditures, the Company is lowering gathering, transportation and production taxes guidance for full year 2025 to $24.0 $26.0 million primarily due to lesser reliance on third-party midstream infrastructure. Also, full year 2025 guidance for DD&A is reduced to $11.50 $12.50 per Boe. W&T expects substantially all income taxes in 2025 to be deferred. Conference Call Information: W&T will hold a conference call to discuss its financial and operational results on Thursday, November 6, 2025 at 9:00 a.m. Central Time (10:00 a.m. Eastern Time). Interested parties may dial 1-844-739-3797. International parties may dial 1-412-317-5713. Participants should request to connect to the "W&T Offshore Conference Call." This call will also be webcast and available on W&T's website at www.wtoffshore.com under "Investors." An audio replay will be available on the Company's website following the call. About W&T Offshore W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of America and has grown through acquisitions, exploration and development. As of September 30, 2025, the Company had working interests in 50 fields in federal and state waters (which include 43 fields in federal waters and seven in state waters). The Company has under lease approximately 624,700 gross acres (486,900 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 477,200 gross acres on the conventional shelf, approximately 141,900 gross acres in the deepwater and 5,600 gross acres in Alabama state waters. A majority of the Company's daily production is derived from wells it operates. For more information on W&T, please visit the Company's website at www.wtoffshore.com. Forward-Looking and Cautionary Statements This press 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. All statements other than statements of historical facts included in this release, including those regarding the Company's financial position, operating and financial performance, business strategy, plans and objectives of management for future operations, projected costs, industry conditions, potential acquisitions, the outcomes and impact of ongoing litigation, the impact of and integration of acquired assets, and indebtedness are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as "estimate," "project," "predict," "believe," "expect," "continue," "anticipate," "target," "could," "plan," "intend," "seek," "goal," "will," "should," "may" or other words and similar expressions that convey the uncertainty of future events or outcomes, although not all forward-looking statements contain such identifying words. Items contemplating or making assumptions about actual or potential future production and sales, prices, market size, and trends or operating results also constitute such forward-looking statements. These forward-looking statements are based on the Company's current expectations and assumptions about future events and speak only as of the date of this release. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. Accordingly, you are cautioned not to place undue reliance on these forward-looking statements, as results actually achieved may differ materially from expected results described in these statements. The Company does not undertake, and specifically disclaims, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements, unless required by law. Forward-looking statements are subject to risks and uncertainties that could cause actual results to differ including, among other things, the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/or maintaining permits and approvals, including those necessary for drilling and/or development projects; the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to permitting, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of the Company's products; inflation levels; global economic trends, geopolitical risks and general economic and industry conditions, such as the global supply chain disruptions and the government interventions into the financial markets and economy in response to inflation levels and world health events; volatility of oil, NGL and natural gas prices; the global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources; supply of and demand for oil, NGLs and natural gas, including due to the actions of foreign producers, importantly including OPEC and other major oil producing companies ("OPEC+") and change in OPEC+'s production levels; disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver the Company's oil and natural gas and other processing and transportation considerations; inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, meet the Company's working capital requirements or fund planned investments; price fluctuations and availability of natural gas and electricity; the Company's ability to use derivative instruments to manage commodity price risk; the Company's ability to meet the Company's planned drilling schedule, including due to the Company's ability to obtain permits on a timely basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable quantities; uncertainties associated with estimating proved reserves and related future cash flows; the Company's ability to replace the Company's reserves through exploration and development activities; drilling and production results, lowerthanexpected production, reserves or resources from development projects or higherthanexpected decline rates; the Company's ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells; changes in tax laws; effects of competition; uncertainties and liabilities associated with acquired and divested assets; the Company's ability to make acquisitions and successfully integrate any acquired businesses; asset impairments from commodity price declines; large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies; geographical concentration of the Company's operations; the creditworthiness and performance of the Company's counterparties with respect to its hedges; impact of derivatives legislation affecting the Company's ability to hedge; failure of risk management and ineffectiveness of internal controls; catastrophic events, including tropical storms, hurricanes, earthquakes, pandemics and other world health events; environmental risks and liabilities under U.S. federal, state, tribal and local laws and regulations (including remedial actions); potential liability resulting from pending or future litigation; the Company's ability to recruit and/or retain key members of the Company's senior management and key technical employees; information technology failures or cyberattacks; and governmental actions and political conditions, as well as the actions by other third parties that are beyond the Company's control, and other factors discussed in W&T Offshore's most recent Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q found at www.sec.gov or at the Company's website at www.wtoffshore.com under the Investor Relations section. W&T OFFSHORE, INC. AND SUBSIDIARIESNon-GAAP Information Certain financial information included in W&T's 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 are "Net Debt," "Adjusted Net Loss," "Adjusted EBITDA" and "Free Cash Flow" or are derivable from a combination of these measures. 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. Prior period amounts have been conformed to the methodology and presentation of the current period. We calculate Net Debt as total debt (current and long-term portions), less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations. Reconciliation of Net Loss to Adjusted Net Loss Adjusted Net Loss adjusts for certain items that the Company believes affect comparability of operating results, including items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. These items include loss on extinguishment of debt, unrealized commodity derivative (gain) loss, net, allowance for credit losses, non-recurring legal and IT-related costs, non-ARO P&A costs, and other which are then tax effected using the Federal Statutory Rate. Company management believes that this presentation is relevant and useful because it helps investors to understand the net loss of the Company without the effects of certain non-recurring or unusual expenses and certain income or loss that is not realized by the Company. W&T OFFSHORE, INC. AND SUBSIDIARIESNon-GAAP Information Adjusted EBITDA/ Free Cash Flow Reconciliations The Company also presents non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow. The Company defines Adjusted EBITDA as net loss plus net interest expense, loss on extinguishment of debt, income tax expense (benefit), depreciation, depletion and amortization, ARO accretion, excluding the unrealized commodity derivative (gain) loss, allowance for credit losses, non-cash incentive compensation, non-recurring legal and IT-related costs, non-ARO P&A costs, and other. Company management believes this presentation is relevant and useful because it helps investors understand W&T'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 W&T 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. The Company defines Free Cash Flow as Adjusted EBITDA (defined above), less capital expenditures, ARO settlements and net interest expense (all on an accrual basis). 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 the lease maintenance costs) and equipment but excludes acquisition costs of oil and gas properties from third parties that are not included in the Company's capital expenditures guidance provided to investors. Company management believes that Free Cash Flow is an important financial performance measure for use in evaluating the performance and efficiency of its current operating activities after the impact of accrued capital expenditures, P&A costs and net interest expense and without being impacted by items such as changes associated with working capital, which can vary substantially from one period to another. There is no commonly accepted definition of Free Cash Flow within the industry. Accordingly, Free Cash Flow, as defined and calculated by the Company, may not be comparable to Free Cash Flow or other similarly named non-GAAP measures reported by other companies. While the Company includes net interest expense in the calculation of Free Cash Flow, other mandatory debt service requirements of future payments of principal at maturity (if such debt is not refinanced) are excluded from the calculation of Free Cash Flow. These and other non-discretionary expenditures that are not deducted from Free Cash Flow would reduce cash available for other uses. The following table presents a reconciliation of the Company's net loss, a GAAP measure, to Adjusted EBITDA and Free Cash Flow, as such terms are defined by the Company: The following table presents a reconciliation of cash flow from operating activities, a GAAP measure, to Free Cash Flow, as defined by the Company:
Borr Drilling Limited Announces Third Quarter 2025 Results
Borr Drilling Limited Announces Third Quarter 2025 Results HAMILTON, Bermuda, Nov. 5, 2025 /PRNewswire/ -- Borr Drilling Limited (NYSE: BORR) ("Borr", "Borr Drilling" or the "Company") announces unaudited results for the nine months ended September 30, 2025. Highlights Total operating revenues of $277.1 million, an increase of $9.4 million or 4% compared to the second quarter of 2025 Net income of $27.8 million, a decrease of $7.3 million or 21% compared to the second quarter of 2025 Adjusted EBITDA of $135.6 million, an increase of $2.4 million or 2% compared to the second quarter of 2025 YTD 2025, the company was awarded 22 new contract commitments, representing more than 4,820 days and $625 million of potential contract revenue CEO, Bruno Morand commented: "Our third quarter results were strong, extending the rebound delivered in the second-quarter. With 23 of our 24 rigs active during the quarter, we demonstrated disciplined execution and commercial strength in contracting rigs despite a dynamic market. Revenue increased by $9.4 million this quarter over the second quarter and Adjusted EBITDA rose 2% to $135.6 million with a margin of 48.9%, confirming the quality of our earnings. Operational execution remained robust, with technical utilization of 97.9% and economic utilization of 97.4% across the active fleet, reflecting the continued strength and efficiency of our operations. Following quarter end, we announced three contract extensions in Mexico. The Galar and Gersemi each received a two-year firm extension at improved commercial and payment terms. A third rig, the Njord, also received an extension. Mexico remains an important market for us. Collections restarted in September, with approximately $19 million received in September and October. These inflows, together with recent government actions to strengthen Pemex finances, are the basis for our confidence in the continued normalization of payments. Today we also announced new commitments for our rigs Odin and Grid, expanding Borr Drilling's footprint into the Gulf of America and Angola. These awards reflect our focused commercial strategy, deep customer relationships, and disciplined fleet management. They further diversify our customer and market portfolio, underscore our ability to navigate evolving conditions, and minimize idle time across the fleet. Following these awards, our 2026 coverage stands at 62% with an average dayrate of $140,000, including priced options. We expect fourth quarter 2025 results to reflect fewer operating days, due to several rigs transitioning between contracts and the recent impact of sanctions-induced contract terminations in Mexico. Despite this, we anticipate full year 2025 Adjusted EBITDA in the range of $455 million to $470 million. In recent quarters, we have experienced incremental jack-up demand across several international markets, absorbing available capacity and providing gradual relief to the headwinds from 2024. While near-term volatility may persist, clear signs of demand inflection in Saudi Arabia and Mexico - two of the world's largest jack-up markets - together with incremental activity in other areas, provide us with confidence that the market is now past the trough. We foresee a tightening market in the near to medium term that we expect should support higher utilization and dayrates. In closing, the Borr Drilling platform - built on operational excellence, customer centricity, and our premium jack-up fleet - remains our defining competitive advantage placing us uniquely to benefit from improving market conditions." Conference Call A conference call and webcast are scheduled for 10:00 AM New York time (16:00 CET) on Thursday, 6 November 2025 and participants are encouraged to dial in 10 minutes before the start of the call. In order to listen to the live presentation, participants may do one of the following: a) Webcast To access the webcast, please go to the following link: https://edge.media-server.com/mmc/p/cnew3tt2 b) Conference Call Please use the below link to register for the conference call: https://register-conf.media-server.com/register/BI3e96a12fb9a64883b3d8e2fb87e2511c Participants will then receive dial-in details on screen and via email and may choose to dial in with their unique pin or select "Call me" and provide telephone details for the system to link them automatically. CONTACT: Questions should be directed to: Magnus Vaaler, CFO, +44 1224 289208 This information was brought to you by Cision http://news.cision.com https://news.cision.com/borr-drilling-limited/r/borr-drilling-limited-announces-third-quarter-2025-results,c4262808 The following files are available for download: https://mb.cision.com/Public/16983/4262808/96cf0156a20d2002.pdf Borr Drilling Limited Q3 2025 Fleet Status Report https://mb.cision.com/Public/16983/4262808/9030ca4fd4b57118.pdf Borr Drilling Limited Q3 2025 Earnings Release View original content:https://www.prnewswire.com/news-releases/borr-drilling-limited-announces-third-quarter-2025-results-302606241.html SOURCE Borr Drilling Limited
GeoPark Reports Third Quarter 2025 Results
GeoPark Reports Third Quarter 2025 Results Strong Operational and Financial Delivery in Line With 2025 GuidanceSeamless Takeover of the Vaca Muerta OperationQuarterly Cash Dividend of $0.03 Per ShareEstablishes Special Committee of Independent Directors to Evaluate Any Revised Offer From Parex and Other Value-maximizing Alternatives for the Company BOGOTA, Colombia, Nov. 05 /BusinessWire/ -- GeoPark Limited ("GeoPark" or the "Company") (NYSE:GPRK), a leading independent energy company with over 20 years of successful operations across Latin America, reports its consolidated financial results for the three-month period ended September 30, 2025 ("Third Quarter" or "3Q2025"). A conference call to discuss these financial results will be held on November 6, 2025, at 10:00 am (Eastern Standard Time). GeoPark delivered a strong quarter, driven by higher production, stable prices, and disciplined cost control, in line with 2025 guidance. The Company continued to strengthen its balance sheet through proactive debt management and robust cash generation while advancing its strategic priorities by successfully completing the Vaca Muerta acquisition and launching a revised dividend program. On October 21, 2025, GeoPark presented its long-term strategic plan, operational priorities and updated capital allocation framework, outlining a clear two-fold reset strategy to (i) sustain a resilient, high-margin base in Colombia and (ii) scale a transformational growth platform in Argentina's Vaca Muerta formation. The plan sets an outlook through 2030, targeting consolidated production of approximately 42,000-46,000 boepd, Adjusted EBITDA between $520-550 million, and a net leverage ratio of 0.8-1.0x1. The strengthening of the Company's balance sheet and its long-term strategic plan reinforce GeoPark's commitment to disciplined sustainable growth, portfolio diversification, shareholder returns and long-term value creation. THIRD QUARTER 2025 FINANCIAL SUMMARY In 3Q2025, GeoPark reported Adjusted EBITDA2 of $71.4 million (57% margin), broadly stable versus 2Q2025, explained by higher production during the quarter (28,136 boepd vs 27,380 boepd in 2Q2025) and the stability of realized prices ($57.1/bbl vs $57.4/bbl in 2Q2025). Operating costs stood at a competitive $12.5 per barrel of produced boe, in line with 2Q2025 and overall market guidance for 2025. Year-to-date Adjusted EBITDA amounted to approximately $230.0 million, supported by higher production and lower operational and G&A costs across the business, reflecting the early impact of the cost discipline and efficiency initiatives underway. Net income for the quarter totaled $15.9 million, compared to a net loss of $10.3 million in 2Q2025. This result for the quarter accounts for a non-recurring write-off of $7.5 million related to exploration costs incurred in previous years in the Putumayo Basin in Colombia. Excluding the non-recurring events in each of 2Q2025 and 3Q20253, net profit in 3Q2025 was $23.4 million compared to $20.7 million in 2Q2025. Capital expenditures totaled $17.5 million in 3Q2025, primarily focused on maintaining and improving production through an integrated drilling and workover campaign in the Llanos 34 block (GeoPark operated, 45% WI). At the same time, activities progressed on multiple fronts across GeoPark's exploration assets in the Llanos basin. During the quarter, the Company advanced drilling operations on the Toritos Norte 3 well in the Llanos 123 block (GeoPark operated, 50% WI) and continued infrastructure development on key platforms in Puerto Gaitán, laying a solid foundation for the upcoming drilling campaign in the Llanos 104 block. Since the closing of the Vaca Muerta acquisition on October 16, 2025, the Company has safely and efficiently taken over the operations, ensuring seamless operational continuity, and within less than 10 days has started delivering on its plan by commencing workover activities to install rod pumps in 3 wells in the Loma Jarillosa Este block to improve productivity. Crude is being sold locally, and procurement is underway to secure the activity plan for 2026. Additionally, the Company is identifying multiple cost efficiency and synergy opportunities to accelerate development, optimize returns and unlock additional value. The Company continued to generate strong operating cash flow during the quarter, supported by the efficiency initiatives implemented in 2Q2025. This solid performance enabled GeoPark to fully fund its investment program, reduce debt, distribute dividends, and make an early payment related to the Vaca Muerta acquisition4. As a result, at the end of 3Q2025, GeoPark's cash in hand stood at $197.0 million. During the quarter, GeoPark repurchased and cancelled $33.0 million in aggregate principal of its 2030 Notes at an average price of $0.90 on the dollar. In total, between June and October, the Company repurchased $108.3 million in aggregate principal of its 2030 Notes, resulting in annual cash coupon savings of $9.5 million. Net debt stood at $373.4 million at the end of 3Q2025, with a low leverage ratio of 1.2x, reflecting a robust capital structure. To mitigate downside risk from oil price volatility, the Company continues to proactively manage its hedging strategy. As of the date hereof, oil price protection for 2026 has been secured through 3-way collars, for approximately 62% of full-year production, with a first floor at $65/bbl, a second floor at $50/bbl and average ceilings of $73/bbl. As announced on October 21, 2025, ahead of the Company's Investor Day, and following the completion of the Vaca Muerta acquisition, the Board approved a revised dividend program including a total expected distribution of approximately $6 million over the next four quarters, equivalent to $1.5 million per quarter (or $0.03 per share), commencing with the 3Q2025 results payout and ending with the 2Q2026 results payout. Dividends will be suspended commencing with the 3Q2026 results, aligned with increased capital expenditures for Vaca Muerta. The Board will reassess dividends once positive free cash flow generation resumes after the peak investment phase, consistent with GeoPark's disciplined, returns-based capital framework. Looking ahead, GeoPark is on track to release its 2026 Work Program and Investment Guidelines before year-end. This plan will reflect the Company's renewed strategic direction-focused on building and maximizing value delivery from its high-margin base in Colombia, and new operated assets in Vaca Muerta. Felipe Bayon, Chief Executive Officer of GeoPark, said: "Our third-quarter results underscore the strength and resilience of GeoPark's business model and the confidence with which we are executing our strategy - delivering operational excellence, disciplined capital allocation, and profitable growth. With a robust balance sheet, a clear plan, and a portfolio of high-quality and distinctive assets that combines stable cash generation in Colombia with transformative growth in Argentina, GeoPark is well positioned to maximize value and deliver sustainable returns for our shareholders." UPDATE ON ENGAGEMENT WITH PAREX RESOURCES As communicated in GeoPark's press release of October 29, 2025, the GeoPark Board is open to opportunities that fairly reflect the Company's value, strategy, and long-term potential. Following a robust process, the Board unanimously determined that the unsolicited, non-binding proposal of $9.00 per share submitted by Parex Resources ("Parex") on September 4, 2025, prior to the announcement of GeoPark's transformative acquisition in Vaca Muerta, undervalues GeoPark, fails to reflect its growth prospects and diversified portfolio, and is not in its shareholders' best interests. Following Parex's public reiteration of its $9.00 per share offer, the Board unanimously agreed that Felipe Bayon should further engage with Parex and provide additional information to help it improve its offer. In addition, GeoPark's Board of Directors has formed a Special Committee of independent directors, including Sylvia Escovar Gomez, Constantin Papadimitriou, Somit Varma and Brian Maxted, to evaluate any potential revised offer from Parex and other value-maximizing alternatives for the Company. GeoPark does not intend to make any further public comment on the process unless and until it determines that further disclosure is appropriate. Supplementary information is available at the following link: https://ir.geo-park.com/3Q25-SupplementaryRelease THIRD QUARTER 2025 HIGHLIGHTS Oil and Gas Production and Operations 3Q2025 consolidated average oil and gas production of 28,136 boepd5, reflecting solid delivery from core operated and non-operated assets Year-to-date consolidated average oil and gas production of 28,194 boepd, within high-end production guidance for 2025 5 rigs in operation (2 drilling and 3 workover) at the end of 3Q2025 Vaca Muerta year-to-date average oil and gas production of approximately 2,060 boepd, with 3Q2025 average production of 1,660 boepd Revenue, Adjusted EBITDA and Net Profit Revenue of $125.1 million, 4% higher than 2Q2025, reflecting higher volumes and a stable realized price Adjusted EBITDA of $71.4 million with a 57% margin, leveraged by stable operating costs Operating profit of $32.4 million, driven by the same factors that explain the previously discussed net income Net profit of $15.9 million ($0.31 basic earnings per share) Cost and Capital Efficiency Capital expenditures of $17.5 million, focused on maintaining and improving production and advancing exploration activities across the Llanos basin 3Q2025 Adjusted EBITDA to capital expenditures ratio of 4.1x ROACE of 23%6 Operating costs per produced boe of $12.5 By September 2025, the Company had achieved $15.1 million in efficiencies, equivalent to about $19.5 million in annualized structural savings Balance Sheet and Liquidity Cash in hand of $197.0 million Full-Year net leverage of 1.2x and no principal debt maturities until January 2027 During 3Q2025, successfully completed open market repurchases of $33.0 million in aggregate principal of its 2030 Notes below par, generating a $3.0 million gain and annual cash coupon savings of $2.9 million Hedging and Risk Management $1.5 million gain from commodity risk management contracts recognized in 3Q2025 revenue As of the date hereof, approximately 62% of 2026 expected production has been protected through 3-way collars with average strikes of $65/$50/$73 Shareholder Value Return Quarterly cash dividend of $0.03 per share, or approximately $1.5 million, payable on December 4, 2025, to shareholders of record at the close of business on November 19, 2025, in line with the revised dividend program approved by the Board following the completion of the Vaca Muerta acquisition, and considering GeoPark's projected capital needs Dividend suspension commencing with the 3Q2026 results The Board will reassess dividends once positive free cash flow generation resumes after the peak investment phase, consistent with GeoPark's disciplined, returns-based capital framework All figures are expressed in US Dollars and growth comparisons refer to the same period of the prior year, except when specified. Definitions and terms used herein are provided in the Glossary at the end of this document. This press release and its supplementary information do not contain all the Company's financial information and the Company's consolidated financial statements and corresponding notes for the period are available on the Company's website. CONFERENCE CALL INFORMATION GeoPark management will host a conference call on Thursday, November 6, 2025, at 10:00 am (Eastern Standard Time) to discuss the 3Q2025 financial results. To listen to the call, participants can access the webcast located in the Invest with Us section of the Company's website at www.geo-park.com, or by clicking below: https://events.q4inc.com/attendee/869247101 Interested parties may participate in the conference call by dialing the numbers provided below: United States Participants: +1 646-844-6383 Global Dial-In Numbers: https://www.netroadshow.com/events/global-numbers?confId=72342 Passcode: 039892 Please allow extra time prior to the call to visit the website and download any streaming media software that might be required to listen to the webcast. An archive of the webcast replay will be made available in the Invest with Us section of the Company's website at www.geo-park.com after the conclusion of the live call. GLOSSARY NOTICE Additional information about GeoPark can be found in the Invest with Us section of the website at www.geo-park.com. Rounding amounts and percentages: Certain amounts and percentages included in this press release and its supplementary information have been rounded for ease of presentation. Percentage figures included in this press release and its supplementary information have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. In addition, certain other amounts that appear in this press release and its supplementary information may not sum due to rounding. This press release and its supplementary information contain certain oil and gas metrics, including information per share, operating netback, reserve life index and others, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods. CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION This press release and its supplementary information contain statements that constitute forward-looking statements. Many of the forward-looking statements contained in this press release can be identified by the use of forward-looking words such as ``anticipate,'' ``believe,'' ``could,'' ``expect,'' ``should,'' ``plan,'' ``intend,'' ``will,'' ``estimate'' and ``potential,'' among others. Forward-looking statements that appear in a number of places in this press release include, but are not limited to, statements regarding the intent, belief or current expectations, regarding various matters, including full year guidance, five-year outlook target figures, hedging of expected production, full year net leverage figures, strategic initiatives, growth and capital allocation, drilling campaign, release of 2026 Work Program and Investment Guidelines. Forward-looking statements are based on management's beliefs and assumptions, and on information currently available to the management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors. Forward-looking statements speak only as of the date they are made, and the Company does not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances, or to reflect the occurrence of unanticipated events. For a discussion of the risks facing the Company which could affect whether these forward-looking statements are realized, see filings with the U.S. Securities and Exchange Commission (SEC). Oil and gas production figures included in this press release and its supplementary information are stated before the effect of royalties paid in kind, consumption and losses. Annual production per day is obtained by dividing total production by 365 days. Non-GAAP Measures: The Company believes Adjusted EBITDA, free cash flow and operating netback per boe, which are each non-GAAP measures, are useful because they allow the Company to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company's calculation of Adjusted EBITDA, free cash flow, and operating netback per boe may not be comparable to other similarly titled measures of other companies. Adjusted EBITDA: The Company defines Adjusted EBITDA as profit for the period before net finance costs, income tax, depreciation, amortization and certain non-cash items such as impairments and write-offs of unsuccessful exploration and evaluation assets, accrual of stock options and stock awards, unrealized results on commodity risk management contracts and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flow as determined by IFRS. The Company excludes the items listed above from profit for the period 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, profit for the period or cash flow from operating activities as determined in accordance with IFRS 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 and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit, see the accompanying financial tables and the supplementary information. Operating Netback per boe: Operating netback per boe should not be considered as an alternative to, or more meaningful than, profit for the period or cash flow from operating activities as determined in accordance with IFRS or as an indicator of the Company's operating performance or liquidity. Certain items excluded from operating netback per boe are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, none of which are components of operating netback per boe. The Company's calculation of operating netback per boe may not be comparable to other similarly titled measures of other companies. View source version on businesswire.com: https://www.businesswire.com/news/home/20251105372349/en/ back