Anaergia and Capwatt Sign Binding Letter of Intent for Nine New Biogas Plants in Europe
Anaergia Inc. ('Anaergia', the 'Company', 'us', or 'our') (TSX:ANRG) (OTCQX:ANRGF), through its subsidiary, Anaergia S.r.l., entered into a binding Letter of Intent ('LOI') with Capwatt Biomethane Unipessoal, Lda ('Capwatt'). Under the terms of this agreement, Anaergia is to design and build nine state-of-the-art facilities for biomethane production from agro-industry waste in Portugal, Spain, and Italy. Under the terms of this binding LOI, the projects are expected to be completed within the next 30 months and are expected to generate more than C$60 million in total revenue for Anaergia during this period.
Anaergia will oversee the design of each facility, ensuring the implementation of advanced processes. These plants will feature a range of Anaergia's proprietary systems, including anaerobic digesters, significantly enhancing Europe's green energy infrastructure and accelerating biomethane production.
'This agreement is to lead to the nine new facilities producing a total of 556,000 MWh per year of high-quality biomethane,' said Sérgio Rocha, CEO of Capwatt. 'It underscores Capwatt's commitment to leading the way in sustainable energy production and accelerating the energy transition.'
'This new agreement strengthens our ongoing relationship with Capwatt, building on previous collaborations where Anaergia's technical expertise and equipment were utilized at two biomethane facilities in Portugal and one in Italy,' said Assaf Onn, CEO of Anaergia. 'This substantial follow-up agreement showcases Capwatt's endorsement of Anaergia's capabilities and our proven abilities to deliver multiple projects simultaneously.'
About Capwatt
Capwatt, a multinational group specializing in sustainable energy solutions, has made biomethane a strategic priority in its drive to support decarbonization. With a portfolio of bioenergy projects at various stages of development, the company reaffirms its commitment to sustainable resource management and to advancing a low-carbon economy. Capwatt currently operates in Portugal, Spain, Italy, and Mexico.
For further information please see: https://www.capwatt.com/en
About Anaergia
Anaergia is a pioneering technology company in the renewable natural gas (RNG) sector, with over 250 patents dedicated to converting organic waste into sustainable solutions such as RNG, fertilizer, and water. We are committed to addressing a significant source of greenhouse gases (GHGs) through cost-effective processes. Our proprietary technologies, combined with our engineering expertise and vast experience in facility design, construction, and operation, position Anaergia as a leader in the RNG industry. With a proven track record of delivering hundreds of innovative projects over the past decade, we are well-equipped to tackle today's critical resource recovery challenges through diverse project delivery methods. As one of the few companies worldwide offering an integrated portfolio of end-to-end solutions, we effectively combine solid waste processing, wastewater treatment, organics recovery, high-efficiency anaerobic digestion, and biomethane production. Additionally, we operate RNG facilities owned by both third parties and Anaergia. This comprehensive approach not only reduces environmental impact but also significantly lowers costs associated with waste and wastewater treatment while mitigating GHG emissions.
For further information please see: www.anaergia.com
Forward-Looking Statements
This news release contains forward-looking information within the meaning of applicable securities legislation, which reflects Anaergia's current expectations regarding future events, including but not limited to,the timing and value of the contracts, funding, goals and benefits of the projects. Forward-looking information is based on a number of assumptions, including, but not limited to counterparty contractual performance, the full development and funding of the projects, the capability of the Company's technology with respect to the project objectives, the enforcement of organic waste recycling laws, and the actual diversion of food waste from regional landfills. The Company is subject to a number of risks and uncertainties, many of which are beyond the Company's control. Such risks and uncertainties include, but are not limited to, the factors discussed under 'Risk Factors' in the Company's annual information form for the fiscal year ended December 31, 2024 and under 'Risks and Uncertainties' in the Company's most recent management's discussion and analysis. Actual results could differ materially from those projected herein. Anaergia does not undertake any obligation to update such forward-looking information, whether as a result of new information, future events or otherwise, except as expressly required under applicable securities laws. Additional information on these and other factors that could affect Anaergia's operations or financial results are included in Anaergia's reports on file with Canadian regulatory authorities.
View source version on businesswire.com:https://www.businesswire.com/news/home/20250416557553/en/
For media and/or investor relations please contact:[email protected]
KEYWORD: CANADA NORTH AMERICA SPAIN ITALY PORTUGAL EUROPE
INDUSTRY KEYWORD: BIOTECHNOLOGY HEALTH OTHER ENERGY UTILITIES OIL/GAS ALTERNATIVE ENERGY ENERGY OTHER SCIENCE OTHER NATURAL RESOURCES ENVIRONMENT AGRICULTURE NATURAL RESOURCES SCIENCE GREEN TECHNOLOGY
SOURCE: Anaergia Inc.
Copyright Business Wire 2025.
PUB: 04/21/2025 05:20 AM/DISC: 04/21/2025 05:22 AM
http://www.businesswire.com/news/home/20250416557553/en
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Helix Reports Second Quarter 2025 Results
HOUSTON--(BUSINESS WIRE)--Helix Energy Solutions Group, Inc. ("Helix") (NYSE: HLX) reported a net loss of $2.6 million, or $(0.02) per diluted share, for the second quarter 2025 compared to net income of $3.1 million, or $0.02 per diluted share, for the first quarter 2025 and net income of $32.3 million, or $0.21 per diluted share, for the second quarter 2024. Helix reported Adjusted EBITDA 1 of $42.4 million for the second quarter 2025 compared to $52.0 million for the first quarter 2025 and $96.9 million for the second quarter 2024. For the six months ended June 30, 2025, Helix reported net income of $0.5 million, or $0.00 per diluted share, compared to net income of $6.0 million, or $0.04 per diluted share, for the six months ended June 30, 2024. Adjusted EBITDA for the six months ended June 30, 2025, was $94.4 million compared to $143.9 million for the six months ended June 30, 2024. The table below summarizes our results of operations: Owen Kratz, President and Chief Executive Officer of Helix, stated, 'Our second quarter results reflect marginal seasonal increases in activity levels in the North Sea and Gulf of America shelf as well as a full quarter of operations on the Q7000 in Brazil. The quarterly improvements were more than offset by the negative impacts of the planned regulatory docking of the Q5000 and the return transit of the Q4000 from its Nigeria project. The macro and geopolitical volatility experienced during the second quarter has created significant uncertainties in the market, with customers scaling back spending and pushing work into 2026 and beyond. While we expect significant improvements in our third quarter financial performance, with a lack of visibility in the fourth quarter as projects get pushed to the right, we have risk-assessed our 2025 outlook accordingly. Even with a challenging and disappointing backdrop, we have positioned Helix to generate meaningful free cash flow this year, and we continued to execute our share repurchase plan with 4.6 million shares repurchased during the second quarter. We are seeing some positive signs in the market, with work starting to be secured in the North Sea well intervention market for 2026, a multi-year MSA with Exxon for our Shallow Water segment and a multi-year 800-day minimum commitment trenching contract secured in the North Sea for our Robotics segment.' Segment Results Well Intervention Well Intervention revenues decreased $41.6 million, or 21%, during the second quarter 2025 compared to the prior quarter primarily due to lower utilization and lower integrated project revenues in the Gulf of America, offset in part by higher utilization on the Q7000 in Brazil and higher seasonal utilization in the North Sea during the second quarter 2025. Revenues on the U.S.-based vessels decreased during the second quarter 2025 as the Q4000 spent approximately 45 days transiting back to the Gulf of America and demobilizing after completing its Nigeria project in early April, and the Q5000 underwent an approximate 57-day planned regulatory docking. Revenues on the Q4000 also decreased during the second quarter due to lower integrated project revenues following the completion of the Nigeria project. Revenues on the Q7000 increased as the vessel had a full quarter under contract in Brazil during the second quarter compared to the prior quarter where the vessel had only six days of revenue following its regulatory docking and mobilization. Revenues also increased in the North Sea as expected with seasonally higher utilization during the second quarter on the Well Enhancer, although the Seawell remained warm-stacked throughout the quarter. Overall Well Intervention vessel utilization increased to 72% during the second quarter 2025 compared to 67% during the prior quarter. Compared to the prior quarter, utilization during the second quarter included a higher number of paid transit, mobilization and demobilization days for which revenues have either been deferred or have already been recognized. Well Intervention operating income decreased $36.4 million during the second quarter 2025 compared to the prior quarter. The decrease was due primarily to lower segment revenues and higher costs on the Q7000 with a full quarter of operations, offset in part by cost deferrals on the Q5000 during its planned regulatory docking during the second quarter 2025. Well Intervention revenues decreased $61.0 million, or 28%, during the second quarter 2025 compared to the second quarter 2024. 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During the second quarter 2025, we launched our third IROV boulder grab, and site clearance operations using our IROV boulder grabs generated 190 days of utilization compared to 21 days during the prior quarter. Robotics operating income increased $13.7 million during the second quarter 2025 compared to the prior quarter primarily due to higher revenues, offset in part by increased vessel charter costs, during the second quarter 2025. Robotics revenues increased $4.3 million, or 5%, during the second quarter 2025 compared to the second quarter 2024. The increase in revenues was primarily due to increased chartered vessel and site clearance activities, offset in part by a reduction in ROV and trencher utilization compared to the second quarter 2024. The second quarter 2025 included 537 chartered vessel days, which included 190 days of site clearance operations using three IROV boulder grabs, compared to 528 chartered vessel days, which included 78 days of site clearance operations using two IROV boulder grabs, during the second quarter 2024. The second quarter 2025 also included 91 days of trenching on a third-party vessel, whereas there was no trenching from a third-party vessel during the second quarter 2024. Offsetting the increases were reductions in integrated vessel trenching days and ROV utilization. Integrated vessel trenching decreased to 157 days during the second quarter 2025 compared to 232 days during the second quarter 2024, and ROV utilization decreased to 64% during the second quarter 2025 compared to 80% during the second quarter 2024. Robotics operating income decreased $9.4 million during the second quarter 2025 due to higher vessel costs and lower margins compared to the second quarter 2024. Shallow Water Abandonment Shallow Water Abandonment revenues increased $33.8 million, or 201%, during the second quarter 2025 compared to the prior quarter. The increase in revenues reflected seasonally higher activity levels and utilization across all asset classes during the second quarter 2025. Vessel utilization (excluding heavy lift) increased to 61% during the second quarter 2025 compared to 31% during the prior quarter. Plug and Abandonment ('P&A') and Coiled Tubing ('CT') systems activity increased to 798 days, or 34% utilization, during the second quarter 2025 compared to 264 days, or 11% utilization, during the prior quarter. The Epic Hedron heavy lift barge had 38% utilization during the second quarter 2025 compared to being idle during the prior quarter. Shallow Water Abandonment generated an operating loss of $0.4 million during the second quarter 2025, an improvement of $13.1 million compared to the prior quarter primarily due to higher seasonal revenues and related operating costs during the second quarter 2025. Shallow Water Abandonment revenues decreased $0.2 million during the second quarter 2025 compared to the second quarter 2024 primarily due to lower day rates on our vessels and P&A systems, lower heavy lift utilization and weaker contract performance during the second quarter 2025, almost entirely offset by higher system and vessel utilization (excluding heavy lift). The Epic Hedron heavy lift barge had 38% utilization during the second quarter 2025 compared 46% utilization during the second quarter 2024. Offsetting these decreases were higher utilization on P&A and CT systems, which increased to 798 days, or 34%, during the second quarter 2025 compared to 632 days, or 27%, during the second quarter 2024 and higher utilization on vessels (excluding heavy lift), which increased to 61% during the second quarter 2025 compared to 58% during the second quarter 2024. Shallow Water Abandonment operating losses increased $0.1 million in the second quarter 2025 primarily due to lower revenues compared to the second quarter 2024. Production Facilities Production Facilities revenues decreased $2.8 million, or 14%, during the second quarter 2025 compared to the prior quarter primarily due to lower oil and gas production and prices from the Droshky field. The Droshky field had a full quarter of production during the first quarter 2025 but was shut in for approximately one month during the second quarter 2025, and the Thunder Hawk field remained shut in during both quarters. 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Other Income and Expense Other income, net was $0.4 million during the second quarter 2025 compared to other expense, net of $0.4 million during the prior quarter and other expense, net of $0.4 million during the second quarter 2024. Other income and expense, net primarily includes net foreign currency gains and losses, respectively, related to the British pound on our U.K subsidiaries' foreign currency positions. Cash Flows Operating cash flows were $(17.1) million during the second quarter 2025 compared to $16.4 million during the prior quarter and $(12.2) million during the second quarter 2024. Second quarter 2025 operating cash flows decreased primarily due to lower earnings and higher working capital outflows compared to the prior quarter. Second quarter 2025 operating cash flows decreased compared to the second quarter 2024 primarily due to lower earnings and higher regulatory certification costs on our vessels and systems during the second quarter 2025, offset in part by the payment of $58.3 million related to the Alliance earn-out and by higher working capital outflows during the second quarter 2024. Regulatory certifications for our vessels and systems, which are included in operating cash flows, were $16.1 million during the second quarter 2025 compared to $17.9 million during the prior quarter and $10.7 million during the second quarter 2024. Capital expenditures, which are included in investing cash flows, totaled $4.5 million during the second quarter 2025 compared to $4.5 million during the prior quarter and $4.0 million during the second quarter 2024. Free Cash Flow was $(21.6) million during the second quarter 2025 compared to $12.0 million during the prior quarter and $(16.2) million during the second quarter 2024. The decrease in Free Cash Flow in the second quarter 2025 compared to the prior quarter and the second quarter 2024 was due primarily to lower operating cash flows during the second quarter 2025. (Free Cash Flow is a non-GAAP measure. See reconciliation below.) Financial Condition and Liquidity Cash and cash equivalents were $319.7 million at June 30, 2025. Available capacity under our ABL facility at June 30, 2025, was $70.5 million, and total liquidity was $374.9 million, excluding $15.3 million pledged toward our ABL facility. Consolidated long-term debt was $311.6 million at June 30, 2025, resulting in negative Net Debt of $8.1 million. (Net Debt is a non-GAAP measure. See reconciliation below.) Conference Call Information Further details are provided in the presentation for Helix's quarterly teleconference to review its second quarter 2025 results (see the Investor Relations page of Helix's website, The teleconference is scheduled for Thursday, July 24, 2025, at 9:00 a.m. Central Time. Investors and other interested parties wishing to participate in the teleconference should dial 1-800-715-9871 within the United States and 1-646-307-1963 outside the United States. The passcode is "Staffeldt." A live webcast of the teleconference will be available in a listen-only mode on the Investor Relations section of Helix's website. A replay of the webcast will be available on Helix's website shortly after the completion of the event. About Helix Helix Energy Solutions Group, Inc., headquartered in Houston, Texas, is an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention, robotics and decommissioning operations. Our services are key in supporting a global energy transition by maximizing production of existing oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments. For more information about Helix, please visit our website at Non-GAAP Financial Measures Management evaluates operating performance and financial condition using certain non-GAAP measures, primarily EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt. We define EBITDA as earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude gains or losses on disposition of assets, acquisition and integration costs, gains or losses related to convertible senior notes, the change in fair value of contingent consideration, and the general provision (release) for current expected credit losses, if any. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from asset sales and insurance recoveries (related to property and equipment), if any. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents and restricted cash. We use EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand and compare our results to other companies that have different financing, capital and tax structures. Other companies may calculate their measures of EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures. See reconciliation of the non-GAAP financial information presented in this press release to the most directly comparable financial information presented in accordance with GAAP. We have not provided reconciliations of forward-looking non-GAAP financial measures to comparable GAAP measures due to the challenges and impracticability with estimating some of the items without unreasonable effort, which amounts could be significant. Forward-Looking Statements This press release contains forward-looking statements that involve risks, uncertainties and assumptions that could cause our results to differ materially from those expressed or implied by such forward-looking statements. All statements, other than statements of historical fact, are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, including, without limitation, any statements regarding: our plans, strategies and objectives for future operations; any projections of financial items including projections as to guidance and other outlook information; future operations expenditures; our ability to enter into, renew and/or perform commercial contracts; the spot market; our current work continuing; visibility and future utilization; our protocols and plans; future economic or political conditions; energy transition or energy security; our spending and cost management efforts and our ability to manage changes; oil price volatility and its effects and results; our ability to identify, effect and integrate mergers, acquisitions, joint ventures or other transactions, including the integration of the Alliance acquisition and any subsequently identified legacy issues with respect thereto; developments; any financing transactions or arrangements or our ability to enter into such transactions or arrangements; our sustainability initiatives; our share repurchase program or execution; any statements of expectation or belief; and any statements of assumptions underlying any of the foregoing. Forward-looking statements are subject to a number of known and unknown risks, uncertainties and other factors that could cause results to differ materially from those in the forward-looking statements, including but not limited to market conditions and the demand for our services; volatility of oil and natural gas prices; complexities of global political and economic developments, including tariffs; results from mergers, acquisitions, joint ventures or similar transactions; results from acquired properties; our ability to secure and realize backlog; the performance of contracts by customers, suppliers and other counterparties; actions by governmental and regulatory authorities; operating hazards and delays, which include delays in delivery, chartering or customer acceptance of assets or terms of their acceptance; the effectiveness of our sustainability initiatives and disclosures; human capital management issues; geologic risks; and other risks described from time to time in our filings with the Securities and Exchange Commission ("SEC"), including our most recently filed Annual Report on Form 10-K, which are available free of charge on the SEC's website at We assume no obligation and do not intend to update these forward-looking statements, which speak only as of their respective dates, except as required by law. HELIX ENERGY SOLUTIONS GROUP, INC. Comparative Condensed Consolidated Statements of Cash Flows Six Months Ended (in thousands) 6/30/2025 6/30/2024 (unaudited) Cash flows from operating activities: Net income $ 474 $ 6,002 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 87,871 89,824 Deferred recertification and dry dock costs (33,931 ) (20,330 ) Payment of earnout consideration - (58,300 ) Losses related to convertible senior notes - 20,922 Working capital and other (55,105 ) 14,202 Net cash provided by (used in) operating activities (691 ) 52,320 Cash flows from investing activities: Capital expenditures (8,958 ) (7,594 ) Proceeds from insurance recoveries - 363 Net cash used in investing activities (8,958 ) (7,231 ) Cash flows from financing activities: Repayments of long-term debt (4,537 ) (65,042 ) Repurchases of common stock (30,214 ) (10,189 ) Payment of earnout consideration - (26,700 ) Other financing activities (6,029 ) 405 Net cash used in financing activities (40,780 ) (101,526 ) Effect of exchange rate changes on cash and cash equivalents 2,142 (688 ) Net decrease in cash and cash equivalents (48,287 ) (57,125 ) Cash and cash equivalents: Balance, beginning of year 368,030 332,191 Balance, end of period $ 319,743 $ 275,066 Reconciliation of Non-GAAP Measures Three Months Ended Six Months Ended (in thousands, unaudited) 6/30/2025 6/30/2024 3/31/2025 6/30/2025 6/30/2024 Reconciliation from Net Income (Loss) to Adjusted EBITDA: Net income (loss) $ (2,598 ) $ 32,289 $ 3,072 $ 474 $ 6,002 Adjustments: Income tax provision (benefit) (5,997 ) 14,725 453 (5,544 ) 13,027 Net interest expense 5,875 5,891 5,706 11,581 11,368 Other (income) expense, net (437 ) 382 357 (80 ) 2,598 Depreciation and amortization 45,389 43,471 42,482 87,871 89,824 EBITDA 42,232 96,758 52,070 94,302 122,819 Adjustments: Loss on disposition of assets, net - - - - 150 General provision for (release of) current expected credit losses 198 137 (85 ) 113 (6 ) Losses related to convertible senior notes - - - - 20,922 Adjusted EBITDA $ 42,430 $ 96,895 $ 51,985 $ 94,415 $ 143,885 Free Cash Flow: Cash flows from operating activities $ (17,133 ) $ (12,164 ) $ 16,442 $ (691 ) $ 52,320 Less: Capital expenditures, net of proceeds from asset sales and insurance recoveries (4,470 ) (3,989 ) (4,488 ) (8,958 ) (7,231 ) Free Cash Flow $ (21,603 ) $ (16,153 ) $ 11,954 $ (9,649 ) $ 45,089 Net Debt: Long-term debt including current maturities $ 311,612 $ 318,629 $ 311,109 $ 311,612 $ 318,629 Less: Cash and cash equivalents (319,743 ) (275,066 ) (369,987 ) (319,743 ) (275,066 ) Net Debt $ (8,131 ) $ 43,563 $ (58,878 ) $ (8,131 ) $ 43,563 Expand
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CALGARY, AB, July 23, 2025 /CNW/ - Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) is pleased to announce its operating and financial results for the three and six months ended June 30, 2025. Selected financial and operational information is outlined below and should be read in conjunction with the unaudited condensed interim financial statements and the related management's discussion and analysis ("MD&A"). These filings will be available at and the Company's website at Financial and Operating Highlights Three months ended June 30, PercentChange Six months ended June 30, PercentChange2025 2024 2025 2024 Financial (thousands of dollars except share data) Total sales, net of blending expense (1) (4) 138,808 157,057 (12) 301,996 284,423 6 Adjusted funds flow from operations (2) 74,218 88,023 (16) 166,577 164,469 1 Per share - basic 0.31 0.37 (16) 0.70 0.70 - - diluted 0.31 0.37 (16) 0.70 0.69 1 Cash flow provided by operating activities 68,673 90,402 (24) 138,608 145,449 (5) Per share - basic 0.29 0.38 (24) 0.58 0.62 (6) - diluted 0.29 0.38 (24) 0.58 0.61 (5) Net income 38,023 53,868 (29) 88,027 91,487 (4) Per share - basic 0.16 0.23 (30) 0.37 0.39 (5) - diluted 0.16 0.22 (27) 0.37 0.38 (3) Capital expenditures (1) 50,704 50,717 - 113,551 115,984 (2) Adjusted working capital (2)58,472 62,381 (6) Shareholders' equity735,055 658,448 12 Dividends declared 26,155 23,765 10 52,310 47,494 10 Per share 0.11 0.10 10 0.22 0.20 10 Weighted average shares (thousands) Basic 237,763 237,275 - 237,767 236,096 1 Diluted 239,471 239,452 - 239,469 238,026 1 Shares outstanding, end of period (thousands) Basic237,763 237,654 - Diluted (5)237,763 241,075 (1) Operating (6:1 boe conversion) Average daily production Heavy crude oil (bbls/d) 20,249 18,825 8 19,882 18,168 9 Natural gas (mmcf/d) 10.8 5.5 96 12.6 8.5 48 Natural gas liquids (bbl/d) 185 67 176 164 77 113 Barrels of oil equivalent (9) (boe/d) 22,235 19,805 12 22,151 19,661 13Average daily sales (6) (boe/d) 22,123 19,754 12 22,071 19,607 13Netbacks ($/boe) (7) Operating Sales, net of blending (4) 68.95 87.37 (21) 75.61 79.70 (5) Royalties (12.84) (16.49) (22) (13.65) (14.43) (5) Transportation (5.65) (5.54) 2 (5.53) (5.44) 2 Production (7.44) (7.24) 3 (7.68) (7.14) 8 Operating netback (3) 43.02 58.10 (26) 48.75 52.69 (7) Realized gains (losses) on financial derivatives (0.36) (0.44) (18) (0.97) 1.49 (165) Operating netback, including financial derivatives (3) 42.66 57.66 (26) 47.78 54.18 (12) General and administrative expense (1.44) (1.50) (4) (1.44) (1.49) (3) Interest income and other expense (8) 0.45 0.81 (44) 0.51 0.89 (43) Current income tax expense (4.81) (8.01) (40) (5.12) (7.46) (31) Settlement of decommissioning liability - - - (0.03) (0.03) - Adjusted funds flow netback (3) 36.86 48.96 (25) 41.70 46.09 (10) (1) Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. (2) Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. (3) Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release. (4) Heavy oil sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the interim financial statements blending expense is recorded within blending and transportation expense. (5) Performance share units and restricted share units are cash settled. (6) Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. The Company's heavy crude oil sales volumes and production volumes differ due to changes in inventory. (7) Netbacks are calculated using average sales volumes. For the three months ended June 30, 2025, sales volumes comprised of 20,136 bbs/d of heavy oil, 10.8 mmcf/d of natural gas and 185 bbls/d of natural gas liquids (three months ended June 30, 2024 – 18,774 bbls/d heavy oil, 5.5 mmcf/d natural gas and 67 bbls/d natural gas liquids). For the six months ended June 30, 2025, sales volumes comprised of 19,802 bbls/d of heavy oil, 12.6 mmcf/d of natural gas and 164 bbls/d of natural gas liquids (six months ended June 30, 2024 – 18,114 bbls/d heavy oil, 8.5 mmcf/d natural gas and 77 bbls/d natural gas liquids). (8) Excludes unrealized foreign exchange gains/losses, accretion on decommissioning liabilities, interest on lease liability and interest on repayable contribution. (9) See '"Barrels of Oil and Cubic Feet of Natural Gas Equivalent." SECOND QUARTER 2025 HIGHLIGHTS Achieved record production of 22,235 boe/d representing an increase of 12% from the second quarter of 2024. Realized adjusted funds flow from operations (1) of $74.2 million ($0.31 per share basic (2)), cash flows from operations of $68.7 million ($0.29 per share basic) and free cash flow (3) of $23.5 million. Achieved an operating netback, including financial derivatives (2) of $42.66/boe and an adjusted funds flow netback (2) of $36.86/boe. Achieved net income of $38.0 million ($0.16 per share basic) equating to $18.89/boe. Exceptional results from our exploration program with new pool discoveries in the Grand Rapids formation in West Marten Hills and the Wabiskaw formation in Greater Pelican. Executed a $50.7 million capital expenditure (3) program inclusive of development, exploration and secondary recovery implementation. Declared a cash dividend of $26.2 million, or $0.11 per common share. To date, Headwater has paid out a cumulative dividend of $265.2 million to shareholders ($1.12 per common share). As at June 30, 2025, Headwater had adjusted working capital (1) of $58.5 million, working capital of $64.8 million, and no outstanding bank debt. (1) Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. (2) Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release. (3) Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. OPERATIONS UPDATE New Pool Discoveries Grand Rapids Formation in Marten Hills West The Company is excited to report a new pool discovery in the Grand Rapids formation within the heart of Marten Hills West. Our discovery well 07/04-18-075-01W5, a 6-leg multi-lateral well achieved a 60-day initial production rate of 345 bbls/d of 19.5 API oil. The well continues to produce at rates in excess of 300 bbls/d and is on track to achieve its first payout by the end of August. This exceptional result has setup further drilling on a pool estimated to be approximately 15 sections in size. In addition, the oil quality and reservoir characteristics of this zone are highly favorable for secondary recovery development. Headwater will follow up this discovery well with 3 - 4 additional wells and 2 secondary recovery pilots in the second half of 2025. Wabiskaw Formation in Greater Pelican The Greater Pelican discovery well, an 8-leg multi-lateral drilled at 04/04-19-079-22W4 in the Wabiskaw formation was brought on production late April and has achieved a 90-day initial production rate of 475 bbls/d of 16.5 API oil. Inflow remains strong with current producing rates in excess of 500 bbls/d. The oil quality and exceptional inflow characteristics have greatly exceeded our expectations, and we are excited to continue delineation drilling and evaluation of secondary recovery implementation. During the balance of 2025 we intend to drill two follow up delineation wells in addition to procuring equipment to implement a polymer flood pilot in early 2026. Marten Hills West Development Headwater's other second quarter activity was focused in Marten Hills West with continued drilling along the southeastern edges of the Clearwater sandstone, further step out drilling on the Clearwater E formation, in addition to further implementation of secondary recovery across both formations. Throughout the second quarter, Headwater continued to delineate the southeastern edges of the Clearwater sandstone with exceptional results. Seven wells were drilled and placed on production providing average 30-day initial production rates exceeding 225 bbls/d. Results from the seven wells have expanded the southeastern Clearwater sandstone pool boundaries and provided confirmation that the southeastern area is ideal for implementation of secondary recovery. To date, in the Clearwater sandstone we have implemented secondary recovery across two sections with stabilized oil volumes from the initial secondary recovery efforts now exceeding 1,100 bbls/d. We have recently commissioned a third full section and by year end, plan to have a total of 5 sections under secondary recovery. With the planned development, Headwater anticipates having approximately 2,500 bbls/d of oil production in the Clearwater sandstone supported by year-end. As we look to 2026 and beyond, Headwater will continue secondary recovery development in the Clearwater sandstone. It is currently estimated that an additional 25-30 sections in the Clearwater sandstone are amenable to secondary recovery. Pool boundary expansion of the Clearwater E was a focus in the second quarter with step out tests to the northwest at 00/15-23-075-02W5 and 06/16-27-075-02W5. The 00/15-23-075-02W5 well achieved a 60-day initial production rate of 184 bbls/d of 23.5 API oil and the 06/16-27-075-02W5 achieved a 30-day initial production rate of 99 bbls/d of 22.5 API oil. During the balance of 2025 Headwater has eight additional wells planned for drilling in the Clearwater E formation including three step out tests on our most northern acreage in Marten Hills West. We recently commissioned our first full section of Clearwater E secondary recovery with encouraging initial results and have plans to commission a second section of secondary recovery prior to year end. Our two original injection pilots have now been on injection for 10 months, with oil rates from these pilots stabilized at approximately 300 bbls/d for 5 months. To date we have identified 15-20 sections of Clearwater E that are amenable to secondary recovery with full scale implementation to continue in 2026 and beyond. By year end 2025 it is anticipated that approximately 25% of Marten Hills West oil volumes and 50% of Headwater's corporate oil production will be supported by secondary recovery. Marten Hills Core The core area remains our flagship commercial secondary recovery asset demonstrating the value proposition of lower declines and increasing recovery factors. Production has been flat at approximately 7,000 bbls/d for more than 18 months, which has reduced our corporate decline rate by more than 5%. Handel Saskatchewan Headwater recently started drilling our 5 well stratigraphic exploration program. The exploration program is designed to evaluate numerous conventional Mannville heavy oil prospects in addition to zones prospective for steam assisted gravity drainage. THIRD QUARTER DIVIDEND The Board of Directors of Headwater has declared a quarterly cash dividend to shareholders of $0.11 per common share payable on October 15, 2025, to shareholders of record at the close of business on September 29, 2025. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada). AUTOMATIC SHARE PURCHASE PLAN In connection with the previously announced normal course issuer bid ("NCIB"), the Company has established an automatic securities purchase plan with a designated broker whereby the Company's common shares may be repurchased at times when such purchases would otherwise be prohibited pursuant to regulatory restrictions or self-imposed blackout periods. Under the automatic securities purchase plan and before entering into a self-imposed blackout period, the Company may, but is not required to, request that the designated broker make purchases under the NCIB. Such purchases will be made at the discretion of the designated broker, within parameters established by the Company prior to the blackout periods. Outside of the blackout periods, purchases are made at the discretion of the Company's management. The automatic securities purchase plan constitutes an "automatic plan" for purposes of applicable Canadian securities legislation and has been accepted by the Toronto Stock Exchange. BOARD OF DIRECTORS Headwater would like to welcome Cheree Stephenson and Karen Nielsen as new members of Headwater's Board of Directors. Ms. Stephenson was elected at Headwater's annual meeting of shareholders held on May 8, 2025. Cheree is currently Vice President Finance & Chief Financial Officer at Topaz Energy Corp. Ms. Nielsen was appointed to Headwater's Board of Directors effective today. Karen was previously the Executive Vice President and Chief Commercial Officer at ATCO EnPower. OUTLOOK Positive working capital in conjunction with a highly flexible capital budget allows timely capital allocation adjustments to appropriately align with market conditions. Headwater remains focused on maximizing total shareholder returns through organic expansion, enhanced oil recovery, dividends and strategic buy backs under its ongoing normal course issuer bid. Additional corporate information can be found in the Company's corporate presentation and on Headwater's website at FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words "guidance", "initial, "anticipate", "scheduled", "can", "will", "prior to", "estimate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation: that the Marten Hills West discovery well will achieve its first payout and the timing thereof; the estimated size of certain of the Company's pools; the expectation to follow up the Grand Rapids discovery well with 3 - 4 additional wells and 2 secondary recovery pilots in the second half of 2025; the expectation to drill two follow up delineation wells in Greater Pelican in addition to procuring equipment to implement a polymer flood pilot in early 2026; that Headwater anticipates having a total of 5 sections under secondary recovery and approximately 2,500 bbls/d of oil production in the Clearwater sandstone supported by year-end and expectations and timing of further secondary recovery plans; the expectation to drill eight wells in the Clearwater E formation; the planned implementation of a second section of secondary recovery in the Clearwater E formation before year end and full scale implementation to occur in 2026 and beyond; the expectation that by year end 2025 it is anticipated that approximately 25% of Marten Hills West oil volumes and 50% of Headwater's corporate oil production will be supported by secondary recovery; well results in Handel; and the anticipated terms of the Company's quarterly dividend, including its expectation that it will be designated as an "eligible dividend". The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, receipt of required regulatory approvals, the success of future drilling, development and secondary recovery activities, the performance of existing wells, the performance of new wells, Headwater's growth strategy, general economic conditions, availability of required equipment and services, prevailing equipment and services costs, prevailing commodity prices. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; risks associated with wildfires in areas in which the Company operates including safety of personnel, asset integrity and potential disruption of operations which could affect the Company's results, business, financial conditions or liquidity; the impact of tariffs and other trade retaliatory measure imposed by the United States, Canada and other countries; disruptions to the Canadian and global economy resulting from major public health events, the Russian-Ukrainian war and the conflict in the Middle-East and the impact on the global economy and commodity prices; the impacts of inflation and supply chain issues and steps taken by central banks to curb inflation; pandemics, war, terrorist events, political upheavals and other similar events; events impacting the supply and demand for oil and gas including actions taken by the OPEC + group; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks); commodity price and exchange rate fluctuations; changes in legislation affecting the oil and gas industry; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures and the risk that the Company's pools may be smaller than anticipated. Refer to Headwater's most recent Annual Information Form dated March 13, 2025, on SEDAR+ at and the risk factors contained therein. DIVIDEND POLICY: The amount of future cash dividends paid by the Company, if any, will be subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, adjusted funds flow from operations, fluctuations in commodity prices, production levels, capital expenditure requirements, acquisitions, debt service requirements and debt levels, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the Board will adjust the Company's dividend policy from time to time and, as a result, future cash dividends could be reduced or suspended entirely. BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The term "boe" (or barrels of oil equivalent) and "Mcf" (or thousand cubic feet of natural gas equivalent) may be misleading, particularly if used in isolation. A boe and Mcf conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value. INITIAL PRODUCTION RATES: References in this press release to initial production ("IP") rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary. NON-GAAP AND OTHER FINANCIAL MEASURES:In this press release, we use various non-GAAP and other financial measures to analyze operating performance and financial position. These non-GAAP and other financial measures do not have standardized meanings prescribed under IFRS and therefore may not be comparable to similar measures presented by other issuers. The term cash flow in this press release is equivalent to adjusted funds flow from operations. Non-GAAP Financial Measures Free cash flow Management utilizes free cash flow to assess the amount of funds available for future capital allocation decisions. It is calculated as adjusted funds flow from operations net of capital expenditures. Three months ended June 30, Six months ended June 30,2025 2024 2025 2024(thousands of dollars) (thousands of dollars) Adjusted funds flow from operations 74,218 88,023 166,577 164,469 Capital expenditures (50,704) (50,717) (113,551) (115,984) Free cash flow 23,514 37,306 53,026 48,485 Total sales, net of blending expense Management utilizes total sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the interim financial statements blending expense is recorded within blending and transportation expense. Three months ended June 30, Six months ended June 30,2025 2024 2025 2024(thousands of dollars) (thousands of dollars) Total sales 144,944 164,281 315,099 298,315 Blending expense (6,136) (7,224) (13,103) (13,892) Total sales, net of blending expense 138,808 157,057 301,996 284,423 Capital expenditures Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company's interim financial statements. Three months ended June 30, Six months ended June 30,2025 2024 2025 2024(thousands of dollars) (thousands of dollars) Cash flows used in investing activities 40,781 66,204 103,884 117,784 Proceeds from government grant - 177 - 354 Change in non-cash working capital 9,923 (15,664) 9,667 (2,154) Capital expenditures 50,704 50,717 113,551 115,984 Capital Management Measures Adjusted Funds Flow from Operations Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. In addition to being a capital management measure, adjusted funds flow from operations is used by management to assess the performance of the Company's oil and gas properties. Adjusted funds flow from operations is an indicator of operating performance as it varies in response to production levels and management of production and transportation costs. Management believes that by eliminating changes in non-cash working capital and restricted cash and adjusting for current income taxes in the period, adjusted funds flow from operations is a useful measure of operating performance. Three months ended June 30, Six months ended June 30,2025 2024 2025 2024(thousands of dollars) (thousands of dollars) Cash flows provided by operating activities 68,673 90,402 138,608 145,449 Changes in non–cash working capital 4,122 1,786 11,010 (6,414) Current income taxes (9,683) (14,392) (20,453) (26,625) Current income taxes paid 9,106 10,227 35,412 39,231 Change in restricted cash 2,000 - 2,000 - Adjusted funds flow from operations 74,218 88,023 166,577 164,469 Adjusted Working Capital Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity. Financial derivative receivable/liability have been excluded as these contracts are subject to a high degree of volatility prior to settlement and relate to future production periods. Financial derivative receivable/liability are included in adjusted funds flow from operations when the contracts are ultimately realized. Management has included the effects of the repayable contribution to provide a better indication of Headwater's net financing obligations. As at June 30, 2025 As at December 31, 2024(thousands of dollars) Working capital 64,836 78,735 Repayable contribution (6,937) (10,916) Financial derivative receivable (975) (3,088) Financial derivative liability 1,548 2,847 Adjusted working capital 58,472 67,578 Non-GAAP Ratios Adjusted funds flow netback, operating netback and operating netback, including financial derivatives Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period. Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. Sales volumes exclude the impact of purchased condensate and butane. Operating netback, including financial derivatives is defined as operating netback plus realized gains (losses) on financial derivatives. Adjusted funds flow from operations per share Adjusted funds flow from operations per share is a non-GAAP ratio and is used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding on a basic or diluted basis. Supplementary Financial Measures Per boe numbers This press release represents various results on a per boe basis including Headwater's net of blending expense, realized gains (losses) on financial derivatives per boe, general and administrative expenses per boe, interest income and other expense per boe, current income tax expense per boe and settlement of decommissioning liability expense per boe. These figures are calculated using sales volumes. 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U-Haul Closes Repair Shop in San Bernardino After 54 Years
SAN BERNARDINO, Calif., July 23, 2025--(BUSINESS WIRE)--The U-Haul® repair shop at 891 S. Arrowhead Ave. has closed after servicing regional moving equipment since 1971. Repair operations and routine maintenance at the facility ceased in late June. As a result of the repair shop closing, 37 Team Members were let go. U-Haul will maintain ownership of its S. Arrowhead property, which houses the U-Haul Company of San Bernardino regional offices. The repair shop will be repurposed as U-Box® of San Bernardino, a 30,000-square-foot warehouse that can store up to 2,500 of the Company's popular portable moving containers. U-Haul rental equipment in the region will soon be serviced at 1235 E. Baseline St. in San Bernardino, site of a new repair shop that is set to begin operations on July 28. Local U-Haul Companies are always exploring opportunities for growth as they pursue means to better serve the needs of customers, but sometimes find it necessary to close or relocate stores, shops, offices and services. Reasons for closures can include: long-term strategic plans; safety and security concerns; physical site conditions and limitations; shifts in demographics; availability of local Team Members; trends in migration; expansion of the U-Haul neighborhood dealer network; proximity to other new or existing Company locations; and external factors. About U-HAUL Celebrating our 80th anniversary in 2025, U-Haul is the No. 1 choice of do-it-yourself movers with more than 24,000 rental locations across all 50 states and 10 Canadian provinces. The U-Haul app makes it easy for customers to use U-Haul Truck Share 24/7 to access trucks anytime through the self-dispatch and -return options on their smartphones with our patented Live Verify technology. Our customers' patronage has enabled the U-Haul fleet to grow to 193,900 trucks, 138,200 trailers and 40,300 towing devices. U-Haul is the third largest self-storage operator in North America and offers 1,060,000 rentable storage units and 92.0 million square feet of self-storage space at owned and managed facilities. U-Haul is the top retailer of propane in the U.S. and the largest installer of permanent trailer hitches in the automotive aftermarket industry. Get the U-Haul app from the App Store or Google Play. View source version on Contacts Sydney EllisJeff LockridgeE-mail: publicrelations@ Phone: 602-263-6981Website: Error in retrieving data Sign in to access your portfolio Error in retrieving data Error in retrieving data Error in retrieving data Error in retrieving data
