Company Announcements

CALGARY, AB , Dec. 3, 2025 /CNW/ - Tamarack Valley Energy Ltd. is pleased to announce its 2026 budget and guidance for the upcoming year in respect of the ongoing development of the Company's Clearwater and Charlie Lake assets.

Tamarack has designed a scaled 2026 capital investment program of $390 to $410 million to maximize total return while maintaining flexibility in the prevailing commodity price cycle. This moderated capital program is projected to generate year-over-year production growth of ~3% primarily reflecting the impact of development activities in 2026 and ongoing waterflood investments in 2024 and 2025. At a budget price of US$60 per barrel WTI, Tamarack expects to generate significant free funds flow⁽¹⁾ and deliver strong returns to shareholders through sustainable base dividends, share buybacks and net debt⁽¹⁾ reduction.

Tamarack is projecting a sustaining free funds flow breakeven cost⁽¹⁾ of ~US$35 per barrel WTI (<US$40 per barrel WTI, unhedged), as the Company continues to drive higher margins in the business through improved capital efficiencies, higher price realizations, lower costs and portfolio optimization. Tamarack's corporate production decline rate⁽²⁾ is anticipated to be 22% for the full year, with ongoing success from primary development and secondary waterflood expansion in the Clearwater continuing to exceed expectations driving higher production growth and lower declines. Together, the low breakeven oil price and declining reinvestment rates have provided Tamarack with greater resiliency in a lower commodity price environment.

Budget & Guidance Update

Approximately 70% of the Company's 2026 capital investment program is dedicated to the Clearwater for ongoing primary development and waterflood expansion. Development activities include the drilling of >75 Clearwater primary development wells, an ~18% decline from 2025, and the implementation of >65 new injection wells (including 25 conversions) across the Nipisi, West Marten, Marten Hills and South Clearwater areas. Waterflood investments are forecasted to be $100 million, which represents double that of 2025 in response to the ongoing success of the program. Clearwater injection rates are expected to grow by 70% to 60,000 bbl per day (exit to exit injection rates) and with greater than 35% of Clearwater oil production under waterflood by the end of 2026. Tamarack expects that expanded waterfloods investments will further accelerate decline mitigation and lower future reinvestment ratios longer term, which will enable the Company to offer more torque to growth at higher commodity price cycles.

Tamarack is allocating 20% of the capital investment budget for ongoing development of Charlie Lake with plans to maintain a flat exit rate production profile, utilizing a one-rig program to drill 10 wells at Pipestone and Wembley. Tamarack's scalable Charlie Lake asset continues to attract capital with top-tier light oil inventory characterized by quick cycle times, low breakeven costs and first payouts within one year.

Tamarack's de-risk and exploration budget includes opportunities in the greater Clearwater fairway and Pelican Area. Tamarack recently increased its land position in the Pelican area to 31.25 net sections. Industry activity at Pelican has been promising with two operators implementing polymer-enhanced recovery schemes offsetting Tamarack's lands in the Wabiskaw oil formation, and a third operator in the area demonstrating early success in the Clearwater. Tamarack plans to drill both the Wabiskaw and Clearwater oil zones at Pelican in 2026.

Tamarack estimates 2026 sustaining capital⁽¹⁾ to be $265 million, reflecting a 16% reduction in sustaining capital requirements compared to the prior year. Strong reservoir response and decline mitigation from the waterflood expansion, combined with ongoing capital efficiencies from multi-well-pad development, level-loaded drilling schedules and solid run times, have lowered the sustaining capital and reinvestment requirements for the Company to maintain corporate production levels.  

The Company's capital investment program is expected to deliver year-over-year production growth of ~3%, which equates to ~9% when adjusted for non-core asset divestitures in 2025. This growth primarily reflects the impact of development activities in 2026 and ongoing waterflood investments in 2024 and 2025. Tamarack is targeting lower production growth in 2026 in response to the weaker WTI price outlook for the full year. Tamarack remains nimble and may scale the 2026 capital program in either direction if prices materially fluctuate during the year.

Net production expenses⁽¹⁾ in 2026 are anticipated to decline by 6% compared to the prior year, primarily due to non-core property dispositions in 2025, which carried higher per barrel costs relative to Tamarack's corporate averages on retained assets. The Company also continues to drive lower per barrel costs through field infrastructure investments, lower water handling and trucking costs from waterflood reinjection, carbon abatement initiatives, higher production and reduced workover costs.

Five-year Plan Update & Additional Shareholder Returns

Tamarack's recently updated five-year plan reflects the ongoing improvements in the profitability of the business through a combination of a lower cost structure, lower corporate decline rates, lower reinvestment requirements and lower corporate breakeven oil prices leading to higher free cash flow⁽¹⁾ generation. Together with lower debt and a laddered debt maturity, Tamarack is uniquely positioned to generate sustainable total returns to shareholders through a combination of growth, debt reduction, share buybacks and the base dividend.

With the improvements demonstrated in the updated long-range plan, the Company has achieved its net debt target of 1X Net Debt to Adjusted EBITDA⁽¹⁾ at US$50 per bbl WTI and is allocating additional free funds flow to share buybacks in 2026. Tamarack seeks to maximize per share returns and value to shareholders across commodity price cycles. Refer to the investor presentation on Tamarack's website for additional information regarding the Company's updated five-year plan and accelerated shareholder returns.

Board of Directors Update

Tamarack is pleased to announce the Board appointment of Mr. Craig Bryksa to the Company's Board of Directors, effective December 2, 2025. Mr. Bryksa most recently served as President and Chief Executive Officer of Veren Inc. until its combination with Whitecap Resources Inc. in May 2025. Prior to this role, he held various senior management positions within the organization, including Vice President, Engineering West, after joining the company in 2006. His industry experience as a professional engineer also includes roles with Enerplus Resources Fund and McDaniel & Associates Consultants. He currently serves on the Board of Directors of Whitecap Resources Inc.

About Tamarack Valley Energy Ltd.

Tamarack is a corporation engaged in the exploration, development, production and sale of oil and natural gas in the Western Canadian Sedimentary Basin. The Company is currently developing two projects in Northern Alberta – a Clearwater heavy oil position at Nipisi, Marten Hills and South Clearwater and a Charlie Lake light oil position at Valhalla, Wembley and Pipestone. Tamarack holds an extensive inventory of low-risk, oil development drilling locations and is pursuing enhanced oil recovery upside across the Company's core asset areas. Tamarack is committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company is publicly traded on the Toronto Stock Exchange under the symbol "TVE". For more information, visit www.tamarackvalley.ca.

Reader Advisories

Selected financial and operating information should be read with Tamarack's unaudited consolidated financial statements and related management's discussion and analysis for the three and nine months ended September 30, 2025, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca

Disclosure of Oil and Gas Information

For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with Canadian Securities Administrators' National Instrument 51 101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Boe may be misleading, particularly if used in isolation.

Oil and Gas Metrics

This news release contains metrics commonly used in the oil and natural gas industry, such as corporate decline rate. "Corporate decline rate" represents the percentage decline of the Company's production base, excluding the production from new wells drilled in the year. Corporate decline rate is not a financial measure and does not have a standardized meaning under NI 51-101. This term has been calculated by management and does not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. Management uses this oil and gas metric for its own performance measurements and to provide shareholders with a measure to compare Tamarack's operations over time. Readers are cautioned that the information provided by these metrics should not be relied upon for investment or other purposes.

Product Types

References in this news release to "crude oil" or "oil" refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to "NGL" throughout this news release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51-101. References to "natural gas" throughout this news release refers to conventional natural gas as defined by NI 51-101. Corporate guidance of 69,000 – 71,000 boe/d: 47,020 – 48,380 bbl/d heavy oil, 9,070 – 9,330 bbl/d light/med. oil, 2,560 – 2,640 bbl/d NGL and 62,100 – 63,900 mcf/d natural gas.

Forward Looking Information

This news release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "budget", "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words (including negatives or grammatical variations) suggesting future outcomes. More particularly, this news release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; the Company's exploration and development plans and strategies; generating significant free funds flow at a budgeted price of US$60 per bbl WTI, allowing the Company to continue delivering strong returns for investors through sustainable dividends, share buybacks and net debt reduction; expectations that sustaining free funds flow breakeven cost will be US$35 per barrel WTI in 2026 (<US$40 per barrel WTI, unhedged) as the Company continues to drive higher margins in the business through improved capital efficiencies, higher price realizations; corporate production decline rates of 22% in 2026; together, the low breakeven oil price and declining reinvestment rates have provided Tamarack with greater resiliency in a lower commodity price environment; projections that year-over-year production growth will be approximately 3%; excluding the impact of lower production from non-core asset divestitures in 2025, year-over production growth is expected to be 9%; 2026 budget and guidance expectations, including capital investments of $390 - 410 million and the allocation thereof, annual average production of 69,000 – 71,000 boe/day, average oil and natural gas weightings of 84 – 86%, royalty rates of 19 – 21%, corporate wellhead price differentials – oil of $1.00 – 1.50 per boe, net production expenses of $6.85 – 7.15 per boe, transportation expenses of $4.00 – 4.50 per boe, general and administrative expenses of $1.30 – 1.45 per boe, interest expense of $2.70 – 3.10 per boe and income taxes as a % of adjusted funds flow before tax of 10 – 12%; plans to ramp up Clearwater injection rates by 70% to 60,000 bbl per day in 2026 and expectations that greater than 35% of Clearwater oil production to be under waterflood by the end of the year; development activities in 2026, including over >75 wells (18% decline over 2025) and associated development costs (including plans to begin developing both the Wabiskaw and Clearwater oil zones at Pelican in 2026); the implementation of >65 new waterflood injection wells (including 25 conversions) across the Nipisi, West Marten, Marten Hills and South Clearwater areas; plans to maintain a flat exit rate production profile in the Charlie Lake; Tamarack's scalable Charlie Lake asset continues to attract capital with top-tier light oil inventory characterized by quick cycle times, low breakeven costs and first payouts within one year; Tamarack's de-risk/exploration budget; expectations that net production expenses in 2026 are anticipated to decline by up to 6% compared to 2025; expectations that the Company continues to drive lower per barrel costs through field infrastructure investments, lower water handling and trucking costs from waterflood reinjection, carbon abatement initiatives, higher production and reduced workover costs; the Company remaining nimble and able to scale the 2026 capital program in either direction if commodity prices materially fluctuate during the year; lower sustaining capital requirements for the Company to maintain corporate production levels, including $265 million of sustaining capital in 2026; Tamarack's recently updated five-year plan reflects the ongoing improvements in the profitability of the business through a combination of a lower cost structure, lower corporate decline rates, lower reinvestment requirements and lower corporate breakeven oil prices leading to higher free cash flow generation; together with lower debt and a laddered debt maturity, Tamarack is uniquely positioned to generate sustainable total returns to shareholders through a combination of growth, debt reduction, share buybacks and the base dividend; with the improvements demonstrated in the updated long range plan, the Company has achieved its net debt target of 1X Net Debt to Adjusted EBITDA at US$50 per bbl WTI and is allocating additional free funds flow to share buybacks in 2026; Tamarack seeks to maximize per share returns and value to shareholders across commodity price cycles; future primary development and secondary waterflood expansion and enhanced oil recovery in the Clearwater continuing to exceed expectations and driving higher production growth, lower corporate decline rates and lower future reinvestment ratios longer term; the performance characteristics of the Company's oil and natural gas properties; and the source of funding for the Company's activities. In addition, statements related to "recovery" are deemed to be forward-looking information as they involve the implied assessment, based on certain estimates, that the resources can be discovered and profitably produced in the future.

Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the Company's return of capital framework and the funds available for such activities from time to time is dependent upon, among other things, free funds flow financial requirements for the Company's operations and the execution of its strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tamarack to pay dividends and buyback shares will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.

The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack; execution of the Company's 2026 budget; actual fourth quarter 2025 results and exit values; the timing of and success of future drilling, conversion, development and completion activities; the geological characteristics of Tamarack's properties; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products; the realization of anticipated benefits of the Company's infrastructure, waterflood development program and recent acquisitions and divestitures; the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the performance of new and existing wells; the application of existing drilling and fracturing techniques; the Company's ability to secure sufficient amounts of water; prevailing weather and break-up conditions; royalty regimes and exchange rates; impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack's ability to execute its plans and strategies.

Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production; the risk that future dividend payments thereunder are reduced, suspended or cancelled; incorrect assessments of the value of benefits to be obtained from exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); the risk that (i) the U.S. and Canadian governments maintain tariffs, increase the rate or scope of tariffs, or impose new tariffs on the import of goods from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company; commodity prices, including the impact of the actions of OPEC and OPEC+ members; risks relating to reliance on third parties, including in respect of the Company's use of third-party infrastructure at Charlie Lake; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; health, safety, litigation and environmental risks; access to capital; and pandemics. In addition, ongoing military actions in the Middle East and between Russia and Ukraine have the potential to threaten the supply of oil and gas from those regions. The long-term impacts of the actions between these nations remains uncertain. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the most recent annual information form and management's discussion and analysis of the Company, for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca. The forward-looking statements contained in this news release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included statements, except as required by law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

This news release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about generating sustainable long-term growth in free funds flow, dividends, share buybacks and debt reduction, the 2026 capital budget of $390 - 410 million, guidance and budget pricing and allocation, including prospective results of operations, production (including annual average production of 69,000 – 71,000 boe/day, average oil and natural gas weightings of 84 – 86% and production growth of 3%) and free funds flow, operating costs (including net production expenses in 2026 declining by up to 6% compared to 2025), balance sheet strength, and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this document was approved by management as of the date of this document and was provided for the purpose of providing further information about Tamarack's future business operations. Tamarack and its management believe that FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. Changes in commodity prices, differences in the timing and allocation of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Tamarack's guidance. Actual results may differ materially from these estimates.

Specified Financial Measures

This news release includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios, capital management measures and supplemental financial measures as further described herein. These measures do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and, therefore, may not be comparable with the calculation of similar measures by other companies.

Net Production Expenses (Non-IFRS Financial Measures, and Non-IFRS Financial Ratio if calculated on a per boe basis) is calculated as production expenses less processing income. Tamarack generates processing income from third parties that utilize excess capacity at Tamarack's facilities. If Tamarack has excess capacity at one of its facilities, the Company will seek to process third-party volumes as a means of offsetting a portion of the facility costs. Accordingly, net production expenses allow Tamarack and others to assess the profitability of field operating results by including the associated income generated from plant operations.

Adjusted funds flow (capital management measure) is defined as cash provided by operating activities excluding asset retirement obligation expenditures, transaction costs and changes in non-cash working capital. Asset retirement obligation expenditures and transactions costs from business combinations both result from the Company's capital budgeting and strategic planning processes, which first considers available adjusted funds flow. Asset retirement obligation expenditures vary from period to period depending on capital programs, government regulations and the maturity of the Company's operating areas. By also excluding changes in non-cash working capital from cash provided by operating activities, the adjusted funds flow measure provides a meaningful metric for Tamarack and others by establishing a clear link between the Company's cash flows, income statement and operating netbacks by isolating the impact of changes in the timing between accrual and cash settlement dates, which can often be within management's control. Tamarack uses adjusted funds flow to assess the Company's financial performance and cash generated from operating activities.

Free funds flow (capital management measure) is defined as adjusted funds flow less investments in oil and natural gas assets (excluding acquisitions and dispositions) and the settlement of asset retirement obligations. Management utilizes free funds flow to assess how much cash was generated in excess of the Company's capital investment and asset retirement programs within the same period, which can be utilized to reduce debt, fund acquisitions or return capital.

Net debt (capital management measure) is calculated as the sum of the Company's debt, government loans and other, cash, accounts receivable, prepaid expenses and deposits, cross-currency swap liability (asset), assets held for sale (net), accounts payable and accrued liabilities. Tamarack and others utilize net debt to assess liquidity and balance sheet strength by aggregating the select financial assets and financial liabilities on the Company's balance sheet.

Adjusted EBITDA (capital management measure) is calculated as net income (loss) before interest, income taxes, depletion, depreciation, impairment losses, non-cash expenses, unrealized gains (losses) and other non-recurring items. Tamarack uses adjusted funds flow to assess the Company's financial performance. Net debt to adjusted EBITDA (capital management ratio) is calculated as net debt divided by Adjusted EBITDA and provides a measure of earnings relative to the Company's debt levels.

Sustaining capital (supplementary financial measure) represents management's estimate of annual capital investments required to maintain corporate production at prior period levels. This measure allows Management and others to assess the approximate composition of Tamarack's annual capital investment programs and its corporate financial sustainability. Sustaining capital is also utilized to calculate the Company's free funds flow breakeven cost.

Free funds flow breakeven cost (capital management measure) reflects the average minimum WTI price (US per bbl) received by Tamarack where adjusted funds flow net of the base dividend and sustaining capital requirements is approximately equivalent to zero, with sustained current hedged production levels and all other variables held constant. Management believes that free funds flow breakeven provides a useful measure to establish corporate financial sustainability.

The calculation of Tamarack's free funds flow breakeven cost of US$35 per bbl was primarily determined by utilizing the ranges within budget assumptions included in the table on page 1 of this news release, other than for capital investments, which utilize the Company's sustaining capital requirements of $265.0 million under an assumed scaled-budget, break-even price scenario, and average royalty rates which would be expected to decline to 14 – 15% at WTI price of $35 per bbl. Other assumptions utilized by the Company to calculate the free funds flow breakeven cost includes annual dividends of $0.16 per share, hedging gains of $4.67 per boe and asset retirement obligation expenditures of $5.0 million.

Please refer to the management's discussion and analysis for additional information relating to specified financial measures including non-IFRS financial measures, non-IFRS financial ratios and capital management measures. The management's discussion and analysis can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca.

Abbreviations

SOURCE Tamarack Valley Energy Ltd.