2026 Q3 Financial Report

During the Company's first quarter as a pure-play Clearwater producer following the sale of its Charlie Lake assets in June, Tamarack generated third-quarter cash provided by operating activities of $247.7 million, adjusted funds flow(1) of $214.0 million ($0.45 per diluted share) and free funds flow(1) of $92.4 million ($0.19 per diluted share), underpinned by production of 55,298 boe per day (93% liquids). Elevated commodity prices and continued improvements to net operating expenses(1) drove robust operating netbacks(1) of

$56.91 per boe. Year to date, the Company has returned $251.2 million to shareholders through share buybacks and the base dividend. Per share returns continue to be enhanced by Tamarack's share buyback program, which has now reduced the common share float by 85.8 million (15.4%) since commencement of the program, at a weighted average price of $5.80 per share.

The Clearwater continues to demonstrate exceptional reservoir response and decline mitigation on base production from ongoing waterflood investments. Tamarack continues to build out waterflood injection capacity across its core Clearwater positions and is currently injecting 60,000 bbl per day. The Company remains on track to achieve exit water injection rates of 70,000 bbl per day with

~40% of Clearwater oil production under waterflood by the end of 2026 (on legacy Tamarack assets).

Tamarack exited the third quarter with net cash(1) of $141.2 million and available funding(1) of $1.3 billion. Balance sheet strength continues to provide substantial flexibility for the Company to fund Clearwater development, return capital to shareholders and pursue strategic opportunities. The proposed acquisition of Headwater Exploration Inc. ("Headwater") represents a significant opportunity for both companies, establishing Tamarack as a premier North American oil company with top-tier profitability and the unmatched position as the only publicly-traded pure-play Clearwater producer. The acquisition is expected to close in November, with the combined company holding run-rate production of >80,000 boe per day, >300 million boe of proved and probable reserves(2) and

>3,000 identified potential drilling locations(2).

Tamarack is a corporation engaged in the exploration, development, production and sale of oil and natural gas in the Western Canadian Sedimentary Basin. Tamarack is a pure-play Clearwater producer, holding an extensive inventory of primary drilling and waterflood expansion opportunities at Nipisi, Marten Hills and South Clearwater in Northern Alberta. The Company is incorporated and domiciled in Alberta, Canada with the head office located at Suite 1700, 525 - 8th Avenue S.W., Calgary, Alberta, T2P 1G1. Tamarack is a publicly traded company on the Toronto Stock Exchange and is traded under the symbol "TVE".

As at December 31, 2025, the Company had 207.8 million boe of total Clearwater gross proved plus probable reserves(2) and currently holds over 900 sections of acreage across the Clearwater fairway. The Clearwater formations are characterized by strong economics supported by a low-cost structure, low declines and multiple payouts on initial investment. The formation responds strongly to enhanced oil recovery through waterflood injection. Tamarack produced over 55,000 boe per day of oil and natural gas (93% liquids) from the Clearwater in the third quarter of 2026.

This Management's Discussion and Analysis ("MD&A") provides a review of the operations, financial results and outlook for Tamarack for the three and nine months ended September 30, 2026 and 2025. This MD&A is dated as at October 27, 2026, and should be read in conjunction with the unaudited condensed interim consolidated financial statements for the three and nine months ended September 30, 2026 and 2025 ("Interim Financial Statements") and the audited consolidated financial statements for the years ended December 31, 2025 and 2024 ("Annual Financial Statements"). Additional information about Tamarack, including the Company's Annual Information Form for the year ended December 31, 2025, is available on SEDAR+ at https://www.sedarplus.ca and Tamarack's website at https://www.tamarackvalley.ca.

The Company uses certain Non-GAAP Financial Measures, Non-GAAP Financial Ratios, Capital Management Measures and Capital Management Ratios in this MD&A. Certain Supplemental Financial Measures are also presented on a per boe, per share or on a percentage basis. For additional information regarding these measures, refer to the "Advisories and guidance" section of this MD&A.

• Strategic combination - On September 7, 2026, Tamarack entered into a definitive arrangement agreement with Headwater to merge in all-stock transaction, with the combined company valued at approximately $10 billion. As part of the transaction, Tamarack will acquire approximately 25,000 boe per day of heavy oil production, more than 100 million boe of proved plus probable reserves(2) and greater than 1,000 potential drilling locations(2), supporting decades of high-margin drilling and waterflood opportunities across the greater Clearwater fairway. The transaction creates a premier North American oil company as the only publicly-traded, pure-play Clearwater producer. The transaction is expected to close in November 2026.

• Production - Third quarter Clearwater production averaged 55,298 boe per day, an increase of 16% compared to the third quarter of 2025, driven primarily by drilling and development activities and strong reservoir response from ongoing waterflood expansion. Year to date, corporate production of 65,228 boe per day was relatively consistent with the same period in the prior year, as Clearwater production growth offset the sale of Charlie Lake and other non-core asset sales.

• Cash flows - Tamarack delivered cash provided by operating activities of $247.7 million and adjusted funds flow(1) of $214.0 million during the third quarter, increases of 10% and 7%, respectively, compared to the same period in the prior year. The increases were reflective of the strong commodity price environment in the quarter, despite lower production from the sale of Charlie Lake in the second quarter. Year to date, Tamarack generated free funds flow(1) of $375.3 million, or $0.78 per diluted share, a 17% improvement over the same period in 2025.

• Capital investments - Tamarack invested $120.5 million in the third quarter of 2026, drilling 28.0 net Clearwater heavy oil wells and 23.0 net injection and water source wells. In response to higher commodity prices and following the close of the Charlie Lake sale, Tamarack is bringing forward incremental capital to accelerate Clearwater growth. Tamarack is currently injecting 60,000 bbl per day and remains on track to achieve exit water injection rates of 70,000 bbl per day, with ~40% of Clearwater oil production under waterflood by the end of the year (on legacy Tamarack assets). Following the Headwater Acquisition, Tamarack expects pro forma exit injection rates of the combined company to >100,000 bbl per day, with approximately 45% of oil production supported by waterflood.

• Shareholder returns - Year to date, Tamarack returned $251.2 million to shareholders through share buybacks and the base dividend. The Company has repurchased 15.8 million common shares year to date, or 3.2% of the common share float, for a total cost of $189.1 million. Tamarack declared a 25% increase to its quarterly dividend following the sale of Charlie Lake from $0.04 per share to $0.05 per share commencing in the third quarter. The Company intends to increase the quarterly dividend a second time by 20% to $0.06 per share, conditional on completion of the Headwater Acquisition.

• Liquidity - Tamarack fully eliminated its net debt(1) following the sale of Charlie Lake in the second quarter and exited the third quarter with net cash(1) of $141.2 million. Following the completion of the Headwater Acquisition, the combined company is expected to have net cash of >$50 million and available funding(1) of >$1.2 billion, including undrawn credit capacity of $875.0 million.

On September 7, 2026, Tamarack entered into a definitive arrangement agreement with Headwater to merge in an all-stock transaction, creating a premier North American oil company as the only publicly-traded pure-play Clearwater producer (the "Headwater Acquisition"). The combined company will be valued at approximately $10 billion. As part of the transaction, Tamarack is acquiring approximately 25,000 boe per day of high-margin heavy oil production, >100 million boe of proved plus probable reserves(2) and >1,000 potential drilling locations(2).

Headwater shareholders will receive 1.0 common shares of Tamarack for each Headwater common share held, resulting in Tamarack issuing a total of 237.8 million shares to acquire all of Headwater. Following the completion of the transaction, Tamarack shareholders will own 66.5% of the combined company and Headwater shareholders will own 33.5% based on common share counts outstanding as at September 7, 2026. The combined company, led by Tamarack's management team, is expected to have net cash(1) of >$50 million and available funding(1) of >$1.2 billion upon completion of the acquisition.

The combined company will have run-rate production of >80,000 boe per day, more than 1,500 sections across the greater Clearwater fairway, approximately 300 million boe of proved and probable reserves(2) and more than 3,000 identified potential drilling locations(2). The transaction more than doubles Tamarack's existing footprint at Pelican and Seal, providing the combined company with greater exposure to upside potential on prospective Clearwater and Wabiskaw targets in the Greater Clearwater fairway. The transaction is expected to be immediately accretive to Tamarack's free funds flow per share(1) and position the combined company to deliver higher total returns to shareholders.

As part of the transaction, certain assets located in Alberta, Saskatchewan and New Brunswick, will be transferred from Headwater and Tamarack into Tributary Exploration Inc. ("Tributary"), a newly formed exploration company under the plan of arrangement. Legacy shareholders of Tamarack and Headwater will receive common shares of Tributary as a distribution in a similar proportion to the pro forma combined entity initially, providing shareholders with continued exposure to these assets under the stewardship of the legacy Headwater management team.

Contingent on completion of the Headwater Acquisition, Tamarack intends to increase its quarterly dividend by an additional 20% from $0.05 per share to $0.06 per share ($0.24 per share annualized), beginning in the fourth quarter of 2026. The transaction is expected to close in November 2026, subject to regulatory and shareholder approvals.

Tamarack's 2026 revised capital program is trending towards the high end of the range, reflecting an acceleration of development capital in response to higher commodity prices in the third quarter. The revised capital budget also includes the consolidation of Headwater's capital investments from the anticipated acquisition completion date in November to the end of the year. The combined 2026 capital investment programs of both companies for the full year are expected to be approximately $700 million. On a standalone basis, Tamarack is increasing full year 2026 Clearwater production guidance to 54,500 - 56,000 boe per day primarily in response to waterflood outperformance, excluding the expected consolidation of acquired Headwater production after the date of acquisition. Tamarack is reaffirming its anticipated 2026 exit water injection guidance of 70,000 bbl per day, with ~40% of oil production under waterflood (on legacy Tamarack assets). Tamarack expects that the combined company will have 2026 exit water injection rates of >100,000 bbl per day, with ~45% of oil production supported by waterflood.

Tamarack's Clearwater production during the three and nine months ended September 30, 2026, increased by 16% and 17%, respectively, primarily due to drilling and development activities and strong reservoir response from waterflood expansion. On a corporate per boe basis, Clearwater production growth of approximately 7,000 boe per day was more than offset by the sale of Charlie Lake in June 2026 (approximately 18,000 boe per day run-rate) and the sale of the Company's Eastern Alberta assets in the fourth quarter of 2025 (approximately 4,000 boe per day run-rate).

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The price of WTI for crude oil sales at Cushing, Oklahoma is the primary benchmark for crude oil pricing in North America. The differential price between Western Canadian crude and WTI is impacted by multiple factors, including domestic production, inventory levels, pipeline capacity, US refinery intake capacity, trade policies and storage constraints in Canada. The price that Tamarack receives for the sale of its crude oil is discounted for delivery points in Alberta and adjusted for quality based on the characteristics of the oil relative to the quoted benchmark.

WTI benchmark prices increased by 32% and 25%, for the three and nine months ended September 30, 2026, respectively, primarily due to global supply constraints beginning in March 2026 stemming from sustained constraints to oil shipments through the Strait of Hormuz amid the U.S.-Iran conflict.

The WCS differential widened by 33% and 28%, respectively, for the three and nine months ended September 30, 2026, primarily due to increased heavy oil supply flowing into the U.S. Gulf Coast following the U.S.-Venezuela conflict, reduced demand from Asia and extensive U.S. Strategic Petroleum Reserve releases later in the year.

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For the three months ended September 30, 2026, oil and natural gas sales increased 19% from higher realized pricing of $139.1 million, partially offset by lower production of $64.5 million. For the nine months ended September 30, 2026, oil and natural gas sales increased 22% from higher realized pricing of $321.1 million, partially offset by lower production of $51.3 million.

Heavy oil wellhead price realization ($/bbl)

Tamarack's heavy oil wellhead price differential widened by 7% and 9%, respectively, during the three and nine months ended September 30, 2026, primarily due to higher heavy oil trucking costs.

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Risk management instruments are measured at their estimated fair market value at each reporting period. An unrealized loss on commodity risk management contracts reflects a non-cash decrease in value resulting from an increase in future estimated commodity prices relative to Tamarack's contract positions. A realized commodity risk management contract loss reflects the cash settlement of the Company's fixed price position below the actual underlying market prices at the maturity date. Realized and unrealized gains generally result from declines in actual and future estimated commodity prices, respectively.

Risk management losses during the three and nine months ended September 30, 2026, were primarily driven by growth in near-term forward commodity pricing stemming from the ongoing conflicts in the Middle East and Eastern Europe. As at September 30, 2026, Tamarack's commodity risk management contracts were a net liability of $63.0 million (December 31, 2025 - $14.6 million net asset).

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During the third quarter of 2026, royalty expenses averaged 23% of oil and natural gas sales, primarily reflecting the impact of higher sliding scale rates due to the increase in benchmark oil prices. Royalty expenses averaged 20% of oil and natural gas sales during the nine months ended September 30, 2026, which included lower reference commodity prices in the first quarter of the year.

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For the three and nine months ended September 30, 2026, net operating expenses per boe improved by 15% and 11%, respectively, primarily due to lower water handling and trucking costs from expanded waterflood reinjection and non-core property dispositions in the second and fourth quarters of 2025. Third quarter net operating expenses per boe also improved from the sale of the Company's Charlie Lake assets in June 2026, which carried higher operating costs on a per barrel basis relative to Tamarack's higher-margin Clearwater assets.

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Transportation expenses per boe during the third quarter of 2026 increased by 24% from third-party pipeline service interruptions and increased trucking activities. For the nine months ended September 30, 2026, transportation expenses per boe increased by 10% primarily due to a greater proportion of new Clearwater production requiring incremental transportation costs to reach Edmonton and higher fuel surcharges.

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For the three and nine months ended September 30, 2026, the operating netback per boe increased by 33% and 22%, respectively, primarily due to higher commodity prices. Improvements in the operating netback were partially offset by higher royalty rates and realized hedging losses from higher benchmark commodity prices.

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Growth in stock-based compensation expense for the three and nine months ended September 30, 2026, was primarily due to an increase in Tamarack's share price in 2025 and 2026. Stock-based compensation expense in 2026 also reflects the impact of forecasted performance multipliers on vesting equity compensation units.

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For the three and nine months ended September 30, 2026, interest expense decreased by 37% and 17%, respectively, primarily due to the ongoing reduction of amounts outstanding under the Credit Facility and the redemption of the 2027 Notes across 2025 and 2026. Interest on Credit Facility draws also improved from overnight rate cuts by the central bank of Canada since mid-2025. These improvements were partially offset by interest expense from the 6.875% 2030 Notes issued in July 2025. The improvements in deferred borrowing costs and loan accretion for the three and nine months ended September 30, 2026, were driven by lower Credit Facility fees and lower deferred borrowing cost amortization on the redeemed 2027 Notes.

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For the three and nine months ended September 30, 2026, current income tax expense increased primarily due to higher adjusted funds flow(1) and proceeds of disposal from the sale of the Charlie Lake assets. The deferred income tax recoveries in the prior year were primarily due to the sale of the Company's Eastern Alberta assets in the third quarter of 2025.

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For the three and nine months ended September 30, 2026, D&D expense per boe decreased by 26% and 23%, respectively, primarily due to higher reserves added from ongoing drilling, development and waterflood activities in the Clearwater area and lower relative future development costs from improved capital efficiencies. Gross D&D expense for the three and nine months ended September 30, 2026, decreased primarily due to the lower rates and lower production.

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Adjusted funds flow for the three and nine months ended September 30, 2026, increased by 7% and 11%, respectively, primarily due to higher operating netbacks from strong benchmark commodity prices. Adjusted funds flow on a per diluted share basis increased by 13% and 17%, respectively, supported by a lower average number of common shares outstanding due to the Company's ongoing share buyback program. Cash provided by operating activities for the three and nine months ended September 30, 2026, increased by 10% and 23%, respectively, primarily reflecting the higher adjusted funds flow, partially offset by changes in non-cash working capital from income tax liabilities.

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Adjusted net income for the three and nine months ended September 30, 2026, increased by 95% and 91%, respectively, primarily due to higher adjusted funds flow and lower depletion and depreciation, partially offset by higher realized losses on risk management contracts. Net income for those periods increased primarily due to higher adjusted net income, partially offset by higher unrealized hedging losses. In the prior year, net income was also impacted by the impairment loss on the sale of the Company's Eastern Alberta assets in the third quarter of 2025.

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Year to date capital investments in 2026 were primarily focused on Clearwater drilling and development activities and secondary waterflood expansion. Waterflood activity increased substantially in the third quarter, in-line with the Company's originally budgeted second-half-weighted waterflood development program and the acceleration of Clearwater development into 2026 following the sale of Charlie Lake and in response to higher commodity prices.

On May 27, 2026, Tamarack entered into a purchase and sale agreement to sell all of its Charlie Lake assets in the Grande Prairie area for gross cash proceeds of $803.8 million before closing adjustments. The transaction had an effective date of April 1, 2026 and was completed on June 15, 2026. The Company received net proceeds of $727.9 million, net of effective date adjustments of

$50.8 million, the unwinding of affiliated light oil risk management contracts of $13.3 million and transaction costs of $11.8 million. In connection with the sale, Tamarack derecognized $27.0 million in discounted asset retirement obligations and recorded a loss of $19.6 million.

On September 17, 2025, Tamarack entered into a purchase and sale agreement with a private company to sell substantially all of the Company's remaining oil and natural gas assets in Eastern Alberta for gross cash proceeds of $112.0 million before closing adjustments and the assumption of $62.5 million of undiscounted asset retirement obligations, resulting in an impairment loss of

$397.0 million. The transaction was completed on October 15, 2025.

On May 21, 2025, Tamarack sold its non-core oil and natural gas assets in the Southern Alberta Penny area for gross cash proceeds of $28.0 million before closing adjustments. In connection with the sale, Tamarack derecognized $14.5 million in discounted asset retirement obligations and recorded a net loss of $40.2 million across 2024 and 2025.

The Company continues to prioritize a combination of growth and shareholder returns through the allocation of free funds flow generated by the business. Tamarack believes that cash on hand and available credit, together with future anticipated adjusted funds flow, will be sufficient to fund Tamarack's planned capital development programs, the Headwater Acquisition and any other future acquisitions, dividends or share buybacks.

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In January 2026, the Company renewed its normal course issuer bid, allowing Tamarack to purchase up to 47.7 million common shares of the Company until January 18, 2027. During the nine months ended September 30, 2026, the Company purchased and retired

15.8 million common shares at an average price of $11.99 per common share for a total repurchase cost of $189.1 million, including

$4.0 million of federal taxes and fees. As of October 19, 2026, Tamarack had repurchased 0.7 million common shares for $9.0 million subsequent to the third quarter.

Starting in 2026, Tamarack adjusted the dividend cadence from monthly to quarterly. In the third quarter, Tamarack increased the quarterly dividend by 25% from $0.04 per share to $0.05 per share. Contingent on completion of the Headwater Acquisition, Tamarack intends to increase its quarterly dividend a second time by 20% from $0.05 per share to $0.06 per share ($0.24 per share annualized), beginning in the fourth quarter.

Tamarack actively manages capital and liquidity risk through the continuous monitoring of asset performance, forecasting anticipated future cash flows in conjunction with the design of the annual capital investment programs, maintaining available credit under bank facilities, managing debt maturity dates, hedging a portion of the Company's production, judiciously assessing new capital investment, acquisition or asset sale opportunities and the pursuit of new liquidity, if necessary.

Tamarack utilizes adjusted funds flow, available funding and net (cash) debt as capital management measures to assess financial performance and liquidity. Tamarack fully eliminated its net debt in 2026 following the sale of Charlie Lake and exited the third quarter with cash of $541.4 million and net cash of $141.2 million.

As at September 30, 2026, Tamarack had access to an undrawn covenant-based $875.0 million revolving lending facility (the "Credit Facility"). In the second quarter of 2026, amounts drawn under the Credit Facility were fully repaid using a portion of the net proceeds from the sale of Charlie Lake. The Credit Facility has an uncommitted accordion feature that provides the Company with the ability to access an incremental $125.0 million of secured debt, subject to certain conditions, including approvals from the lending syndicate. In May 2026, Tamarack extended the Credit Facility maturity date by two years to May 29, 2030 and the facility was also amended to ease certain covenant restrictions, including the leverage ratios.

In July 2025, the Company issued the 2030 Notes, consisting of $325.0 million of 6.875% interest-bearing senior unsecured notes maturing on July 25, 2030. The 2030 Notes pay interest semi-annually. The Company also previously held $200.0 million of 7.25% interest-bearing senior unsecured notes due on May 10, 2027. On May 11, 2026, Tamarack redeemed the remaining outstanding 2027 Notes at a cost of 100.75% of principal, initially utilizing the proceeds of a Credit Facility draw.

At any given time, the balance of issued and outstanding equity compensation units that are granted to service providers of the Company may not exceed 4% of the outstanding common share float of the Company, pursuant to the limits set forth in Tamarack's stock-based compensation plans.

During the nine months ended September 30, 2026, the Company granted 4.3 million share-based awards at a weighted average fair value of $10.33 per share, which was primarily based on the Company's share price at the date of grant. Tamarack utilized acquired treasury shares to settle 2.7 million stock-based compensation units that were exercised in the nine months ended September 30, 2026, resulting in no dilution of outstanding common shares.

Performance share units ("PSUs") and performance incentive awards ("PIAs") are subject to a maximum performance multiplier of

2.0 times, which would increase the number of common shares that are ultimately issued to unitholders. As at September 30, 2026, if all outstanding, unvested PSUs and PIAs were to vest with the maximum potential performance multiplier of 2.0, 6.4 million incremental units (or equivalent cash value) would be issued to unitholders. For the nine months ended September 30, 2026, actual market and non-market performance adjustment factors on vested PSUs and PIAs averaged 1.93 (year ended December 31, 2025 - 1.25).

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In August 2026, Tamarack entered into a 20-year, $2.3 billion pipeline commitment on the TMX mainline system to transport up to 25,000 bbl per day from Edmonton to the West Coast of British Columbia. Tamarack expects to commence shipping volumes on the TMX system in the first quarter of 2027, subject to the completion of the TMX's Drag Reducing Agent expansion.

In July 2026, Tamarack also finalized a 10-year, $269.1 million commitment with a third-party to transport 22,000 bbl per day of oil production from the Company's core West Marten development area to Edmonton. The transaction included third-party construction of a LACT, storage tank and lateral pipeline connection near Tamarack's 15-15 facility to the mainline system.

Not included in the commitments table above is a 20-year pipeline commitment that Tamarack has entered into on the proposed South Bow Prairie Connector pipeline. The arrangement will potentially allow the Company to transport up to 10,000 bbl per day from Edmonton to Cushing, Oklahoma and the U.S. Gulf Coast. The contract commitment is subject to project regulatory approval and construction and could be in-service by the end of 2028.

Tamarack is involved in legal matters that have arisen in the normal course of business. While the final outcomes of such matters cannot be predicted with certainty and could be material, Tamarack believes that the claims are without merit. The Company also does not anticipate that any of these legal proceedings will have a material impact on Tamarack's consolidated financial position or results of operations.

Significant factors and trends that have impacted the Company's results during the above quarterly periods include:

• Changes in commodity prices and differentials and the resulting effect on revenue, cash provided by operating activities, adjusted funds flow and earnings.

• Changes in asset retirement obligations due to fluctuations in discount rates, acquisitions and dispositions.

• The Company uses derivative contracts to reduce the financial impact of changing commodity prices, foreign exchange and interest rates, which can cause significant fluctuations in earnings due to unrealized gains and losses recognized on a quarterly basis.

• On December 17, 2024, Tamarack entered into a purchase and sale agreement for the disposition of substantially all of the non-core oil and natural gas assets in the Southern Alberta Penny area for gross cash proceeds of $28.0 million before effective date adjustments, resulting in a reduction in discounted asset retirement obligations of $14.5 million. As at December 31, 2024, the assets and corresponding liabilities were presented as held for sale at their anticipated recoverable value, resulting in an impairment loss of $38.1 million. The transaction was completed on May 21, 2025.

• On July 25, 2025, the Company issued $325.0 million aggregate principal amount of 6.875% interest-bearing senior unsecured notes due on July 25, 2030. The 2030 Notes pay interest semi-annually with the principal amount repayable at the date of maturity. Net proceeds from the transaction at the date of completion were utilized primarily to repay amounts outstanding under the Credit Facility and redeem $100.0 million of the 2027 Notes.

• On July 29, 2025, Tamarack acquired all of the issued and outstanding shares of a private company for cash consideration of $51.5 million before effective date adjustments. In connection with the acquisition, Tamarack acquired approximately 1,100 boe per day of heavy oil and natural gas production and over 114 net sections of mineral rights near the Company's core asset holdings in the Clearwater.

• On October 15, 2025, Tamarack sold substantially all of the Company's remaining non-core oil and natural gas assets in the Veteran Consort and Eyehill areas of Eastern Alberta for gross cash proceeds of $112.0 million before effective date adjustments. As part of the sale, Tamarack derecognized $40.8 million in asset retirement obligations and recorded a loss on sale of $397.9 million. The disposed assets included production of ~4,000 boe per day.

• On October 17, 2025, Tamarack acquired 20.46 net sections in the Pelican area for $41.5 million, targeting the Clearwater and Wabiskaw formations.

• On May 11, 2026, Tamarack redeemed the remaining outstanding 2027 Notes at a cost of 100.75% of principal utilizing the proceeds from a Credit Facility draw.

• On June 15, 2026, Tamarack sold all of the Company's Charlie Lake assets in the Grande Prairie area for gross cash proceeds of $803.8 million before effective date adjustments. As part of the sale, Tamarack derecognized $27.0 million in asset retirement obligations and recorded a loss on sale of $19.6 million. The disposed assets included production of ~18,000 boe per day. A portion of the net proceeds were utilized to repay amounts drawn under the Credit Facility.

1. Refer to "Advisories and guidance" for information on Capital management measures and ratios, Non-GAAP financial measures and ratios and Supplemental financial measures.

2. Tamarack's reserves are based upon the independent evaluation of the Company's properties conducted by McDaniel & Associates Consultants Ltd. ("McDaniel") dated January 21, 2026 and effective December 31, 2025. Headwater's reserves are based upon the independent evaluation of Headwater's properties conducted by McDaniel dated January 15, 2026 and effective December 31, 2025 included in Headwater's annual information form for the year ended December 31, 2025. Combined figures are the arithmetic sum of the two evaluations. Drilling locations include booked and unbooked locations. Refer to "Advisories and guidance" for information about the reserves evaluations and drilling locations.

   Advisories and guidance

   Key accounting policies, estimates and judgments

   Tamarack utilized significant estimates, assumptions and judgments in order to apply the relevant accounting policies to the preparation of the Annual Financial Statements in accordance with IFRS Accounting Standards. A summary of this information can be found in Notes 2-4 of the Annual Financial Statements. The key accounting policies of the Company that are subject to significant estimates, assumptions or judgments consist of oil and natural gas assets, impairment, business combinations, financial instruments, provisions, income taxes and the basis of consolidation. There were no new or significant updates to the application of the Company's key accounting policies, estimates, assumptions or judgments during the three and nine months ended September 30, 2026.

   Non-GAAP financial measures and non-GAAP financial ratios

   This document contains the terms "net operating expenses", "operating netback", "operating field netback", "heavy oil wellhead price differential" and "adjusted net income", which are non-GAAP financial measures, or ratios if calculated on a per boe or per share basis. These non-GAAP financial measures and ratios do not have any standardized meaning prescribed by GAAP and, therefore, may not be comparable to similar measures presented by other issuers without taking into account the method by which the measures are prepared. These performance measures should not be considered in isolation or as a substitute for performance measures prepared in accordance with GAAP and should be read in conjunction with the Interim Financial Statements and Annual Financial Statements. Refer to the discussion of the Company's operating results for further details regarding the calculation and measurement of these measures. The most directly comparable financial measures presented in the primary financial statements are operating expenses (for net operating expenses), oil and natural gas sales (for operating netback, operating field netback and heavy oil wellhead price differential) and net income (loss) (for adjusted net income).

   The non-GAAP financial ratios consisting of non-GAAP measures presented on a per share basis are determined by dividing the value of the financial measure by the weighted average common shares outstanding and diluted weighted average common shares outstanding during the period. These per share disclosures allow Tamarack and others to understand the value of selected financial information that is attributable to each common share. The non-GAAP financial ratios consisting of non-GAAP measures presented on a per boe basis are determined by dividing the value of the financial measure by the sales volumes in the period. These per boe disclosures allow Tamarack and others to assess the profitability of each barrel of oil equivalent produced and also facilitates a comparison of current period performance to historical periods, or to peer results, by isolating the impact of differences in production volumes.

   Heavy oil wellhead price differential

   The calculation of the Company's heavy oil wellhead price differential is presented in the "Oil and natural gas sales" section of this MD&A and is determined by comparing the Company's realized price on a per barrel basis to the published benchmark price, including the impact of transportation expenses. The Company and others utilize this performance measure to assess the value of net wellhead revenue received by Tamarack for each barrel sold, relative to the published benchmark price during that period. These performance measures are presented on a per bbl basis as a non-GAAP financial ratio.

   Net operating expenses

   Tamarack generates processing income from third parties that utilize excess capacity at Tamarack's facilities. In this MD&A, processing income is recognized as a reduction to operating expenses, whereas processing income is reported as other income in the financial statements. If Tamarack has excess capacity at one of its facilities, the Company will seek to process third-party volumes as a means to reduce the cost of operating those facilities. Accordingly, net operating expenses allow Tamarack and others to assess the performance of its field and facility operating results by including the associated income generated from plant operations. Net operating expenses are also presented on a per boe basis as a non-GAAP financial ratio.

   Operating netback and operating field netback

   The calculation of the Company's operating netback and operating field netback is presented in the "Operating netback" section of this MD&A. Tamarack and others utilize the operating netback and operating field netback measures to assess the operational performance of the Company's assets by isolating the impact of corporate and other overhead related expenditures. These metrics are also presented on a per boe basis as a non-GAAP financial ratio.

   Adjusted net income

   The calculation of the Company's adjusted net income is presented in the "Net income (loss) and adjusted net income" section of this MD&A and is determined by removing impairment losses, gains and losses on dispositions and unrealized gains and losses on risk management contracts on an after-tax basis from the Company's net income (loss) for the period. Tamarack and others utilize this performance metric to assess earnings, excluding the impact of non-cash gains and losses. This metric may also be presented on a per share basis as a non-GAAP financial ratio.

   Capital management measures and ratios

   This document contains capital management measures of "adjusted funds flow", "free funds flow", "available funding", "net (cash) debt", "working capital surplus" and "net (cash) debt to annualized adjusted funds flow", which the Company utilizes to manage its capital. Refer to the Interim Financial Statements and Annual Financial Statements for further details. Available funding is a capital management measure that was added in the second quarter of 2026 in response to the

   Company's net cash position and available credit following the sale of Charlie Lake. These capital management measures do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers without taking into account the method by which the measures are prepared. These performance measures should not be considered in isolation or as a substitute for performance measures prepared in accordance with GAAP and should be read in conjunction with the Interim Financial Statements and Annual Financial Statements. Refer to the discussion of the Company's operating results and the "Liquidity and Capital Resources" section for further details regarding the calculation of these measures.

   This MD&A also contains forward-looking non-GAAP financial measures and capital management measures, including the anticipated net cash and available funding of the combined company following completion of the Headwater Acquisition and the expected accretion to free funds flow per share. Such forward-looking measures are calculated on a basis consistent with the equivalent historical measures described in this section, and there are no significant differences between the forward-looking measures and the equivalent historical measures.

   Adjusted funds flow

   Adjusted funds flow 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 are often within management's control. Tamarack uses adjusted funds flow to assess the Company's financial performance and cash generated from operating activities. Adjusted funds flow per share and adjusted funds flow per boe are supplemental financial measures and are calculated by dividing adjusted funds flow by the Company's weighted average basic and diluted shares outstanding and total sales volumes during the period, respectively.

   Free funds flow

   Free funds flow is defined as adjusted funds flow less investments in oil and natural gas assets 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 net debt, fund acquisitions or return capital to shareholders. Free funds flow is also presented on a per share basis as a capital management ratio.

   Available funding

   Available funding is calculated as the sum of undrawn credit capacity under the Company's credit facility and cash, accounts receivable, prepaid expenses and deposits, cross-currency swap liability (asset), assets held for sale (net), accounts payable and accrued liabilities. The available funding measure provides users with an indication of the liquidity available to fund capital investments and any acquisitions or shareholder distributions.

   Net (cash) debt and working capital surplus

   The calculation of the Company's net (cash) debt and working capital surplus is included under "Liquidity and capital resources". Tamarack and others utilize net (cash) debt and working capital surplus to assess liquidity and balance sheet strength by aggregating the select financial assets and financial liabilities on the Company's balance sheet.

   Net (cash) debt to annualized adjusted funds flow

   Net (cash) debt to annualized adjusted funds flow is a capital management ratio and is calculated as net (cash) debt divided by the annualized adjusted funds flow for the most recently completed quarter. Tamarack and others utilize net (cash) debt to annualized adjusted funds flow to provide a measure of the overall financial health of the Company and assess the Company's ability to fund capital investments, acquisitions, the servicing of debt costs, debt reduction, the ability to raise new debt, repurchase shares or make dividend payments.

   Supplemental financial measures

   Per share disclosures

   Tamarack's supplemental financial measures on a per share basis consist of cash provided by operating activities per share, adjusted funds flow per share and free funds flow per share. These supplemental financial measures are determined by dividing the value of the financial measure by the weighted average common shares outstanding and diluted weighted average common shares outstanding, as presented in the Interim and Annual Financial Statements. The per share disclosures allow Tamarack and others to understand the value of the selected financial information attributable to each common share holder. Adjusted funds flow and free funds flow per share are capital management ratios as discussed above.

   Per BOE disclosures

   Tamarack's supplementary financial measures on a per boe basis consist of average heavy oil realized sales price per bbl, average light oil realized sales price per bbl, average NGL realized sales price per bbl, average natural gas realized sales price per mcf, heavy oil wellhead price differential per bbl, royalty expense per boe, transportation expenses per boe, realized commodity hedging gain/loss per boe, G&A expense per boe, stock-based compensation expense per boe, interest expense per boe and D&D per boe. The calculation of the heavy oil wellhead price differential is included in the operating results section of this MD&A. Certain measures are presented on a per boe basis to allow Tamarack and others to assess the profitability of each barrel produced, and allows for a comparison of current period performance to historical periods, or to peer results, by isolating for the impact of differences in production volumes. Net operating expenses per boe, operating field netback per boe and operating netback per boe are non-GAAP financial ratios as discussed above.

   Percentage of sales

   Tamarack's supplementary financial measures as percentage of sales consists of the average royalty rate. The average royalty rate as a percentage of sales is used by Tamarack and others to understand the average effective amount of royalties owing for each dollar of sales that is generated.

   Disclosure controls and internal controls over financial reporting

   Part 1 of National Instrument 52-109 - Certification of Disclosure in Issuer's Annual and Interim Filings defines disclosure controls and procedures ("DC&P") as "controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure".

   The Company has designed DC&P to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's CEO and CFO by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in the annual filings, interim filings or other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

   The CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR") to provide reasonable assurance regarding the reliability of financial reporting and the preparation of annual financial statements for external purposes in accordance with GAAP. The

   Company is required to disclose herein any change in the Company's ICFR that occurred during the recent fiscal period that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting.

   The Company's DC&P and ICFR were effective as at September 30, 2026. No material changes to the Company's DC&P and its ICFR were identified during the period ended September 30, 2026 that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting. Internal control systems, including the Company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute assurance that the objectives of the control system will be met, and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

   Volumetric reporting

   For the purpose of reporting unit production and related units of measurement, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based on an energy equivalency conversion at the burner tip but does not necessarily represent a value equivalency at the wellhead where production is actually measured and reported. This conversion complies with the Canadian Securities Administrators' National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), however, a boe unit of measurement could be misleading, particularly if used in isolation.

   Climate change

   The Company continues to monitor the impact of global demand for carbon-based energy and advancement of alternative energy sources. Emissions, carbon and other regulations impacting climate related matters are constantly evolving. With respect to ESG and climate reporting, the International Sustainability Standards Board ("ISSB") was created on November 3, 2021 to develop consistent, comparable and reliable sustainability reporting standards. On June 26, 2023, the ISSB issued IFRS S1 "General Requirements for Disclosure of Sustainability-related Financial Information" and IFRS S2 "Climate-related Disclosures". IFRS S1 and IFRS S2 are effective for annual reporting periods beginning on or after January 1, 2024, but are not mandatory for Canadian reporting issuers unless and until adopted by the CSA. The standards provide for transitional relief allowing an issuer to limit its disclosure to climate-related risks and opportunities in the first year.

   On December 18, 2024, the Canadian Sustainability Standards Board published its first two disclosure standards for sustainability reporting in Canada (general sustainability disclosures and climate related disclosures). Most notably, the new standards retained the requirement for companies to report their scope 3 emissions. The standards provide for numerous transitional provisions and allowances between 2025 and 2028 to facilitate the adoption by Canadian companies.

   The Canadian Securities Administrators ("CSA") are responsible for determining the reporting requirements for public companies in Canada and decisions related to the adoption of the sustainability reporting standards, including the effective annual reporting dates. The CSA issued proposed National Instrument 51-107 Disclosure of Climate-related Matters ("NI 51-107") in October 2021. The CSA has indicated it will consider the ISSB sustainability standards and developments in the United States in its decisions related to developing climate-related reporting requirements for reporting issuers in Canada. The CSA will involve the Canadian Sustainability Standards Board ("CSSB") for their combined review of the ISSB issued sustainability standards for their suitability for adoption in Canada. However, in April 2025, the CSA announced that it is pausing further work on the development of mandatory climate-related reporting rules, in light of recent developments in the United States and internationally. The CSA has indicated that it will monitor domestic and international regulatory developments with respect to climate-related disclosures and expects to revisit this project in future years to finalize the requirements for Canadian issuers. Until such time as the CSA and CSSB make decisions on sustainability standard adoption in Canada, there is no requirement for public companies in Canada to adopt the sustainability standards. The Company is actively evaluating the potential effects of the sustainability standards.

   Risks

   Tamarack faces business risks, both known and unknown, with respect to its oil and gas exploration, development, and production activities that could cause actual results or events to differ materially from those forecasts. Most of these risks (financial, operational or regulatory) are not within the Company's control. While the following sections discuss some of these risks, they should not be construed as exhaustive. Tamarack is directly impacted by these risks:

   • Changes in commodity and petroleum product prices

   • Inflation risk

   • Environmental and climate change risk

   • Financial risks

   • Operational risks

   • Regulatory risks

   For additional information on the risks relating to Tamarack's business, see "Risk Factors" in Tamarack's Annual Information Form and "Business Risks" in Tamarack's Annual MD&A for the year ended December 31, 2025.

   Forward-looking statements

   Certain statements contained within this MD&A constitute forward-looking statements within the meaning of applicable Canadian securities legislation. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "budget", "plan", "endeavour", "continue", "estimate", "evaluate", "expect", "forecast", "monitor", "may", "will", "can", "able", "potential", "target", "intend", "consider", "focus", "identify", "use", "utilize", "manage", "maintain", "remain", "result", "cultivate", "could", "should", "believe", "strive" and similar expressions or the negative of such terms or other comparable terminology. The Company believes that the expectations reflected in such forward-looking statements are reasonable, but no assurance can be given that such expectations will prove to be correct and such forward-looking statements should not be relied upon without appropriate consideration. This MD&A contains forward-looking statements pertaining to:

   • the intentions of management and the Company;

   • the Headwater Acquisition, including the anticipated timing of completion, the satisfaction of closing conditions and receipt of shareholder, court, regulatory and stock exchange approvals, the number of common shares to be issued and the resulting pro forma ownership, the production, reserves, drilling locations, land position and other attributes of the combined company, the anticipated net cash, available funding and accretion to free funds flow per share of the combined company, the transfer of certain assets to Tributary and the distribution of Tributary shares, the consolidation of Headwater's capital investment and production in the Company's 2026 guidance, and the proposed dividend increase contingent on completion of the transaction;

   • the anticipated timing of commencement of shipping on the TMX system and of the in-service date of the South Bow Prairie Connector pipeline;

   • the Company's commitment to maintaining financial flexibility and liquidity;

   • the Company's business strategy, objectives, strength and focus, including with respect to acquisitions;

   • the Company's plans to continue developing and expand its Clearwater asset base in Northern Alberta;

   • the timing, amount and allocation of the planned additional Clearwater capital investments by the Company and planned secondary waterflood recovery initiative;

   • the Company's continued consideration of the impact of climate change and possible upcoming related financial and operational considerations and implications with respect to the future of the Company;

   • the Company's continued consideration of the potential impacts of the evolving global demand for carbon-based energy and global advancement of alternative energy sources;

   • expectations relating to future realized commodity prices, changing commodity prices, royalty rates and oil price differentials and the effects thereof, including with respect to revenue, earnings and stability to oil pricing;

   • the Company's financial and physical hedging program, including the use of financial derivatives and physical delivery contracts to manage fluctuations in commodity prices, foreign exchange rates, and interest rates, and the effects thereof on cash flow risk and commodity pricing upside;

   • anticipated benefits of Clearwater formations including its enhanced recovery potential and benefits of the Company's ongoing waterflood investment, including lower production costs, reduced corporate decline rates and lower reinvestment ratios;

   • purchases under the Company's current normal course issuer bid including the Company's plan to reacquire up to 47.7 million common shares by January of 2027;

   • the Company's plans in respect of returns of capital, including dividend and enhanced return programs, including the Company's intention to increase the quarterly dividend;

   • the Company's expectation regarding low corporate breakeven oil prices and its ability to generate free funds flow;

   • the Company's expectations surrounding its 2026 capital guidance, including the Company's expectation to trend towards the higher end of the capital investment guidance, funding thereof and the ability to satisfy its planned 2026 capital development program, while maximizing free funds flow generation with continued growth of the Company and shareholder returns by way of dividend payments and share buybacks being the priorities of the Company;

   • expectations regarding continued shareholder returns throughout 2026, including dividends and share buybacks;

   • the Company's belief that cash on hand, available credit and anticipated adjusted funds flow will be sufficient to fund the Company's planned capital programs and any future acquisitions, dividends and share buybacks;

   • the Company's 2026 outlook and planned 2026 capital projects and ongoing assessments in respect of the same;

   • the Company's ability to scale its 2026 capital program in response to near-term market changes;

   • expectations surrounding the Credit Facility and the terms thereof, including the ability to access an incremental $125.0 million of secured debt subject to certain conditions;

   • financial covenants applicable to the Credit Facility;

   • Tamarack's 2026 production guidance, operating expense guidance and ongoing assessments in respect of the same;

   • the Company's ability to meet its obligations and commitments under the 2030 Notes;

   • the Company's expectations relating to the continued generation of higher margins through improved heavy oil price differentials, enhanced market egress, long-term firm volume commitments and lower operating costs;

   • contractual obligations and commitments;

   • estimates used to calculate asset retirement obligations and depletion of oil and natural gas assets;

   • the Company's capital investment plans, including drilling activities in the Clearwater, the ongoing expansion of the Clearwater waterflood and the

     expectation to achieve exit water injection rates in the Clearwater area of over 70,000 bbl per day with 40% of Clearwater oil production under waterflood by the end of 2026;

   • anticipated phasing of the majority of the Company's secondary recovery investment to the balance of the year;

   • the Company's exploration and derisking plans;

   • the Company's expectations surrounding continued production growth supported by strong reservoir response and decline mitigation on base production from ongoing Clearwater waterflood investments;

   • forecasted royalty rate, general and administrative expenses, income taxes and interest expense for 2026;

   • the Company's risk management activities (including plans to continue actively managing capital and liquidity risk through continuous monitoring of asset performance, forecasting anticipated future cash flows in conjunction with the design of the annual capital investment programs, maintaining available credit under bank facilities, spreading debt maturity dates, hedging a portion of the Company's production, judiciously assessing new capital investment, acquisition or asset sale opportunities and the pursuit of new liquidity, if necessary);

   • the Company's plans in respect to its employees including for its employees to address the continued development of new or established reservoirs on a go-forward basis using the same procedure as is used to address exploration risk and the effects thereof on mitigation of operation risk;

   • Tamarack's stock-based compensation plans and the equity compensation units issuable thereunder;

   • expectations surrounding the Company's major infrastructure projects and anticipated benefits thereof, including with respect to the performance of its Clearwater drilling programs;

   • expectations regarding the Company's ongoing monitoring of evolving climate-related reporting standards and the potential impacts on reporting obligations and business operations;

   • expectations surrounding identified changes to the Company's DC&P and its ICFR (or no changes) and its effect on the Company's internal controls over financial reporting on a go-forward basis (including the lack thereof);

   • expectations regarding the merits, impacts and the outcome of ongoing legal processes; and

   • the Company's expectations regarding inflation and interest rates and the ability to manage such pressures.

     With respect to the forward-looking statements contained in this MD&A, Tamarack has made assumptions regarding, among other things:

   • the material assumptions and observations described under the headings "Q3 2026 in review", "About Tamarack Valley Energy Ltd.", "Q3 2026 operational and financial highlights", "Highlights for the three and nine months ended September 30, 2026", "Acquisition of Headwater Exploration Inc.", "Annual guidance", "Production", "Benchmark prices", "Oil and natural gas sales", "Risk management", "Royalties", "Net operating expenses", "Transportation expenses", "Operating netback", "General and administrative ("G&A") expenses", "Stock-based compensation expense", "Finance expense", "Income taxes", "Depletion and depreciation ("D&D")", "Cash provided by operating activities and adjusted funds flow", "Net income (loss) and adjusted net income", "Investments in oil and natural gas assets", "Liquidity and capital resources", "Share capital", "Commitments and contingencies" and "Selected quarterly information";

   • future commodity prices, price differentials and the actual prices received for the Company's products;

   • the satisfaction of the conditions to completion of the Headwater Acquisition, including receipt of all required approvals, on the anticipated timeline;

   • the accuracy of Headwater's public reporting and of the reserves and resources evaluations of Headwater's properties;

   • the realization of the anticipated benefits of the Headwater Acquisition and the successful integration of Headwater's business;

   • expected net operating expenses and transportation expenses;

   • basis for continued shareholder returns, including assumptions regarding production, pricing, foreign exchange, differential and free cash flow return;

   • estimated proved plus probable oil and natural gas reserves;

   • the effects of volume apportionment and fluctuating diluent costs on the heavy oil market in Alberta;

   • the ability to obtain equipment and services in the field in a timely and efficient manner;

   • the ability to add production and reserves through acquisition and/or drilling at competitive prices;

   • the timing of anticipated future production additions from the Company's properties and acquisitions;

   • the realization of anticipated benefits of the Company's infrastructure and waterflood development program and the Company's acquisitions, including related drilling programs, as applicable;

   • drilling results, including field production rates and decline rates;

   • the performance of the waterflood projects;

   • the timing, amount and performance of additional Clearwater capital investments and secondary waterflood recovery initiatives;

   • the continued application of horizontal drilling and fracturing techniques and pad drilling;

   • the continued availability of capital and skilled personnel;

   • the ability to obtain financing on acceptable terms;

   • the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation;

   • the impact of increasing competition;

   • the ability of the Company to secure adequate product transportation;

   • the ability to enter into future commodity derivative contracts on acceptable terms;

   • the continuation of the current tax, royalty and regulatory regime;

   • the changes in commodity prices and oil price differentials and the resulting effect on Tamarack's revenue, cash provided by operating activities, adjusted funds flows and earnings;

   • the actions of OPEC+ and non-OPEC+ oil and gas exporting countries to set production levels and the influence thereof on oil prices and global demand including in respect of recent increases to the group's production quotas;

   • the ability to adjust capital spending relative to commodity prices and use financial derivatives and physical delivery contracts to manage fluctuations in commodity prices, foreign exchange rates and interest rates;

   • the availability of cash on hand, available credit and future anticipated adjusted funds flow to fund planned capital development programs and future acquisitions, dividends or share buybacks;

   • Tamarack's ability to maintain financial flexibility; and

   • the impact of inflation on costs and interest rates.

     Without limitations of the foregoing, future dividend payments, if any, and the level thereof, are uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time is dependent upon, among other things, commodity prices, 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 the frequency thereof, 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.

     Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated or implied by such forward-looking statements due to a number of factors and risks. These include:

   • the material uncertainties and risks described under the heading "Advisories and guidance";

   • the risk that the Headwater Acquisition is not completed on the anticipated timeline or at all, including as a result of not being able to obtain required shareholder, court or regulatory approvals or to satisfy other conditions required to complete the transaction;

   • the risk that the arrangement agreement is not completed, including the payment of any termination fee;

   • the risk that the anticipated benefits of the Headwater Acquisition are not realized or that integration is more complex or expensive than anticipated;

   • dilution resulting from the issuance of common shares under the Headwater Acquisition;

   • the risks relating to the Tributary spin-out and to Headwater's business;

   • the risks relating to inclement weather events, including fire, dry conditions and flooding and corresponding effects, including in respect to safety, asset integrity, temporarily suspending production, impact on production, maintaining 2026 guidance and resumption of operations;

   • the risks with respect to third-party pipeline or natural gas processing facility outages;

   • the risks associated with the oil and gas industry in general, such as operational risks in development, exploration and production and including changes in commodity prices and petroleum product prices;

   • the actions of OPEC+ and non-OPEC+ oil and gas exporting countries to set production levels and the influence on oil prices and global demand;

   • Russia's military actions in Ukraine;

   • the U.S.-Venezuela conflict and the impact of potential increases in North American heavy oil supply;

   • the U.S.-Iran conflicts and uncertainty regarding the stability of any ceasefires or other de-escalation measures;

   • changes in plans with respect to exploration or development projects or capital expenditures;

   • changes in commodity prices may cause royalty rates, income taxes, general and administrative expenses or interest expense to differ materially from the Company's expectations;

   • the risk that the Company may not achieve anticipated water injection rates, anticipated Clearwater oil production or meet the capital investment guidance;

   • the risk that the Company may not be able to scale its capital program as anticipated due to market conditions or other factors;

   • the Company will not fund its capital programs on anticipated terms or timing;

   • changes in market prices for oil and natural gas;

   • uncertainties associated with estimating proved plus probable oil and natural gas reserves and the ability of the Company to realize value from its properties;

   • geological, technical, drilling and processing issues;

   • facility and pipeline capacity constraints and access to processing facilities and to markets for production;

   • fluctuations in foreign exchange or interest rates and stock market changes;

   • risk that existing tariffs and additional or expanded tariffs imposed by the

     U.S. administration and other countries on Canadian goods or other restrictive trade measures, including with respect to crude oil and natural gas, and that such measures (and/or the Canadian government's response to such measures, including countermeasures) impact the demand and/or market price for the Company's products and/or otherwise adversely affect the Company;

   • the risks related to the ongoing negotiations of the new United States-Mexico-Canada Agreement, resulting in changes to trade, tariff or market access terms that may impact the Company;

   • the risk that cash on hand, available credit and anticipated adjusted funds flow will not be sufficient to fund the Company's planned capital programs and any future acquisitions, dividends and share buybacks;

   • credit worthiness of counterparties to commodity, foreign exchange and interest rate contracts;

   • increased borrowing costs due to increased lending rates from prime rate increase and associated changes to financial metrics evaluated under the Credit Facility;

   • marketing and transportation;

   • prevailing weather and spring weather conditions;

   • environmental risks;

   • evolving climate change reporting standards and sustainability reporting requirements, and the potential impacts on the Company's operations and reporting obligations;

   • competition for, among other things, capital, acquisition of reserves, undeveloped lands and skilled personnel;

   • operating costs, transportation and future development costs;

   • the ability to access sufficient capital from internal and external sources;

   • changes in tax, royalty and environmental legislation and any government policy;

   • any legal proceedings, the results thereof and the impact on the Company's business, financial condition and results of operations;

   • third party not able to manage inflationary cost pressures;

   • changes in the political landscape, both domestically and abroad; and

   • increased operating and capital costs due to inflationary pressures (actual and anticipated).

     Readers should be aware that the foregoing list of risk factors is not exhaustive. The risk factors above should be considered in the context of current economic conditions, increased supply resulting from evolving development methods, the attitude of lenders and investors towards corporations in the energy industry, potential changes to royalty and taxation regimes and to environmental and other government regulations, the condition of financial markets generally, as well as the stability of joint venture and other business partners, all of which are outside the control of the Company. Also, to be considered are increased levels of political uncertainty and possible changes to existing international trading agreements and relationships. Legal matters relating to asset ownership, limitations to rights of access and adequacy of pipelines or alternative methods of getting production to market may also have a significant effect on the Company's business. Additional information on these and other factors that could affect the business, operations or financial results of Tamarack are included in reports on file with applicable securities regulatory authorities, including but not limited to Tamarack's Annual Information Form for the year ended December 31, 2025, which may be accessed on Tamarack's SEDAR+ profile at https://www.sedarplus.ca or on the Company's website at https://www.tamarackvalley.ca.

     This MD&A contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Tamarack's 2026 development capital program and plans regarding payment of 2026 dividends and any share buybacks by using anticipated adjusted funds flow combined with available credit facilities, commodity prices, Tamarack's 2026 capital guidance and components thereof including prospective results of operations and production, planned investment in oil and natural gas assets and expansion of the waterflood program; expected capital expenditures (including in respect of Tamarack's capital E&D budget), 2026

     annual guidance and the components thereof including capital investments and annual average production, average oil and NGL weighting, and expenses (including expected royalty rates, operating expenses, transportation expenses, leasing expenditures, carbon tax, G&A expenses, interest and income taxes), payout of wells, adjusted funds flow, net debt (and the reduction thereof) targets, capital requirements, return of capital, the Company's 2026 budget and associated targets, debt repayments, Tamarack's 2026 base capital investment program of $450 - 470 million, the combined 2026 capital investment programs of approximately $700 million, the anticipated net cash and available funding of the combined company, targeting average production range of 65,500 - 67,500 boe per day in 2026, anticipated generation of significant free cash flow in 2026 based on current strip prices, the use of free cash flow for share buybacks, dividends and debt reduction, the availability and use of credit facilities, expected commitments and contingencies of the Company over the upcoming years and the components thereof, total returns and components thereof, decline rates, and expected ongoing enhancement of operating netbacks through improved realizations and lower operating expenses, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs and the assumptions outlined under "Non-GAAP financial measures and Non-GAAP financial ratios" and "Capital management measures and ratios", and should not be used for purposes other than those for which it is reported herein. Tamarack and its management believe that the prospective financial information 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, Tamarack's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future activities or results.

     The forward-looking statements and FOFI contained in this MD&A, as defined by Canadian securities legislation, are approved by management as of the date hereof and Tamarack undertakes no obligation to update publicly or revise any forward-looking statements, forward-looking information or FOFI whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. The forward-looking statements and FOFI contained herein are expressly qualified by this cautionary statement.

     Reserves disclosure

     All references to reserves are presented on a gross basis, reflecting Tamarack's working interest before royalties. The figures are based on the independent evaluation reports of McDaniel & Associates Consultants Ltd. ("McDaniel"), dated January 21, 2026, and have an effective date of December 31, 2025. The reports were prepared in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook and contain significant estimates, assumptions and judgments relating to crude oil and natural gas reserves, production, commodity prices, future development costs and operating related expenses. These reports are subject to significant measurement uncertainty as actual results may differ from these estimates and could be material.

     Headwater's reserves referred to in this MD&A are derived from the independent evaluation of Headwater's oil and gas properties prepared by McDaniel dated January 15, 2026 and effective December 31, 2025, prepared in accordance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook, as reported in Headwater's annual information form for the year ended December 31, 2025, available on SEDAR+. Reserves of the combined company are the arithmetic sum of the two evaluations and are presented on a gross basis before royalties. There is no assurance that the forecast price and cost assumptions applied in either evaluation will be attained and variances could be material.

     Drilling locations

     This MD&A discusses drilling locations in two categories: (i) booked locations, being proved and probable locations derived from the McDaniel evaluations of Tamarack's and Headwater's properties; and (ii) unbooked locations, which do not have attributed reserves. Of Tamarack's Clearwater inventory of more than 2,000 (net) primary drilling locations, 520 (net) are proved or probable locations and the remainder are unbooked. Of Headwater's Clearwater inventory of more than 1,000 (net) primary drilling locations, 273 (net) are proved or probable locations and the remainder are unbooked. Tamarack's unbooked locations have attributed contingent or prospective resources based on the resource evaluation prepared by McDaniel effective December 31, 2025; Headwater's unbooked locations do not have attributed resources. Unbooked locations have been identified by management as an estimation of multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked locations and, if drilled, there is no certainty that such locations will result in additional reserves, resources or production. The locations on which wells are actually drilled will depend upon the availability of capital, regulatory approvals, seasonal restrictions, commodity prices, costs, actual drilling results and other factors.

     Certain oil and gas terms

     Certain terms used in this MD&A that are not otherwise defined herein are provided below:

   • reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates.

   • proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

   • probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

   • proved plus probable reserves is the sum of proved reserves and probable reserves.

   • gross means: in relation to reserves, the applicable working interest (operating or non-operating) share before royalties and without including any royalty interests; and, in relation to wells, the total number of wells in which the Company has an interest.

   • net means: in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company.

Note regarding product types

This MD&A includes references to total average daily production, crude oil production, NGLs production and natural gas production. NGLs refers to all natural gas liquids, consisting of condensate, pentanes plus, butane, propane and ethane. Natural gas refers to conventional natural gas and shale gas combined. Crude oil refers to light, medium, and heavy crude oil combined. Tamarack's Clearwater production volumes on a standalone total boe per day basis are comprised of approximately 91% heavy oil, 1% NGLs and 8% natural gas. The Charlie Lake production volumes referenced in this MD&A on a boe per day basis are comprised of approximately 55% light oil, 12% NGLs and 33% natural gas. The run-rate production volumes of the combined company are comprised of approximately 94% heavy oil and 6% natural gas. The Company's 2026 annual average production guidance of 65,500 - 67,500 boe per day is comprised of approximately 80% heavy oil, 7% light oil, 2% NGLs and 11% natural gas.

Short-term production

References in this MD&A to initial production rates and other short-term production rates 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 decrease thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers should be aware not to place reliance on such rates in calculating the aggregate production of Tamarack.

Abbreviations

Unaudited Condensed Interim Consolidated Balance Sheets (thousands of Canadian dollars)

Commitments and contingencies 9, 11

See accompanying notes to the Interim Financial Statements.

Unaudited Condensed Interim Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (thousands of Canadian dollars, except per share amounts)

See accompanying notes to the Interim Financial Statements.

Unaudited Condensed Interim Consolidated Statements of Cash Flows (thousands of Canadian dollars)

See accompanying notes to the Interim Financial Statements.

Unaudited Condensed Interim Consolidated Statements of Changes in Shareholders' Equity (thousands of Canadian dollars)

See accompanying notes to the Interim Financial Statements.

Notes to the Unaudited Condensed Interim Consolidated Financial Statements For the three and nine months ended September 30, 2026 and 2025 (thousands of Canadian dollars, unless otherwise indicated)

1. Reporting entity

   Tamarack Valley Energy Ltd. is a corporation engaged in the exploration, development, production and sale of oil and natural gas in the Western Canadian Sedimentary Basin. Tamarack is a pure-play Clearwater producer, holding an extensive inventory of primary drilling and waterflood expansion opportunities at Nipisi, Marten Hills and South Clearwater in Northern Alberta. Tamarack is a publicly-traded company on the Toronto Stock Exchange and is traded under the symbol "TVE". The Company is incorporated and domiciled in Alberta, Canada with a registered office address located at Suite 4300, 888 - 3rd Street S.W., Calgary, Alberta, T2P 5C5 and the head office address located at Suite 1700, 525 - 8th Avenue S.W., Calgary, Alberta, T2P 1G1. These unaudited condensed interim consolidated financial statements for the three and nine months ended September 30, 2026 and 2025 (the "Interim Financial Statements") were approved and authorized by the Board of Directors on October 27, 2026.

2. Basis of preparation

   These Interim Financial Statements have been prepared in accordance with IAS 34 - Interim Financial Reporting as issued by the International Accounting Standards Board. These Interim Financial Statements are condensed as they do not include all information required by IFRS Accounting Standards for annual financial statements and should be read in conjunction with Tamarack's annual financial statements for the years ended December 31, 2025 and 2024 (the "Annual Financial Statements"). These statements follow the same accounting policies as the Annual Financial Statements. They have been prepared on a historical cost basis with the exception of certain financial instruments and equity compensation units which are measured at their estimated fair value.

   These Interim Financial Statements consist of Tamarack and its subsidiaries. Intercompany balances and any income and expenses arising from intercompany transactions have been eliminated. These Interim Financial Statements are presented in Canadian dollars, which is Tamarack's functional and reporting currency.

3. Cash

   Tamarack exited the third quarter of 2026 with cash of $541.4 million, that was primarily held with four large Canadian chartered banks within the Company's lending syndicate, with no single institution holding more than 45% of the balance.

4. Receivables

   As at	September 30, 2026	December 31, 2025
   Oil and natural gas sales	$ 135,008	$ 108,807
   Joint venture billings	3,183	4,425
   Other receivables	2,486	1,016
   Accounts receivable	$ 140,677	$ 114,248

5. Oil and natural gas assets

   Cost	PP&E	E&E	Total
   Balance at December 31, 2025	$ 5,000,516	$ 82,909	$ 5,083,425
   Investments in oil and natural gas assets	311,727	921	312,648
   Non-cash capitalized costs	25,762	-	25,762
   Acquisitions	8,899	-	8,899
   Disposal of Charlie Lake assets	(1,336,750)	-	(1,336,750)
   Balance at September 30, 2026	$ 4,010,154	$ 83,830	$ 4,093,984

   Accumulated depletion and depreciation	PP&E	E&E	Total
   Balance at December 31, 2025	$ 1,867,288	$ 17,218	$ 1,884,506
   Depletion and depreciation	304,281	4,159	308,440
   Disposal of Charlie Lake assets	(561,553)	-	(561,553)
   Balance at September 30, 2026	$ 1,610,016	$ 21,377	$ 1,631,393

   Carrying amounts	PP&E	E&E	Total
   At December 31, 2025	$ 3,133,228	$ 65,691	$ 3,198,919
   At September 30, 2026	$ 2,400,138	$ 62,453	$ 2,462,591

   Sale of Charlie Lake assets

   On May 27, 2026, Tamarack entered into a purchase and sale agreement to sell its Charlie Lake assets in the Grande Prairie area for gross cash proceeds of $803.8 million before closing adjustments. The transaction had an effective date of April 1, 2026 and was completed on June 15, 2026. The Company received net proceeds of $727.9 million, net of effective date closing adjustments of $50.8 million, the unwinding of affiliated light oil risk management contracts of $13.3 million and transaction costs of $11.8 million. In connection with the sale, Tamarack derecognized $27.0 million in discounted asset retirement obligations (Note 10) and recorded a loss of $19.6 million.

   Acquisition of Headwater Exploration Inc. ("Headwater")

   On September 7, 2026, Tamarack entered into a definitive arrangement agreement with Headwater to merge in an all-stock transaction, with the combined company valued at approximately $10.0 billion ("the Transaction"). As part of the Transaction, Tamarack will acquire approximately 25,000 boe per day of Clearwater heavy oil production and greater than 100 million boe of proved plus probable reserves. Headwater shareholders will receive 1.0 common share of Tamarack for each Headwater common share held, resulting in Tamarack issuing a total of 237.8 million shares to acquire all of Headwater. Following the completion of the Transaction, Tamarack shareholders will own 66.5% of the combined company and Headwater shareholders will own 33.5% based on common share counts outstanding as at September 7, 2026. The combined company will be led by Tamarack's management team and the Transaction is expected to close in November 2026, subject to regulatory and shareholder approvals.

   In conjunction with the Transaction, certain assets located in Alberta, Saskatchewan and New Brunswick, will be transferred from Headwater and Tamarack into Tributary Exploration Inc. ("Tributary"), a newly formed exploration company. Legacy shareholders of Tamarack and Headwater will receive common shares of Tributary as a distribution, providing shareholders with continued exposure to these assets under the stewardship of the legacy Headwater management team.

6. Debt

   	Credit Facility	2030 Notes	2027 Notes	Total
   Balance at December 31, 2025	$ 151,968	$ 318,927	$ 197,433	$ 668,328
   Repayment of debt instruments, net	(152,794)	-	(200,000)	(352,794)
   Unrealized foreign exchange loss	73	-	-	73
   Amortization of deferred borrowing costs	753	994	2,567	4,314
   Balance at September 30, 2026 Maturity date	$ - May 29, 2030	$ 319,921 July 25, 2030	$ -	$ 319,921

   Credit Facility

   As at September 30, 2026, Tamarack had access to an undrawn covenant-based $875.0 million revolving lending facility (the "Credit Facility"). Amounts previously drawn under the Credit Facility were fully repaid in the second quarter of 2026 with operating cash flows and a portion of the net proceeds from the Charlie Lake sale (Note 5). The Credit Facility has an uncommitted accordion feature that provides the Company with the ability to access an incremental $125.0 million of secured debt, subject to certain conditions, including approvals from the lending syndicate.

   The incremental borrowing rate on term draws under the facility is approximately 5%, excluding deferred borrowing cost amortization. The Credit Facility bears interest at a variable market-based interest rate plus an applicable credit margin depending on the Company's senior debt to EBITDA ratio and is secured by a $2.5 billion debenture with fixed coverage over all assets of Tamarack, excluding the Clearwater Infrastructure Partnership assets (Note 8). In May 2026, Tamarack extended the Credit Facility maturity date by two years to May 29, 2030 and the facility was also amended to ease certain covenant restrictions, including the leverage ratios. As at September 30, 2026, Tamarack had $3.7 million of letters of credit issued and outstanding under the Credit Facility.

   Financial covenants on the Credit Facility as at September 30, 2026	Limit (previous)	Limit (new)	Current (actual)
   Total Debt to EBITDA ratio	<3.5:1.0	<4.0:1.0	0.4:1.0
   Senior Debt to EBITDA ratio	<3.0:1.0	<3.5:1.0	0.0:1.0
   Interest Coverage ratio	>3.0:1.0	>3.0:1.0	21.0:1.0

   2030 Notes

   During 2025, the Company issued $325.0 million aggregate principal amount of 6.875% interest-bearing senior unsecured notes maturing on July 25, 2030 (the "2030 Notes"). The 2030 Notes pay interest semi-annually and are not governed by any financial covenants. The 2030 Notes carry an effective interest rate of 7.28%.

   The Company may redeem the 2030 Notes at a cost of 103.4% of principal starting on July 25, 2027, which decreases thereafter at each subsequent anniversary date, reaching par on July 25, 2029. Prior to July 25, 2027, Tamarack can repay up to 40% of the 2030 Notes using the proceeds of an equity offering at a cost of 106.9%. The Company may also redeem the 2030 Notes at a present value cost of 103.4% plus all of the interest that would otherwise be owing from the redemption date through to July 25, 2027.

   2027 Notes

   During 2022, the Company issued $300.0 million aggregate principal amount of 7.25% interest-bearing senior unsecured notes due May 10, 2027 (the "2027 Notes"). In 2025, a portion of the net proceeds from the 2030 Notes were utilized to redeem $100.0 million of the 2027 Notes at a cost of 102.0% of principal. On May 11, 2026, Tamarack redeemed the remaining outstanding 2027 Notes at a cost of 100.75% of principal utilizing the proceeds from a Credit Facility draw. Loss on dispositions and other includes

   $3.6 million in call premiums and the acceleration of remaining unamortized deferred borrowing costs associated with the redeemed notes.

7. Risk management contracts Commodity related contracts

   As at and for the nine months ended	September 30, 2026
   Balance at December 31, 2025	$ 14,579
   Realized loss on settlements	86,960
   Change in fair market value	(164,528)
   Balance at September 30, 2026	$ (62,989)

   At September 30, 2026, Tamarack held the following derivative contracts in respect of the Company's hedging program:

   Crude oil derivatives	Q4 2026	Q1 2027	Q2 2027	Q3 2027
   WTI 2-way collar Volume (bbls/d) Average Put/Call/Premium (USD/bbl)	18,500 50.00 / 78.65 / 1.64	18,000 51.53 / 83.36 / 0.25	15,000 53.50 / 84.00 / 0.08	11,500 51.74 / 97.09 / 0.00
   WTI - WCS Hardisty Volume (bbls/d) basis swap Average Fixed Price (USD/bbl)	15,500 (13.05)	- -	- -	- -
   WCS Hardisty - WCS Volume (bbls/d) Houston swap Average Fixed Price (USD/bbl)	- -	2,000 (9.55)	- -	- -
   Natural gas derivatives				Summer 26(1)
   AECO 5A swap Volume (GJ/d) Average Fixed Price (CAD/GJ)				10,000 2.74

   (1) Summer runs from April 1 to October 31 of the given year

   Foreign exchange derivatives	Q4 2026	Q1 2027	Q2 2027	Q3 2027
   CAD/USD collar Amount (USD/month) Average Put/Call (CAD/USD)	$19,000,000 1.35 / 1.40	$13,000,000 1.34 / 1.39	$13,000,000 1.34 / 1.39	$17,000,000 1.35 / 1.41
   CAD/USD variable Amount (USD/month) collar Average Put/Call/knock-in (CAD/USD)(1)	$10,000,000 1.35 / 1.42 / 1.39	$14,000,000 1.35 / 1.42 / 1.39	$14,000,000 1.35 / 1.42 / 1.39	$14,000,000 1.35 / 1.43 / 1.40
   CAD/USD swap Amount (USD/month) Average Fixed Price (CAD/USD)	$8,000,000 1.37	$12,000,000 1.37	$12,000,000 1.37	$5,000,000 1.39

   (1) If the average rate for the month exceeds the call, Tamarack receives an average rate forward equivalent to the knock-in rate.

8. Other liabilities

   	Notes	Clearwater Infrastructure Partnership	Government loans and other	Lease liabilities	Cash-settled awards (Note 15)	Total
   Balance at December 31, 2025		$ 171,843	$ 22,241	$ 6,952	$ 29,747	$ 230,783
   Change in estimates		-	-	-	15,349	15,349
   Liabilities incurred (disposed)		-	(444)	(509)	23,529	22,576
   Payments		(19,122)	(7,361)	(1,454)	(20,586)	(48,523)
   Interest expense	14	13,040	-	326	-	13,366
   Accretion	14	413	821	-	-	1,234
   Balance at September 30, 2026		$ 166,174	$ 15,257	$ 5,315	$ 48,039	$ 234,785
   Consisting of:
   Current liability		$ 8,401	$ 12,385	$ 1,120	$ 36,763	$ 58,669
   Non-current liability		$ 157,773	$ 2,872	$ 4,195	$ 11,276	$ 176,116

   Clearwater Infrastructure Partnership

   The Clearwater Infrastructure Partnership liability reflects an Indigenous-held 85% share of Tamarack's 16-year take-or-pay commitment to the partnership for the utilization of certain infrastructure assets in the Clearwater area, which commenced in the

   fourth quarter of 2023. Tamarack holds a 15% operated share of the partnership and is responsible for all associated operating and maintenance costs. The Company has retained full access to 100% of the partnership's midstream capacity and priority access to any incremental capacity above the minimum take-or-pay commitment, where volumes can be utilized on a prescribed fee-for-service basis.

   Government loans and other

   As at September 30, 2026, the Company held interest-free government loans of $15.3 million that are repayable under the Federal Government of Canada's Emissions Reduction Fund for the construction of certain methane conservation facilities in the Company's Clearwater development area. The agreements include scheduled repayment dates within the next two years. The loans remain interest-free subject to the Company's compliance with the terms and conditions of the agreement and the pre-established repayment schedule.

9. Commitments and contingencies

   As at September 30, 2026	2026	2027	2028	2029	2030+	Total
   Senior Notes	$ -	$ -	$ -	$ -	$ 325,000	$ 325,000
   Accounts payable and accrued liabilities	206,436	8,100	-	-	-	214,536
   Clearwater Infrastructure Partnership (CIP)	2,202	9,152	10,187	8,669	140,053	170,263
   Risk management contracts	18,897	44,092	-	-	-	62,989
   Other liabilities, excluding CIP	272	50,675	13,545	3,701	1,142	69,335
   Financial liabilities on the balance sheet	227,807	112,019	23,732	12,370	466,195	842,123
   Transportation commitments	13,373	143,465	153,621	159,519	2,405,655	2,875,633
   Interest on debt and other liabilities	4,328	39,047	37,984	36,924	90,036	208,319
   Processing commitments	621	2,062	987	-	-	3,670
   Total financial commitments	$ 246,129	$ 296,593	$ 216,324	$ 208,813	$2,961,886	$3,929,745

   In August 2026, Tamarack entered into a 20-year, $2.3 billion pipeline commitment on the TMX mainline system to transport up to 25,000 bbl per day from Edmonton to the West Coast of British Columbia. Tamarack expects to commence shipping volumes on the TMX system in the first quarter of 2027, subject to the completion of the TMX's Drag Reducing Agent expansion.

   In July 2026, Tamarack also finalized a 10-year, $269.1 million commitment with a third-party to transport 22,000 bbl per day of oil production from the Company's core West Marten development area to Edmonton. The transaction included third-party construction of a LACT, storage tank and lateral pipeline connection near Tamarack's 15-15 facility to the mainline system.

   Not included in the commitments table above is a 20-year pipeline commitment that Tamarack has entered into on the proposed South Bow Prairie Connector pipeline. The arrangement will potentially allow the Company to transport up to 10,000 bbl per day from Edmonton to Cushing, Oklahoma and the U.S. Gulf Coast. The contract commitment is subject to project regulatory approval and construction and could be in-service by the end of 2028.

   Tamarack is involved in legal matters that have arisen in the normal course of business. While the final outcomes of such matters cannot be predicted with certainty and could be material, Tamarack believes that the claims are without merit. The Company also does not anticipate that any of these legal proceedings will have a material impact on Tamarack's consolidated financial position or results of operations.

10. Asset retirement obligations

    As at and for the period ended	Notes	September 30, 2026	December 31, 2025
    Balance, beginning of year		$ 134,072	$ 194,608
    Liabilities incurred		7,102	9,246
    Change in discount rates and estimates		(13,809)	(18,460)
    Liabilities settled		(2,891)	(5,441)
    Acquisitions (dispositions) (net)	5	(6,616)	(54,359)
    Revaluation of acquired liabilities		-	2,080
    Accretion	14	4,161	6,398
    Balance, end of period		$ 122,019	$ 134,072
    Consisting of:
    Current portion of asset retirement obligations		$ 18,695	$ 4,911
    Asset retirement obligations		$ 103,324	$ 129,161

    Tamarack's asset retirement obligations primarily reflect the estimated cost to dismantle, abandon, reclaim and remediate the Company's assets at the end of their useful lives. As at September 30, 2026, the Company's total undiscounted and uninflated cash

    flows required to settle its asset retirement obligations was approximately $195.0 million (Dec. 31, 2025 - $205.1 million) and the majority of the costs are expected to be incurred over the next 45 years. A risk-free rate of 4.3% (Dec. 31, 2025 - 3.9%) and an inflation rate of 2.0% (Dec. 31, 2025 - 2.0%) were utilized to measure the present value of the asset retirement obligations.

11. Shareholders' equity

    Share capital	September 30, 2026 Shares Amount		December 31, 2025 Shares Amount
    Balance, beginning of year	485,681	$ 1,642,819	522,207	$ 1,764,900
    Purchase of common shares for cancellation	(15,774)	(53,227)	(36,180)	(122,081)
    Purchase of common shares for equity compensation units	(2,424)	-	(3,239)	-
    Issuance of common shares for equity compensation units	2,770	-	2,893	-
    Balance, end of period	470,253	$ 1,589,592	485,681	$ 1,642,819

    Shareholder returns Period ended	Dividend per common share	Total dividends distributed	Shares retired through NCIB (thousands)	Total NCIB repurchases	Total shareholder distributions
    December 31, 2022	$ 0.1165	$ 55,268	-	$ -	$ 55,268
    December 31, 2023	0.1500	83,521	-	-	83,521
    December 31, 2024	0.1502	81,474	33,889	135,352	216,826
    December 31, 2025	0.1541	77,020	36,180	185,281	262,301
    September 30, 2026	$ 0.1300	62,066	15,774	189,097	251,163
    Total		$ 359,349	85,843	$ 509,730	$ 869,079

    Normal course issuer bid

    In the first quarter of 2026, Tamarack renewed its normal course issuer bid, receiving approval from the TSX to purchase up to 47.7 million common shares until January 18, 2027. During the nine months ended September 30, 2026, Tamarack purchased and retired

    15.8 million common shares at an average price of $11.99 per common share for a total repurchase cost of $189.1 million, including

    $4.0 million of federal taxes and fees. Tamarack de-recognized the net book value of the repurchased shares for $53.2 million, resulting in a net distribution from retained earnings of $135.9 million.

    On July 27, 2026, Tamarack declared a 25% increase to the quarterly dividend from $0.04 per share to $0.05 per share, commencing on September 30, 2026. Contingent upon completion of the Headwater Transaction (Note 5), Tamarack intends to increase the quarterly dividend a second time from $0.05 per share to $0.06 per share ($0.24 annualized), commencing in the fourth quarter.

    Treasury shares

    During the nine months ended September 30, 2026, the Company acquired 2.4 million common shares for $27.5 million to settle exercised share-based compensation units (year ended Dec. 31, 2025 - 3.2 million common shares for $18.2 million). As at September 30, 2026, Tamarack held 0.8 million treasury shares (Dec. 31, 2025 - 1.1 million).

12. Earnings per share Three months ended Nine months ended

    September 30	2026	2025	2026	2025
    Net income (loss)	$ 98,841	$ (248,766)	$ 310,162	$ (98,271)
    Weighted average shares outstanding - basic	472,615	496,617	478,225	505,051
    Weighted average shares outstanding - diluted	478,141	496,617	483,609	505,051
    Net income (loss) per share - basic	$ 0.21	$ (0.50)	$ 0.65	$ (0.19)
    Net income (loss) per share - diluted	$ 0.21	$ (0.50)	$ 0.64	$ (0.19)

    For the three and nine months ended September 30, 2026, 6.6 million common shares issuable upon the exercise and settlement of equity compensation units were included in the calculation of the diluted weighted average number of common shares outstanding (September 30, 2025 - 8.2 million excluded from the calculation).

13. Oil and natural gas sales Three months ended Nine months ended

    September 30	2026	2025	2026	2025
    Heavy oil	$ 460,382	$ 292,648	$ 1,276,274	$ 875,662
    Light oil	-	89,940	194,489	315,111
    Natural gas	4,658	4,684	24,909	31,037
    Natural gas liquids	3,647	6,816	20,745	24,833
    Oil and natural gas sales	$ 468,687	$ 394,088	$ 1,516,417	$ 1,246,643

14. Finance expense Three months ended Nine months ended

    September 30	Notes	2026	2025	2026	2025
    Senior Notes	6	$ 5,632	$ 8,323	$ 21,876	$ 19,111
    Credit Facility	6	1,271	4,449	6,676	17,080
    Clearwater infrastructure liability and other	8	4,058	4,537	13,295	14,114
    Interest expense		10,961	17,309	41,847	50,305
    Deferred borrowing costs and loan accretion	6, 8	1,132	4,128	3,952	9,598
    Accretion of asset retirement obligations	10	1,549	1,559	4,161	4,791
    Finance expense		$ 13,642	$ 22,996	$ 49,960	$ 64,694

15. Stock-based compensation Three months ended Nine months ended

    September 30	Notes	2026	2025	2026	2025
    Equity-settled plans		$ 5,388	$ 2,636	$ 14,071	$ 9,022
    Cash-settled plans	8	13,101	5,017	38,878	9,882
    		18,489	7,653	52,949	18,904
    Capitalized stock-based compensation	5	(4,469)	(1,785)	(10,851)	(4,236)
    Stock-based compensation expense		$ 14,020	$ 5,868	$ 42,098	$ 14,668

    Equity compensation unit continuity	RSUs	PSUs	RIAs	PIAs	Stock options	Total
    Balance at December 31, 2025	4,132	3,176	829	4,267	95	12,499
    Granted	1,107	1,335	215	1,669	-	4,326
    Exercised	(1,552)	(1,123)	(401)	(1,907)	(95)	(5,078)
    Forfeited or expired	(302)	(155)	-	-	-	(457)
    Balance at September 30, 2026	3,385	3,233	643	4,029	-	11,290
    Consisting of
    Equity-settled units	3,385	3,233	-	-	-	6,618
    Cash-settled units (Note 8)	-	-	643	4,029	-	4,672
    Units exercisable	509	663	-	-	-	1,172
    Weighted-average remaining life	1.14	1.13	1.38	1.52	-	1.29

    During the nine months ended September 30, 2026, Tamarack granted 4.3 million stock-based awards at a weighted average fair value of $10.33 per share, which was primarily based on the Company's share price at the date of grant. As at September 30, 2026, if all outstanding, unvested PSUs and PIAs were to vest with the maximum potential performance multiplier of 2.0, 6.4 million incremental units (or equivalent cash value) would be issued to unitholders. For the nine months ended September 30, 2026, actual market and non-market performance adjustment factors on vested PSUs and PIAs averaged 1.93 (year ended December 31, 2025 - 1.25).

16. Supplemental cash flow