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Clearwater Growth and Resiliency – The highly economic Clearwater asset remains a key driver of Tamarack's free funds flow growth and a significant contributor to its portfolio of long-life oil production. Continued success in primary development and the addition of cost-effective waterflood reserves led to 18% growth, while replacing 235% of production on a TPP basis. Building on previous success, waterflood reserves grew by 75%, adding over 10 MMboe⁽⁶⁾ at a TPP F&D cost of less than $6.00/boe. Tamarack remains committed to investing in enhanced oil recovery ("EOR") projects, creating ongoing opportunities for reserves expansion and value growth.

Charlie Lake Continues to Add Increased Value – The Company's Charlie Lake asset continues to deliver significant growth through impressive results and innovative development strategies, achieving a 5% increase in reserves and a 155% reserve replacement on a TPP basis. This is inclusive of ~3 MMboe⁽¹⁴⁾ of positive technical revisions based on demonstrated results from both base performance and the 2024 development program.

Contingent and Prospective Resource Evaluation – Tamarack retained McDaniel to evaluate the heavy oil contingent and prospective resources of the Company's Clearwater assets as at December 31, 2024 (the "Resource Report").

• The Resource Report indicates Tamarack's Clearwater heavy oil assets have a "best estimate" of Company gross Contingent Resources (unrisked) of 106 MMbbl⁽¹⁵⁾ and Company gross Prospective Resources (unrisked) of 98 MMbbl⁽¹⁶⁾.
  
  

• The Resource Report exemplifies the Company's continued progression of delineating its vast resource base. At year-end 2024, promotion of oil volumes from Other Resources Categories resulted in the addition of 22.4 MMbbl⁽¹⁵⁾ to TPP reserves and 33.4 MMbbl⁽¹⁶⁾ to Contingent Resources (unrisked).
  
  

• The Resource Report includes 635 net Contingent and 1,035 net Prospective drilling locations, representing primary development inventory attributed to the Company's Clearwater assets. When combined with the Company's 401 net TPP locations included in the year-end evaluation, Tamarack's identified Clearwater inventory exceeds 2,000 locations. At the current rate of development this would imply upwards of 20 years of drilling on the Clearwater asset base.
  
  

• With the Clearwater assets producing approximately 14 MMbbl of heavy oil in 2024, TPP reserves represent nine years of equivalent production. Unrisked best estimate contingent and prospective resources equate to approximately eight and seven years of equivalent production, respectively which affords incremental visibility to future opportunities.
  
  

• See "Reader Advisories - Resource Disclosure" below and our supplementary filing titled "Statement of Contingent and Prospective Resources" dated February 11, 2024 which has been filed on SEDAR+ at www.sedarplus.ca for additional details with respect to Tamarack's contingent and prospective resources, including the risks and uncertainties related thereto.

Non-core Asset Divestment

In Q4/24, Tamarack entered into a definitive agreement to divest its Penny Barons assets in southern Alberta for $28MM (before closing adjustments), including ~900 boe/d⁽¹⁷⁾ of production, with the transaction expected to close in early 2025. Proceeds from the sale will be initially utilized to advance Tamarack's debt reduction strategy to further enhance the Company's financial flexibility.

Risk Management

The Company takes a systematic approach to manage commodity price risk and volatility to ensure sustaining capital, debt servicing requirements and the base dividend are protected through a prudent hedging management program. For 2025, approximately 40% of net after royalty oil production is hedged against WTI with an average floor price of ~US$63/bbl with structures that allow for upside price participation averaging ~US$84/bbl. Our strategy provides protection to the downside while maximizing upside exposure. Additional details related to current hedges in place can be found in the corporate presentation on Tamarack's website (www.tamarackvalley.ca).

2024 Independent Qualified Reserve Evaluations

The following tables highlight the findings of the Reserve Reports, which have been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the most recent publication of the Canadian Oil and Gas Evaluation Handbook ("COGEH") by McDaniel and GLJ, qualified independent reserves evaluators, each with an effective date of December 31, 2024 and preparation dates of January 20, 2025 and January 8, 2025, respectively. All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. The information included in the "Net Present Values of Future Net Revenue Before Income Taxes Discounted" table below is based on an average of pricing assumptions prepared by the following three independent external reserves evaluators: GLJ, Sproule Associates Limited and McDaniel (the "3-Consultant Average Forecast Pricing"). It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. Note that columns may not add due to rounding.

Company Reserves Data (Forecast Prices and Costs)^(18)(19)(20)

Net Present Values of Future Net Revenue before Income Taxes Discounted at (% per year)⁽¹⁸⁾

Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs⁽¹⁸⁾

Future Development Capital Costs⁽¹⁰⁾

The following is a summary of estimated FDC required to bring TP and TPP undeveloped reserves on production.

Finding, Development & Acquisition Costs

About Tamarack Valley Energy Ltd.

Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake and Clearwater plays in Alberta while also pursuing EOR upside in these core areas. For more information, please visit the Company's website at www.tamarackvalley.ca.

Abbreviations

Reader Advisories

Notes to News Release

1. Production of 66,104 boe/d: 39,341 bbl/day heavy oil, 13,822 bbl/d light and medium oil, 2,841 bbl/d NGL and 60,602 mcf/d natural gas.

2. Production of 64,331 boe/d: 38,082 bbl/day heavy oil, 14,271 bbl/d light and medium oil, 2,556 bbl/d NGL and 56,529 mcf/d natural gas.

3. Production of 41,269 boe/d: 38,058 bbl/day heavy oil, 258 bbl/d NGL and 17,718 mcf/d natural gas.

4. Production of 16,963 boe/d: 9,242 bbl/d light and medium oil, 2,213 bbl/d NGL and 33,046 mcf/d natural gas.

5. Capital expenditures of ~$440MM exclude amounts attributed to the Clearwater Infrastructure Limited Partnership and ARO spending.

6. Waterflood TPP reserves growth of 10 MMboe comprised of 10 MMbbl heavy oil.

7. PDP reserves of 70 MMboe comprised of 18 MMbbl light and medium oil, 39 MMbbl heavy oil, 3 MMbbl NGL and 61,038 MMcf natural gas.

8. TP reserves of 140 MMboe comprised of 40 MMbbl light and medium oil, 76 MMbbl heavy oil, 6 MMbbl NGL and 112,670 MMcf natural gas.

9. TPP reserves of 243 MMboe comprised of 74 MMbbl light and medium oil, 124 MMbbl heavy oil, 11 MMbbl NGL and 206,009 MMcf natural gas.

10. FDC as per Reserve Report based on the 3-Consultant Average Forecast Pricing

11. The calculation of F&D costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the F&D number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

12. See "Specified Financial Measures"

13. Utilizing a 10% discount 3-Consultant Average Forecast Pricing.

14. 3 MMboe comprised of 1.4 MMbbl light and medium oil, 0.8 MMbbl NGL and 5 MMcf natural gas.

15. The estimate of Contingent Resources has not been adjusted for risk based on the chance of development. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. See "Resource Disclosure".

16. The estimate of Prospective Resources has not been adjusted for risk based on the chance of discovery or the chance of development. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Prospective resources are not evaluated for economics. See "Resource Disclosure".

17. Production of 900 boe/d: 760 bbl/d light and medium oil, 9 bbl/d NGL and 790 mcf/d natural gas.

18. Based on the 3-Consultant (represented by: GLJ, Sproule Associates Limited and McDaniel) Average Forecast Pricing as at January 1, 2025.

19. Company Gross Reserves are defined as working interest share of reserves prior to royalty deductions.

20. Company Net reserves are defined as working, net carried, and royalty interest reserves after royalty deductions.

21. Immaterial Tight Oil volumes have been included with light & medium crude oil volumes.

22. Condensate volumes have been included with natural gas liquids.

23. Unit values are based on Company net reserves.

24. Reserves additions under Infill Drilling, Improved Recovery and Extensions are combined and reported as "Extensions and Improved Recovery".

25. While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company's cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above.

26. Reserves are Company Gross Reserves.

Unaudited Financial Information

Certain financial and operating results included in this news release, including operating netbacks, capital expenditures and production information, are based on unaudited estimated results. These estimated results are subject to change upon completion of the Company's audited financial statements for the year ended December 31, 2024, and changes could be material. Tamarack anticipates filing its audited financial statements and related management's discussion and analysis for the year ended December 31, 2024, on or near February 25, 2025.

Disclosure of Oil and Gas Information

AIF. Tamarack's Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 dated effective as at December 31, 2024, which will include further disclosure of Tamarack's oil and gas reserves and other oil and gas information in accordance with NI 51-101 and COGEH forming the basis of this news release, will be included in the AIF which will be available on SEDAR+ at www.sedarplus.ca on or near February 25, 2025.

Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with NI 51-101. Boe may be misleading, particularly if used in isolation.

Product Types. References in this news release to "crude oil" or "oil" refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to "NGL" throughout this news release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51-101. References to "natural gas" throughout this news release refers to conventional natural gas as defined by NI 51-101.

Reserves and Future Net Revenue Disclosure. All reserves values, future net revenue and ancillary information contained in this news release are derived from the Reserve Reports unless otherwise noted. All reserve references in this news release are "Company Gross Reserves". Company Gross reserves defined as working interest share of reserves prior to royalty deductions. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by GLJ and McDaniel in evaluating Tamarack's reserves will be attained and variances could be material. All reserves assigned in the Reserve Reports are located in the Province of Alberta and presented on a consolidated basis.

All evaluations and summaries of future net revenue are stated prior to the provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The recovery and reserve estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only.

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 developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. Certain terms used in this news release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101, Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.

Resource Disclosure. Tamarack's heavy oil Clearwater contingent resource and prospective resource estimates contained herein were derived from the Resource Report prepared by McDaniel, a qualified independent resource evaluator, effective as of December 31, 2024, in accordance with the definitions, standards and procedures contained in NI 51-101 and COGEH. The contingent and prospective resources estimates of Tamarack's Clearwater heavy oil contingent resources provided herein are estimates only and there is no guarantee that the estimated prospective and contingent resources will be recovered. Actual resources may be greater than or less than the estimates provided herein and the differences may be material. Tamarack's Statement of Contingent and Prospective Resources dated February 11, 2025, which has been filed on SEDAR+ at www.sedarplus.ca, includes further disclosure of Tamarack's contingent and prospective resources, including the risks and uncertainties related thereto. Contingent resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as "contingent resources" the estimated discovered recoverable quantities associated with a project in the early project stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates, assuming their discovery and development, and may be subclassified based on project maturity. Estimates of prospective resources have not been adjusted for risk based on the chance of discovery or the chance of development. Resources are classified according to degree of certainty associated with those estimates. In this news release, "best estimate" classification is used which is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources identified as best estimate have a 50 percent probability that the actual quantities recovered will equal or exceed the estimate.

Drilling Locations. This news release discloses Clearwater drilling locations two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved and probable locations derived from the McDaniel Reserve Report prepared in accordance with NI 51-101 and the most recent publication of the COGE Handbook. Unbooked locations do not have attributed reserves. However, the unbooked Clearwater locations have attributed contingent or prospective resources, based on the Resource Report. Of the Clearwater inventory of 2,071 net drilling locations identified herein, 401 net are proved or probable locations, and 1,670 net are unbooked locations. Unbooked locations have been identified by management as an estimation of our 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 drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

Oil and Gas Metrics. This news release contains metrics commonly used in the oil and natural gas industry, such as development capital, F&D costs, FD&A costs and recycle ratio.

"Development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital presented herein excludes land and capitalized administration costs but includes the cost of acquisitions and capital associated with acquisitions where reserve additions are attributed to the acquisitions.

"Finding and development costs" or "F&D costs" are calculated as the sum of field capital plus the change in FDC for the period divided by the change in reserves that are characterized as development for the period and "finding, development and acquisition costs" are calculated as the sum of field capital plus acquisition capital plus the change in FDC for the period divided by the change in total reserves, other than from production, for the period. Both finding and development costs and finding development and acquisition costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Finding and development costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on Tamarack's ongoing reserves replacements costs and excluding these amounts could result in an inaccurate portrayal of the Company's cost structure.

"Finding, development and acquisition costs" or "FD&A costs" incorporate the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

"Recycle ratio" is measured by dividing the operating netback for the applicable period by F&D cost per boe for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves.

These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Tamarack's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

Forward Looking Information

This news release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words suggesting future outcomes. More particularly, this news release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; the Company's exploration and development plans and strategies; dividends and share buybacks; oil and natural gas production levels, adjusted funds flow and free funds flow; anticipated operational results for 2025 including, but not limited to, estimated or anticipated production levels, capital expenditures, drilling plans and infrastructure initiatives, including on-stream timing of the new CSV Albright sour gas plant in the Charlie Lake and anticipated margin improvements; the Company's capital program, guidance for 2025 and the funding thereof; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; EOR, including waterflood initiatives and long term net asset value capture; the continued successful integration of acquired assets; the ability of the Company to achieve drilling success consistent with management's expectations; risk management activities; ARO reduction; risk management activities, including hedging positions and targets; Tamarack's continued capital flexibility under its 2025 capital program; the completion of the Penny Barons asset disposition and expectation that this will not impact 2025 production guidance; and the source of funding for the Company's activities including development costs. Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the Company's return of capital framework and the funds available for such activities from time to time is dependent upon, among other things, free funds flow financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tamarack to pay dividends and buyback shares will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility. In addition, statements related to "reserves", "contingent resources" and "prospective resources" are deemed to be forward-looking information as they involve the implied assessment, based on certain estimates and assumptions, that the resources can be discovered and profitably produced in the future.

The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack; the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack's properties; the continued successful integration of acquired assets into Tamarack's operations; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products; the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the drilling, completion and tie-in of wells being completed as planned; the performance of new and existing wells; the application of existing drilling and fracturing techniques; prevailing weather and break-up conditions; royalty regimes and exchange rates; impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack's ability to execute its plans and strategies.

Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production, delivering on 2025 guidance; the risk that future dividend payments thereunder are reduced, suspended or cancelled; unforeseen difficulties in integrating of recently acquired assets into Tamarack's operations; incorrect assessments of the value of benefits to be obtained from acquisitions and exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); the risk that the new U.S. administration imposes tariffs on Canadian goods, including crude oil and natural gas, and that such tariffs (and/or the Canadian government's response to such tariffs) adversely affect the demand and/or market price for the Company's products and/or otherwise adversely affects the Company; that Tamarack will continue to conduct our operations in a manner consistent with past operations except as specifically noted herein (and for greater certainty, the forward-looking information contained herein excludes the potential impact of any acquisitions or dispositions that the Company may complete in the future); commodity prices, including the impact of the actions of OPEC and OPEC+ members; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; health, safety, litigation and environmental risks; access to capital; and pandemics. In addition, ongoing military actions in the Middle East and between Russia and Ukraine have the potential to threaten the supply of oil and gas from those regions. The long-term impacts of the actions between these nations remains uncertain. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the AIF for the year ended December 31, 2023, and the MD&A for the period ended September 30, 2024, for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca. The forward-looking statements contained in this news release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

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

Specified Financial Measures

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

"Net Production Expenses, Operating Netback and Operating Field Netback (Non-IFRS Financial Measures, and Non-IFRS Financial Ratios if calculated on a per boe basis)" – Management uses certain industry benchmarks, such as net production expenses, operating netback and operating field netback, to analyze financial and operating performance. Net production expenses are determined by deducting processing income primarily generated by processing third party volumes at processing facilities where the Company has an ownership interest. Under IFRS this source of funds is required to be reported as income. Where the Company has excess capacity at one of its facilities, it will process third party volumes as a means to reduce the cost of operating/owning the facility, and as such third-party processing revenue is netted against production expenses in the MD&A. Operating netback equals total petroleum and natural gas sales (net of blending), including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties, net production expenses and transportation expense. Operating field netback equals total petroleum and natural gas sales, less royalties, net production expenses and transportation expense. These metrics can also be calculated on a per boe basis, which results in them being considered a non-IFRS financial ratio. Management considers operating netback and operating field netback important measures to evaluate Tamarack's operational performance, as it demonstrates field level profitability relative to current commodity prices.

"Operating Netback" is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity, interest rate and foreign exchange derivative contracts, less royalties and net production and transportation costs. "Operating Field Netback" is calculated as total petroleum and natural gas sales, less royalties and net production and transportation costs.

SOURCE Tamarack Valley Energy Ltd.

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