Earnings release
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TSX: TVE Tamarack Valley Energy Achieves Record Quarterly Oil Production Driven by Clearwater Waterflood Success and Announces 2025 Investor Day Calgary, Alberta – May 7, 2025 – Tamarack Valley Energy Ltd. (“ Tamarack” or the “ Company”) (TSX: TVE) is pleased to announce its financial and operating results for the three months ended March 31, 2025 . Selected financial and operating information should be read with Tamarack’s unaudited consolidated financial statements and related management’s discussion and analysis (“MD&A”) for the three months ended March 31, 2025, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack’s website at www.tamarackvalley.ca. Tamarack’s first quarter 2025 results continue to carry momentum forward noting significant growth in both production and free funds flow (“FFF”)(1). Relative to the same quarter last year, the Company’s Clearwater assets delivered a 15% increase in production , with waterflood investment providing stronger response s than previously anticipated and further mitigating declines on the base production. In addition, with acceleration of onstream timing and continued well outperformance, the Charlie Lake delivered a 6% production increase YoY. Strong operational performance is being backstopped by higher margins and lower costs, providing increases to FFF(1) per share and returns which are further enhanced by ongoing share buybacks. Q1 2025 Financial and Operational Highlights • Free Funds Flow (1) Per Share Growth – Delivered Q1/25 adjusted funds flow (“ AFF”)(1) of $226MM or $0.44/share, increasing by 33% YoY. Including capital spending Tamarack generated Q1/25 FFF(1) of $91MM or $0.18/share, versus $52MM or $0.09/share in Q1/24, representing a 100% per share increase YoY. • Increased Shareholder Returns – Bought back 12.5MM common shares, representing a 2.4% reduction relative to the 202 4 YE shares outstanding. Over the past 12 -months, Tamarack has returned $246MM to shareholders in the form of dividends and share buybacks. • Production Outperformance – Q1/25 production averaged 67,697 boe/d(2), and was highlighted by a new Company quarterly liquids production record of 57,594 bbl/d(3). • Heavy Oil Margin Strength – Higher margins reflected improved heavy oil price realizations from ongoing marketing initiatives as operating netbacks improved by 8% YoY . Heavy oil price differentials, net of transportation, relative to the WCS benchmark, improved by 13% in Q1/25 to $4.96/bbl versus Q1/24. • Continued Cost Improvements – Production expense of $7.76/boe for Q1/25 demonstrated a 23% YoY improvement. Higher production combined with lower trucking costs from waterflood reinjection, lower energy costs, enhanced pipeline connections , operational Clearwater synergies , and the disposition of higher cost assets were key contributing factors. • Capital and Operational Efficiencies – Capital expenditures of $133MM reflected ongoing Clearwater and Charlie Lake development during the quarter . In addition , the Company invested $5MM on additional Clearwater lands. Better than forecast capital efficiencies have enabled the Company to redirect incremental capital into the Clearwater waterflood. Expansion of the waterflood program is expected to more than double 2024 exit water injection volumes with rates increasing to ~30,000 bbl/d by 2025 year-end. • Balance Sheet Strength – Tamarack continued to reduce net debt through Q1/25 , exiting the quarter with ~$400MM of undrawn credit capacity. On a 12-month trailing basis the net debt to EBITDA (1) multiple at the end of the quarter was 0.7x.
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2 Q1 2025 Financial & Operating Results Three months ended March 31, December 31, 2025 2024 % change 2024 % change ($ thousands, except per share amounts) Oil and natural gas sales $ 444,288 $ 393,336 13 $ 426,482 4 Cash provided by operating activities 187,553 165,201 14 201,798 (7) Per share – basic(1) 0.36 0.30 20 0.38 (5) Per share – diluted(1) 0.36 0.30 20 0.38 (5) Adjusted funds flow(1) 226,146 181,556 25 223,431 1 Per share – basic(1) 0.44 0.33 33 0.42 5 Per share – diluted(1) 0.43 0.33 30 0.42 2 Free funds flow(1) 90,693 51,811 75 89,208 2 Per share – basic(1) 0.18 0.09 100 0.17 6 Per share – diluted(1) 0.17 0.09 89 0.17 - Net income (loss) 64,258 (32,744) nm 6,382 nm Per share – basic 0.12 (0.06) nm 0.01 nm Per share – diluted 0.12 (0.06) nm 0.01 nm Net debt(1) 768,625 984,768 (22) 775,438 (1) Investments in oil and natural gas assets 132,731 128,221 4 127,311 4 Weighted average shares outstanding Basic 515,306 552,345 (7) 529,136 (3) Diluted 520,368 555,595 (6) 533,845 (3) Average daily production Heavy oil (bbls/d) 40,383 36,255 11 39,341 3 Light oil (bbls/d) 14,204 15,270 (7) 13,822 3 NGL (bbls/d) 3,007 1,925 56 2,841 6 Natural gas (mcf/d) 60,616 51,431 18 60,602 - Total (boe/d) 67,697 62,022 9 66,104 2 Average sale prices Heavy oil ($/bbl) $ 83.03 $ 76.36 9 $ 79.69 4 Light oil ($/bbl) 92.78 86.52 7 94.30 (2) NGL ($/bbl) 35.13 42.54 (17) 32.84 7 Natural gas ($/mcf) 2.64 2.93 (10) 1.71 54 Total ($/boe) 72.92 69.69 5 70.12 4 Benchmark pricing West Texas Intermediate (US$/bbl) 71.42 76.96 (7) 70.27 2 Western Canadian Select (WCS) (C$/bbl) 84.30 77.77 8 80.74 4 WCS differential (US$/bbl) 12.67 19.31 (34) 12.56 1 Edmonton Par (Cdn$/bbl) 95.33 92.15 3 94.90 - Edmonton Par differential (US$/bbl) 4.98 8.65 (42) 2.42 106 Foreign Exchange (USD to CAD) 1.43 1.35 6 1.40 2 Operating netback ($/Boe) Realized sales price 72.92 69.69 5 70.12 4 Royalty expenses (14.11) (13.46) 5 (13.42) 5 Net production expenses(1) (7.76) (10.06) (23) (7.16) 8 Transportation expenses (3.68) (4.18) (12) (3.30) 12 Operating field netback ($/Boe)(1) 47.37 41.99 13 46.24 2 Realized commodity hedging gain (loss) (1.74) 0.37 nm (1.59) 9 Operating netback ($/Boe)(1) $ 45.63 $ 42.36 8 $ 44.65 2 Adjusted funds flow ($/Boe)(1) $ 37.12 $ 32.17 15 $ 36.74 1
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3 2025 Outlook The Company’s 2025 guidance remains unchanged, targeting average production of 65,000 to 67,000 boe/d (4) for the full year. Management expects production to trend towards the high -end of the annual guidance range given the production performance to date, characterized by strong reservoir response and decline mitigation on the base production owing to the Clearwater waterflood and outperformance of the Q1/25 Charlie Lake program. The capital investment outlook is currently trending towards the low -end of guidance, driven by ongoing capital efficiencies from expanded multi-well pad development schemes and the resultant cost savings . The lower end of the capital guidance includes incremental Clearwater waterflood scope that will see water injection volumes more than double on a YoY exit basis, to ~30,000 bbl/d. Tamarack remains nimble, with the ability to scale its 2025 capital program in response to near -term market volatility. As such, the Company has identified certain projects that could be deferred with minimal impacts to 2025 production. Relative to budget, from a FFF(1) perspective, higher production, continued margin improvements and enhanced capital efficiencies have combined to offset commodity price pressures experienced year to date. The Company’s 2025 guidance is unchanged and summarized in the table below. Units 2025 Guidance 2025 Capital Budget(5) $MM $430 – $450 Annual Average Production(4) boe/d 65,000 – 67,000 Average Oil & NGL Weighting % 83% – 85% Expenses: Royalty Rate (%) % 20% – 22% Wellhead price differential – Oil(6) $/bbl $1.50 – $2.50 Production(7) $/boe $8.40 – $8.90 Transportation $/boe $3.75 – $4.25 General and Administrative (8) $/boe $1.30 – $1.45 Interest(9) $/boe $2.90 – $3.30 Income Taxes(10) % 10% - 12% Operations Update Clearwater Clearwater production of 44,560 boe/d(11) (91% oil & liquids) in Q1/25 increased by 5,950 boe/d(12) or 15% YoY compared to Q1/24 . Growth in the play is being driven by robust drilling results, waterflood outperformance and continued strength in base volumes. During Q1/25, Tamarack drilled 29 (27.3 net) Clearwater heavy oil wells and 3 (3.0 net) water injection wells. The Company is increasing water injection across its Clearwater asset base, having achieved ~15,000 bbl/d during the quarter. Leveraging efficiency gains , Tamarack expects to continue ramping up injection through the year . Reflecting further decline mitigation, as the waterflood response occurs earlier in the development plan, Tamarack expects to accelerate the reduction of sustaining capital and growth in FFF(1) generation capability. Tamarack continues to observe outperformance from multiple waterflood patterns at Marten Hills and Nipisi. Oil production from the 102/15-02-075-25W4 Marten Hills pattern is ramping , reaching 389 bbl/d in March. This was the highest monthly rate since commencing injection in September 2021. Following recent optimization work, the well tested at >500 bbl/d, achieving a rate ~400 bbl/d higher than its primary baseline. The adjacent 16 -2 pattern, implemented in January 2024, is currently producing ~100 bbl/d above its primary baseline as it continues to ramp up. Tamarack's first "W" pattern at 102/1 -11-74-25W4 at Marten Hills has sustained performance at 175 bbl/d above its primary baseline, outpacing initial expectations for response time and peak oil rate. At Nipisi, the Company is observing a strong oil resp onse from the 100/11 -24-076-08W5 pattern, which is now testing in excess of 500 bbl/d and trending >200 bbl/d above its baseline. In aggregate, the Nipisi waterflood program is delivering oil volumes that are >1,500 bbl/d above primary expectations. Capital efficiencies continue to improve, benefitting from the enhanced scale of the Company’s Clearwater holdings and larger pad sizes that are accessing stacked pay across the asset. In 2025 , Tamarack ’s development plan includes approximately seven wells per pad occupation versus approximately four wells per pad occupation over
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4 the prior three years. This approach is being deployed to optimize success realized in the stacked West Marten ‘B’ and ‘C’ sands, which are being developed concurrent with associated waterflood implementation. As part of the Q1/25 capital program, Tamarack drilled eight of 23 planned wells on the 14-14-076-05W5 pad, that will target the ‘B’ and ‘C’ sands in West Marten. This pad design includes 12 producing multi-lateral wells, 10 water injection wells and one water source well, with drilling expected to be completed in early June. Tamarack conducts simultaneous operations to ensure short cycle times as production from the multi -well pad is maintained while drilling of the injector and source wells is executed. Increased development scale, facilitated in part by stacked targets, contributed to realizing 10% drilling performance improvement and ~$5/meter cost savings relative to Q1/24 . These realized efficiencies allow the Company to redirect savings to additional Clearwater waterflood projects, while continuing to trend to the lower end of annua l capital guidance ranges. Charlie Lake Tamarack’s Charlie Lake asset saw increased activity in Q1/25, drilling 7 (5.8 net) horizontal wells in the quarter. All 5 (5.0 net) operated wells from this group were also able to be completed and br ought onstream before the end of March, leveraging capacity at operated infrastructure in the Wembley area and efficient execution. Charlie Lake production of 17, 780 boe/d(13) (69% oil & liquids) in Q1/25 increased by 99 0 boe/d(14) or 6% versus Q1/24. Production during the quarter benefitted from 5 (5.0) net wells drilled in Q4/24 coming onstream in January that delivered stronger than expected well performance . In addition, Tamarack achieved quick cycle times on the aforementioned 5 (5.0 net) operated wells drilled in Q1/25. The Company continues to leverage existing capacity and maintains its drill to fill strategy to manage capital deployment within the play. Production from the Charlie Lake is expected to moderate through the balance of the year as Tamarack awaits the start-up of the CSV Albright gas plant. With temporary alternate egress arrangements in place, the 2025 average production outlook remains unchanged alongside plans to run a continuous one rig program in Charlie Lake for H2/25. Risk Management The Company takes a systematic approach to manag ing 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 the remainder of 2025, approximately ~36% of net after royalty oil production is hedged against WTI with an average floor price of ~US$62/bbl with structures that allow for upside price participation at prices that average above ~US$83/bbl. Our strategy provides protection to the downside while retaining upside exposure. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca). Investor Day 2025 We are pleased to announce that Tamarack will be hosting an Investor Day on Wednesday, June 25, 2025, from 9:30 – 11:00am MT (11:30am – 1:00pm ET). Virtual participation will be available by webcast and registration will be accessible on Tamarack’s website in advance of the event with a link to be provided on our “Event Calendar” page on Tamarack’s website. We would like to thank our employees, shareholders and other stakeholders for their ongoing support. Tamarack continues to execute its five-year plan, with success and results driven by the dedication and hard work of our employees. We look forward to cont inuing to develop our high -quality assets to create long-term, sustainable shareholder value. Investor Call 9:30 AM MST (11:30 AM EST) Tamarack will host a webcast at 9: 30 AM MST (11:30 AM EST) on Wednesday May 7, 2025, to discuss the Q1 2025 financial results. Participants can access the live webcast via thi s link or through links provided on the Company’s website. An archive of the webcast will be made available on the Company’s website.
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5 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 stab ility 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 AECO the natural gas storage facility located at Suffield, Alberta connected to TC Energy's Alberta System bbls barrels bbls/d barrels per day boe barrels of oil equivalent boe/d barrels of oil equivalent per day bopd barrels of oil per day CGU cash generating unit CIP Clearwater Infrastructure Limited Partnership DCET drilling, completions, equip and tie-in costs EOR enhanced oil recovery GJ gigajoule IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board Mcf thousand cubic feet mcf/d thousand cubic feet per day MM Million MMcf/d million cubic feet per day WCS Western Canadian Select, the benchmark for conventional and oil sands heavy production at Hardisty in Western Canada MSW Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil in Western Canada NGL Natural gas liquids WTI West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade YoY year-over-year Notes to Press Release 1) See “Specified Financial Measures” 2) 67,697 boe/d: 14,204 bbl/d light & medium oil, 40,383 bbl/d heavy oil, 3,007 bbl/d NGL, 60,616 mcf/d natural gas. 3) 57,594 bbl/d: 14,204 bbl/d light and medium oil, 40,383 bbl/d heavy oil, 3,007 bbl/d NGL. 4) 65,000 – 67,000 boe/d: 39,150-40,350 bbl/d heavy oil, 13,30 0-13,700 bbl/d light and medium oil, 2,300 -2,360 bbl/d NGL and 61,550-63,550 mcf/d natural gas. 5) 2025 annual guidance numbers are based on 2025 Budget average pricing assumptions of: Crude Oil – WTI ($US/bbl) $70.00 Crude Oil – MSW Differential ($US/bbl) ($4.00) Crude Oil – WCS Differential ($US/bbl) ($14.00) Natural Gas – AECO ($CAD/GJ) $2.00 Foreign Exchange – USD/CAD 1.35 6) Oil wellhead deductions for grade specific trading differential (ex CHV), blending requirements, quality differential, and pipeline tolls if Tamarack is not marketing (lease transactions). 7) Production expense budget includes the “CIP” fee for service and minimal carbon tax. 8) G&A noted excludes the effect of cash settled stock-based compensation. 9) Budgeted interest includes CIP take-or-pay capital fee. 10) Tamarack estimates a tax rate as a percentage of adjusted funds flow. 11) 44,560 boe/d: 40,390 bbl/d heavy oil, 305 bbl/d NGL and 13,190 mcf/d natural gas. 12) 5,950 boe/d: 4,186 bbl/d heavy oil, 2,640 bbl/d NGL and 10,000 mcf/d natural gas. 13) 17,780 boe/d: 9,600 bbl/d light and medium oil, 2,640 bbl/d NGL and 33,240 mcf/d natural gas. 14) 990 boe/d: -156 bbl/d light and medium oil, 1,010 bbl/d NGL and 820 mcf/d natural gas.
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6 Reader Advisories Notes to Press Release Disclosure of Oil and Gas Information 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 Canadian Securities Administrators' National Instrument 51 -101 - Standards of Disclosure for Oil and Gas Activities ("NI 51 -101"). Boe may be misleading, particularly if used in isolation. Product Types. References in this press 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 press release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51 -101. References to "natural gas" throughout this press release refers to conventional natural gas as defined by NI 51-101. 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, share buybacks and debt reduction; 2025 budget, outlook and guidance, including Tamarack’s continued capital flexibility under its 2025 capital program; anticipated operational results for 2025 including, but not limited to, estimated or anticipated production levels, capi tal expenditures, drilling and conversion plans and infrastructure initiatives and anticipated margin improvements; the anticipated on-stream timing of the new CSV Albright sour gas plant in the Charlie Lake; expectations regarding commodity prices; the pe rformance characteristics of the Company’s oil and natural gas properties; EOR, including the acceleration of waterflood initiatives and decline mitigation; the ability of the Company to achieve drilling success consistent with management’s expectations; r isk management activities, including hedging positions and targets; 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 (includ ing the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility. The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack; the timing of and success of future drilling, conversion, development and completion activities; the geological characteristics of Tamarack's properties; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products; the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the performance of new and existing wells; the application of existing drilling and fracturing techniques; the Company's ability to secure sufficient amounts of water; prevailing weather and break -up conditions; royalty regimes and exchange rates; impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or gr ow 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 the ir 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 respec t of safety, asset integrity and shutting-in production; the risk that future dividend payments thereunder are reduced, suspended or cancelled;
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7 incorrect assessments of the value of benefits to be obtained from exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); the risk that (i) ongoing negotiations between the U.S. and Canadian governments are not successful and one or both of such governments maintain tariffs, increase the rate or scope of tariffs, or impose new tariffs on the import of goods from one country to the other, including on oi l and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company; commodity prices, including the impact of the actions of OPEC and OPEC+ members; 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; acce ss 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 re mains uncertain. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the most recent annual information form of the Company and the MD&A, 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 flow, dividends, share buybacks, debt reduction, prospective results of operations and production (including annual average production, average oil & NGL weighting), hedging, operating costs, 2025 capital guidance, 2025 annual budget and budget pricing, 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, differe nces 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 press 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 st andardized meaning prescribed by International Financial Reporting Standards ("IFRS") and, therefore, may not be comparable with the calculation of similar measures by other companies. "Adjusted funds flow (capital management measure)" is calculated by taking cash -flow from operating activities, on a periodic basis, deducting current income tax expense and interest expense (excluding fees) and adding back income tax paid, interest paid, changes in non -cash working capital, expenditures o n decommissioning obligations and transaction costs settled during the applicable period. Tamarack believes the timing of collection, payment or incurrence of these items is variable and that adjusting for estimated current income taxes and interest in the period expensed is a better indication of the adjusted funds generated by the Company. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of the Company's operating areas. Expenditures on decommissioning obligations are managed through the capital budgeting process which considers available adjusted funds flow. Tamarack uses adjusted funds flow as a key measure to demonstrate the Company's ability to generate funds to repay debt, pay dividends and fund future capital investment. Adjusted funds flow per share is calculated using the same weighted average basic and diluted shares that are used in calculating income per share, which results in the measure
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8 being considered a supplemental fin ancial measure. Adjusted funds flow can also be calculated on a per boe basis, which results in the measure being considered a supplemental financial measure. "Differential including transportation expense " The calculation of the Company's heavy oil differ ential including transportation expenses is presented in the " Oil and natural gas sales" section of the MD&A and is determined by comparing the Company's realized price to the published benchmark price, plus transportation expenses. The Company and others utilize these performance measures to assess the value of net rev enue received by Tamarack for each barrel sold relative to the published market price during that period. "EBITDA (non-IFRS financial measure) " is calculated as consolidated net income (loss) before interest and financing expenses, income taxes, depletion , depreciation and amortization, adjusted for certain non -cash, extraordinary and non -recurring items primarily relating to unrealized gains and losses on financial instruments and impairment losses. The Company considers this metric as key measures that d emonstrate the ability of the Company's continuing operations to generate the cash flow necessary to maintain production at current levels and fund future growth through capital investment and to service and repay debt. The most directly comparable IFRS measure to EBITDA is cash provided by operating activities. "Free funds flow (capital management measure) " is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Management believes that free funds flow provides a useful measure to determine Tamarack's ability to improve returns and manage long-term value of the business. "Net debt (capital management measure)" is calculated as credit facilities plus senior unsecured notes, plus deferred acquisition payment notes, plus working capital surplus or deficiency, plus other liability, including the fair value of cross -currency swaps, plus government loans, plus facilities acquisition payments, less notes receivable and excluding the current portion of fair value of financial instruments, decommissioning obligations, lease liabilities and the cash award incentive plan liability. "Net Debt to EBITDA (capital management measure)" is calculated as net debt at a point in time divided by EBITDA. Management considers Net Debt to EBITDA an important measure as it is a key metric to identify the Company's ability to fund financing expenses, net debt reductions and other obligations. When this measure is presented quarterly, EBITDA is annualized by multiplying by four. When this measure is presented on a trailing twelve-month basis, EBITDA for the twelve months preceding the net debt date is used in the calculation. "Net Production Expense s, 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. Please refer to the MD&A for additional information relating to specified financial measures including non -IFRS financial measures, non -IFRS financial ratios and capital management measures. The MD&A can be a ccessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca. For additional information, please contact: Brian Schmidt President & Chief Executive Officer Tamarack Valley Energy Ltd. Phone: 403.263.4440 www.tamarackvalley.ca Steve Buytels Chief Financial Officer Tamarack Valley Energy Ltd. Phone: 403.263.4440 www.tamarackvalley.ca Christine Ezinga VP Business Development & Sustainability Tamarack Valley Energy Ltd. Phone: 403.263.4440 www.tamarackvalley.ca