Tamarack Valley Energy Achieves Record Funds Flow in 2024 & Provides Operational Update

TSX: TVE

CALGARY, AB, Feb. 25, 2025 /CNW/ - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") (TSX: TVE) is pleased to announce its financial and operating results for the three months and year ended December 31, 2024. Selected financial and operating information should be read with Tamarack's audited annual consolidated financial statements and related management's discussion and analysis ("MD&A") for the three and twelve months ended December 31, 2024, and the Company's Annual Information Form ("AIF") for the year ended December 31, 2024, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca.

Tamarack closed out 2024 with annual production of 64,331 boe/d⁽¹⁾ exceeding expectations and adjusted funds flow ("AFF")⁽²⁾ of $851MM achieving a new corporate record. Through continuous improvement initiatives and execution of the business plan, the Company is realizing improved price margins, cost structure and asset productivity, all of which contribute to enhanced profitability. The Company drove total return to shareholders of ~21% on a per share basis during 2024. This was achieved through the buyback of ~6% of 2023 YE shares outstanding, a base dividend increase, the reduction of debt, and production growth in its core Clearwater and Charlie Lake plays.

2024 Financial and Operational Highlights

• Increased Free Funds Flow⁽²⁾ Generation – Delivered Q4/24 and full year AFF of $223MM and $851MM respectively. Including capital spending Tamarack generated Q4/24 and full year free funds flow ("FFF")⁽²⁾ of $89MM and $387MM respectively. Annual FFF represented a 65% YoY increase, which was directed to dividends, enhanced returns, and debt repayment.
  
  
• Enhanced Returns Execution – Bought back 33.9MM common shares in 2024, including 11.9MM in Q4/24, representing a 6% reduction relative to the 2023 YE shares outstanding. This provides for per share accretion on key metrics including production, reserves, AFF⁽²⁾ and FFF⁽²⁾. Tamarack returned over $215MM to shareholders in 2024, through dividends and share buybacks.
  
  
• Net Debt Reduction – Balance sheet strength was enhanced through lower net debt⁽²⁾ which was reduced by $208MM during the year to $775MM at December 31, 2024, representing 0.8x debt to EBITDA⁽²⁾ multiple.
  
  
• Production Performance – During Q4/24, production averaged 66,104 boe/d⁽³⁾, and was highlighted by YoY increases of 10% and 9% in the Clearwater and Charlie Lake respectively. Full year average production of 64,331 boe/d⁽¹⁾ included 6% growth in heavy oil volumes, reflecting continued success in the Clearwater.
  
  
• Lower Operating Costs – Production expense of $8.60/boe for 2024 demonstrated a 9% YoY improvement, reflecting core area production growth, program efficiencies, and disposition of higher cost assets.
  
  
• Heavy Oil Margin Improvements – The Company's heavy oil price differential in 2024, net of transportation expense⁽²⁾ relative to the Hardisty Heavy benchmark price, improved by 45% YoY.
  
  
• Capital Investment Efficiencies – Capital expenditures of $439MM⁽⁴⁾ were inline with prior 2024 guidance. Efficient annual spending allowed for the drilling of four additional Charlie Lake wells (which were brought on-stream in Q1/25) without an increase to the 2024 annual capital plan.
  
  
• Reserves Growth & Production Replacement – Bookings at 2024 YE increased across all categories by 8% - 9% with Proved Developed Producing ("PDP"), Total Proved ("TP") and Total Proved Plus Probable ("TPP") increases replacing 127%, 150% and 179% of production respectively (prior to dispositions).
  
  
• Low F&D Costs Driving Strong Recycle Ratios – Clearwater and Charlie Lake results achieved PDP, TP, and TPP F&D⁽⁵⁾ costs, including changes in FDC⁽⁵⁾, of $15.20/boe, $14.16/boe and $10.94/boe respectively. Coupled with an annual field operating netback⁽²⁾ of $46.41/boe Tamarack achieved PDP, TP, and TPP recycle ratios⁽²⁾ of 3.1x, 3.3x and 4.2x respectively, representing the strongest recycle ratios in Tamarack's history.

2024 Financial & Operating Results

	Three months ended			Year ended
December 31	2024	2023	% change		2024	2023	% change
($ thousands, except per share amounts)
Oil and natural gas sales	$    426,482	$    418,864	2		$ 1,720,732	$ 1,702,930	1
Cash provided by operating activities	201,798	215,981	(7)		833,212	631,626	32
Per share – basic^(2)	0.38	0.39	(3)		1.54	1.13	36
Per share – diluted^(2)	0.38	0.39	(3)		1.52	1.13	35
Adjusted funds flow^(2)	223,431	194,771	15		850,960	764,494	11
Per share – basic^(2)	0.42	0.35	20		1.57	1.37	15
Per share – diluted^(2)	0.42	0.35	20		1.56	1.37	14
Free funds flow^(2)	89,208	58,927	51		386,901	235,130	65
Per share – basic^(2)	0.17	0.11	55		0.71	0.42	69
Per share – diluted^(2)	0.17	0.11	55		0.71	0.42	69
Net income	6,382	57,322	(89)		162,219	94,196	72
Per share – basic	0.01	0.10	(90)		0.30	0.17	76
Per share – diluted	0.01	0.10	(90)		0.30	0.17	76
Net debt^(2)	775,438	983,585	(21)		775,438	983,585	(21)
Investments in oil and natural gas assets	127,311	127,704	(0)		450,905	516,456	(13)
Weighted average shares outstanding
Basic	529,136	556,699	(5)		542,530	556,527	(3)
Diluted	533,845	560,008	(5)		546,940	560,032	(2)
Average daily production
Heavy oil (bbls/d)	39,341	37,447	5		38,082	35,788	6
Light oil (bbls/d)	13,822	14,928	(7)		14,271	16,326	(13)
NGL (bbls/d)	2,841	2,769	3		2,556	3,536	(28)
Natural gas (mcf/d)	60,602	58,419	4		56,529	68,302	(17)
Total (boe/d)	66,104	64,881	2		64,331	67,034	(4)
Average sale prices
Heavy oil ($/bbl)	$        79.69	$        74.28	7		$        82.37	$        75.84	9
Light oil ($/bbl)	94.30	99.79	(6)		96.12	98.64	(3)
NGL ($/bbl)	32.84	42.31	(22)		37.51	41.67	(10)
Natural gas ($/mcf)	1.71	2.82	(39)		1.72	2.84	(39)
Total ($/boe)	70.12	70.17	(0)		73.08	69.60	5
Benchmark pricing
West Texas Intermediate (US$/bbl)	70.27	78.32	(10)		75.72	77.62	(2)
Western Canadian Select (WCS) (C$/bbl)	80.74	76.96	5		83.52	79.53	5
WCS differential (US$/bbl)	12.56	21.89	(43)		14.76	18.70	(21)
Edmonton Par (Cdn$/bbl)	94.90	99.69	(5)		97.54	100.39	(3)
Edmonton Par differential (US$/bbl)	2.42	5.19	(53)		4.51	3.25	39
Foreign Exchange (USD to CAD)	1.40	1.36	3		1.37	1.35	1
Operating netback ($/Boe)
Realized sales price	70.12	70.17	(0)		73.08	69.60	5
Royalty expenses	(13.42)	(13.81)	(3)		(14.33)	(12.97)	10
Net production expenses^(2)	(7.11)	(8.89)	(20)		(8.60)	(9.49)	(9)
Transportation expenses	(3.30)	(3.56)	(7)		(3.43)	(3.90)	(12)
Carbon tax	(0.05)	(2.53)	(98)		(0.31)	(0.65)	(52)
Operating field netback ($/Boe)^(2)	46.24	41.38	12		46.41	42.59	9
Realized commodity hedging loss	(1.59)	0.80	nm		(0.48)	(1.23)	(61)
Operating netback ($/Boe)^(2)	$        44.65	$        42.18	6		$        45.93	$        41.36	11
Adjusted funds flow ($/Boe)^(2)	$        36.74	$        32.63	13		$        36.14	$        31.25	16

Operations Update

Clearwater

Clearwater production of 43,300 boe/d⁽⁶⁾ (92% oil & liquids) in Q4/24 increased by 3,900 boe/d⁽⁷⁾ or 10% YoY. Growth was driven by strong drilling results, lower declines on the base production and better-than-expected waterflood response. This is indicative of the size and quality of the resource in place across the Company's Clearwater assets, and the continued growth and evolution of the Clearwater waterflood, which is now exhibiting the potential to deliver ultimate recoveries of up to 3x the primary estimates. Successful step-out and delineation drilling across the fairway contributed to over 20 MMbbls of TPP reserves additions, as a result of de-risking and reclassification from the contingent and prospective resources.

In total, Tamarack drilled 114 (101.5 net) oil wells during the year and was able to reduce drilling costs by 5%. Cost efficiencies were driven by multi-well stacked pad development, focused long-term planning, and operational performance. Clearwater activity in 2024 also included drilling 16 (16 net) injection and 3 (3.0 net) water source wells. Tamarack's highly efficient Clearwater waterflood additions achieved TPP F&D costs of less than $6.00/boe.

Clearwater water injection increased through 2024, from 3,000 bbl/d and is currently over 14,000 bbl/d, supporting continued expansion of the waterflood program. At year-end Tamarack had ~9% of Clearwater oil production under waterflood, which has now increased to ~12%, and currently supports ~4,700 bbl/d of oil production. Increased injection contributed to the Company's strong base production performance with success recognized through 10 MMbbl of TPP Clearwater waterflood reserve additions in the 2024 reserves report. Based on the success of waterflood, in both the 'B' and 'C' sands, Tamarack is accelerating implementation of waterflood on new wells to support continued improvement in Clearwater declines.

At Marten Hills Tamarack is deploying a "W" waterflood pattern to optimize flood performance based on area-specific reservoir characteristics. Success from this "W" design is observed at the 102/01-11-074-25W4 pattern, which is currently producing 175 bbl/d above its primary baseline. In Q4/24, the Company implemented two additional "W" injectors in Marten Hills where the Company has identified more than 80 additional conversion opportunities on its existing wells.

Charlie Lake

In the Charlie Lake, Q4/24 production averaged 16,936 boe/d⁽⁸⁾ (68% oil and liquids), representing a 9% YoY increase of 1,356 boe/d⁽⁹⁾ versus Q4/23. Production benefitted from strong new drill performance throughout 2024 and solid reliability via operated infrastructure.

Tamarack rig released 5 (5.0 net) horizontal wells in Q4/24, bringing the total drill count to 16 (14.4 net) for the year, with each of these 5 wells from Q4/24 being brought onstream in Q1/25. Overall there were 11 (11.0 net) operated wells brought online during 2024, achieving average IP90 rates of 1,174 boe/d⁽¹⁰⁾ per well (73% oil & liquids) and delivering consistent results throughout the year. Four wells brought online in H2/24, including two at Pipestone (14-34-071-08W6 pad) and two at Wembley (11-11-074-08W6 pad), outperformed type curve expectations and continue to exhibit outstanding results with average IP90 rates of 1,166 boe/d⁽¹¹⁾ (76% oil & liquids) per well. Based on the average results, these wells achieved an IP90 oil rate in the top 10 among all Charlie Lake wells brought on-stream in 2024.

2025 Outlook

Tamarack currently has four drilling rigs operating in the Clearwater. At West Marten, during the first quarter, the Company will target stacked development in the 'B' (7 wells) and 'C' (8 wells) sands, with the plan to initiate follow-up waterflood injection in H2/25. At Nipisi, first quarter drilling includes three water injection wells offsetting the 102/13-19-076-07W5 pilot as the Company continues to implement waterflood across the field. At Marten Hills the Q1/25 program includes six wells on the west side of the field and the conversion of two additional injectors offsetting the successful 01-11-074-25W4 pattern. Tamarack commenced a nine well drilling program at Canal in Q4/24 that will conclude in early Q2/25.

In the Charlie Lake, Tamarack has leveraged capacity at its owned and operated Wembley gas plant, which enabled the Company to flow production from new wells ahead of plan. Tamarack is awaiting guidance on the planned start-up timing for the CSV Albright gas plant, with alternate arrangements in place, our 2025 average production outlook remains unchanged. The Company plans to run a continuous one rig program in the Charlie Lake for 2025.

Based on the 2025 capital budget⁽¹²⁾, Tamarack expects to continue executing on its shareholder return framework which provides for stable base dividends, enhanced returns through buy backs and ongoing debt reduction. The Company's 2025 guidance remains as previously released.

	Units			2025 Guidance
2025 Capital Budget^(12)	$MM			$430 – $450
Annual Average Production^(13)	boe/d			65,000 – 67,000
Average Oil & NGL Weighting	%			83% – 85%
Expenses:
Royalty Rate (%)	%			20% – 22%
Wellhead price differential – Oil^(14)	$/bbl			$1.50 – $2.50
Production^(15)	$/boe			$8.40 – $8.90
Transportation	$/boe			$3.75 – $4.25
General and Administrative ^(16)	$/boe			$1.30 – $1.45
Interest^(17)	$/boe			$2.90 – $3.30
Income Taxes^(18)	%			10% - 12%

Risk Management

The Company takes a systematic approach to managing 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 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).

Automatic Share Purchase Plan

In connection with the previously announced normal course issuer bid ("NCIB"), and the Company's enhanced return of capital framework which is approved by Tamarack's Board of Directors, the Company has created an automatic share purchase plan with its designated broker to allow for purchases of its common shares under the NCIB during blackout periods. Such purchases would be at the discretion of the broker, based on parameters established by the Company prior to any blackout period or any period when it is in possession of material undisclosed information. Outside of these blackout periods, common shares will be repurchased in accordance with management's discretion, subject to applicable law.

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 continuing 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 Tuesday, February 25, 2025, to discuss the 2024 financial results. Participants can access the live webcast via this link or through links provided on the Company's website. An archive of the webcast will be made available on the Company's website.

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

AECO	the natural gas storage facility located at Suffield, Alberta connected to TC Energy's Alberta System
ARO	asset retirement obligation; may also be referred to as decommissioning obligation
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
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
IP30	average production for the first 30 days that a well is onstream
IP90	average production for the first 90 days that a well is onstream
Mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
MM	Million
MMcf/d	million cubic feet per day
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

Notes to Press Release

1. 64,331 boe/d: 14,271 bbl/d light and medium oil, 38,082 bbl/d heavy oil, 2,556 bbl/d NGL, and 56,529 mcf/d natural gas.
2. See "Specified Financial Measures"
3. 66,104 boe/d:13,822 bbl/d light and medium oil, 39,341 bbl/d heavy oil, 2,841 bbl/d NGL and 60,602 mcf/d natural gas.
4. $439MM of noted exploration and development capital excludes $11.6MM of projects attributed to Clearwater Infrastructure Limited Partnership (the "CIP") and $13.2MM of ARO.
5. 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.
6. 43,300 boe/d: 39,352 bbl/d heavy oil, 331 bbl/d NGL and 21,702 mcf/d natural gas.
7. 3,900 boe/d: 1,730 bbl/d heavy oil, 161 bbl/d NGL and 12,055 mcf/d natural gas.
8. 16,936 boe/d: 9,075 bbl/d light and medium oil, 2,441 bbl/d NGL and 32,520 mcf/d natural gas. 
9. 1,356 boe/d: 611 bbl/d light and medium oil, 809 bbl/d NGL and -384 mcf/d natural gas. 
10. 1,174 boe/d: 766 bbl/d light and medium oil, 91 bbl/d NGL and 1,904 mcf/d natural gas. 
11. 1,166 boe/d: 773 bbl/d light and medium oil, 111 bbl/d NGL and 1,690 mcf/d natural gas. 
12. Annual guidance numbers are based on 2025 average pricing assumptions of:
    

    2025 Budget Pricing
    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

13. 65,000 – 67,000 boe/d: 39,150-40,350 bbl/d heavy oil, 13,300-13,700 bbl/d light and medium oil, 2,300-2,360 bbl/d NGL and 61,550-63,550 mcf/d natural gas.
14. Oil wellhead deductions for grade specific trading differential (ex CHV), blending requirements, quality differential, and pipeline tolls if Tamarack is not marketing (lease transactions).
15. Production expense budget includes the "CIP" fee for service and minimal carbon tax.
16. G&A noted excludes the effect of cash settled stock-based compensation.
17. Budgeted interest includes CIP take-or-pay capital fee.
18. Tamarack estimates a tax rate as a percentage of adjusted funds flow.

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.

Short Term Results. References in this press release to peak rates, initial production rates, IP30, IP90 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 decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Tamarack. The Company cautions that such results should be considered to be preliminary.

Type Curves. Certain type curves disclosure presented herein represents estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves represent what management thinks an average well will achieve, based on methodology that is analogous to wells with similar geological features. Individual wells may be higher or lower but over a larger number of wells, management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Additional details on well performance and management's type curves are available in the presentation on Tamarack's website at www.tamarackvalley.ca .

Reserves Disclosure. All reserves values and ancillary information contained in this news release are derived from the oil and gas reserves evaluations as of December 31, 2024 (the "Reserve Reports"), prepared by Tamarack's independent qualified reserves evaluators, McDaniel & Associates Consultants Ltd. ("McDaniel) and GLJ Ltd. ("GLJ"), which have been prepared in accordance with definitions, standards and procedures contained in NI 51-101 and the most recent publication of the Canadian Oil and Gas Evaluation Handbook ("COGEH"), unless otherwise noted. Additional reserves information as required under NI 51-101 is included in the AIF which has been filed on SEDAR+ at www.sedarplus.ca. 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. All reserves assigned in the Reserve Reports are located in the Province of Alberta and presented on a consolidated basis.

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 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.

"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, share buybacks and debt reduction; 2025 budget, outlook and guidance; anticipated operational results for 2025 including, but not limited to, estimated or anticipated production levels, capital 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 performance characteristics of the Company's oil and natural gas properties; EOR, including the acceleration of waterflood initiatives; the ability of the Company to achieve drilling success consistent with management's expectations; risk 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 (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" and "recovery" 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, 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 grow the banking facilities; the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack's ability to execute its plans and strategies.

Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production; the risk that future dividend payments thereunder are reduced, suspended or cancelled; incorrect assessments of the value of benefits to be obtained from exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); the risk that (i) negotiations between the U.S. and Canadian governments are not successful and one or both of such governments implements announced tariffs, increases the rate or scope of announced tariffs, or imposes new tariffs on the import of goods from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company; commodity prices, including the impact of the actions of OPEC and OPEC+ members; 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 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, dividends and 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 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 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 standardized 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 on decommissioning obligations and transaction costs settled during the applicable period. since Tamarack believes the timing of collection, payment or incurrence of these items is variable. Management believes 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 being considered a supplemental financial 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 differential 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 revenue received by Tamarack for each barrel sold relative to the published market price during that period.

"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 to manage the long-term value of the business.

"Free funds flow breakeven (capital management measure)" is determined by calculating the minimum WTI price in US/bbl required to generate free funds flow equal to zero, sustaining current production levels and all other variables held constant. Management believes that free funds flow breakeven provides a useful measure to establish corporate financial sustainability.

"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 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.

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 accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca.

SOURCE Tamarack Valley Energy Ltd.

For additional information, please contact: Brian Schmidt, President & Chief Executive Officer, Tamarack Valley Energy Ltd., Phone: [phone], www.tamarackvalley.ca; Steve Buytels, Chief Financial Officer, Tamarack Valley Energy Ltd., Phone: [phone], www.tamarackvalley.ca; Christine Ezinga, VP Business Development & Sustainability, Tamarack Valley Energy Ltd., Phone: [phone], www.tamarackvalley.ca