Tamarack Valley Energy Announces Q3 2024 Financial Results, Updated Corporate Guidance and Dividend Increase

TSX: TVE

CALGARY, AB, Oct. 31, 2024 /CNW/ - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") (TSX: TVE) is pleased to announce its unaudited financial and operating results for the three and nine months ended September 30, 2024. 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 and nine months ended September 30, 2024, and 2023, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca.

Q3 2024 Financial and Operational Highlights

• Quarterly Production Growth – Production averaged 65,024 boe/d⁽¹⁾, exceeding the high end of prior guidance, reflecting ongoing strength in corporate performance driven by the Clearwater and Charlie Lake drilling programs and waterflood initiatives. Q3/24 Clearwater production increased to 43,300 boe/d⁽²⁾ reflecting a 15% (19% per share) increase YoY as Tamarack continues to expand its heavy oil operations.
• Increasing Funds Flow⁽³⁾ – Delivered Adjusted Funds Flow⁽³⁾ of $220.4MM ($0.41 per share), and Free Funds Flow⁽³⁾ of $108.7MM. YTD Tamarack has generated $297.7MM of Free Funds Flow⁽³⁾ which, on a per share basis, represents a 72% increase YoY⁽⁴⁾.
• Margin Enhancement – Continued cost reductions and better wellhead realizations are driving stronger margins across the business. Per boe transportation expense demonstrated a 43% improvement YoY. Higher pipeline flows, reduced trucking and a one-time royalty cost recovery all contributed to the improvement. Wellhead price realizations continue to improve due to enhanced blending, sales of CWH oil (Clearwater Heavy) and strong trading differentials driven by the TMX pipeline.
• Delivering Returns to Shareholders – Total shareholder return value for first nine months of 2024, was $144.7MM, or ~$0.26/share⁽⁵⁾, including base dividends of $61.4MM and share buybacks.
  • Continued Debt Reduction – Exit net debt of $807.4MM reflected a further strengthening of the balance sheet. Net debt has been reduced by $176.2MM YTD.
  • Increased Share Buybacks – During Q3/24, Tamarack repurchased 12.3MM common shares. During the first nine months of 2024, the Company bought back and cancelled 4.0% of the year-end 2023 shares outstanding.
  • Dividend Increase – Tamarack's per share monthly dividend will increase by 2% for the November dividend, payable in December, to $0.01275 from $0.0125 previously, which equates to $0.1530 annually.
• Expanded Clearwater Infrastructure Partnership – Added a 13^th Indigenous community to the Clearwater Infrastructure Limited Partnership (the "CIP") arrangement. Tamarack transferred an additional $50.8MM of Clearwater assets to the partnership for $43.2MM in cash and retained 15% operated working interest in the assets.

Achieving Success: Plan, Execute & Deliver

Brian Schmidt, President and CEO of Tamarack stated:

"Tamarack's Q3/24 results continue to highlight the quality of the Clearwater and Charlie Lake asset base that has been built over the past three years, and the operational excellence of the team that is driving this performance. Growth in Clearwater production of 15%, relative to the same period in 2023, was achieved while at the same time debt has been materially reduced and enhanced returns to shareholders have been increasing. By demonstrating improved efficiencies, the Company continues to deliver more while spending less."

Q3 2024 Financial & Operating Results

	Three months ended			Nine months ended
September 30	2024	2023	% change	2024	2023	% change
($ thousands, except per share amounts)
Oil and natural gas sales, before blending expense	$       439,435	$   506,365	(13)	$ 1,294,250	$  1,284,066	1
Cash provided by operating activities	240,843	199,756	21	631,414	415,645	52
Per share – basic^(3)	0.45	0.36	25	1.15	0.75	53
Per share – diluted^(3)	0.44	0.36	22	1.15	0.74	55
Adjusted funds flow^(3)	220,419	255,199	(14)	627,529	569,723	10
Per share – basic^(3)	0.41	0.46	(11)	1.15	1.02	13
Per share – diluted^(3)	0.40	0.46	(13)	1.14	1.02	12
Free funds flow^(3)	108,688	128,857	(16)	297,693	176,203	69
Per share – basic^(3)	0.20	0.23	(13)	0.54	0.32	72
Per share – diluted^(3)	0.20	0.23	(14)	0.54	0.31	72
Net income	93,694	8,634	985	155,837	36,874	323
Per share – basic	0.17	0.02	750	0.28	0.07	300
Per share – diluted	0.17	0.02	750	0.28	0.07	300
Net debt^(3)	807,401	1,128,030	(28)	807,401	1,128,030	(28)
Investments in oil and natural gas assets	109,032	122,759	(11)	323,594	388,752	(17)
Weighted average shares outstanding (thousands)
Basic	540,990	556,708	(3)	547,074	556,399	(2)
Diluted	545,266	558,569	(2)	551,091	559,958	(2)
Average daily production
Heavy oil (bbls/d)	39,047	35,900	9	37,659	35,229	7
Light oil (bbls/d)	13,203	16,974	(22)	14,422	16,797	(14)
NGL (bbls/d)	2,915	3,623	(20)	2,460	3,795	(35)
Natural gas (mcf/d)	59,154	72,597	(19)	55,162	71,633	(23)
Total (boe/d)	65,024	68,597	(5)	63,735	67,760	(6)
Average sale prices
Heavy oil, net of blending expense ($/bbl)^(3)	$          85.25	$        92.85	(8)	$        83.19	$        76.15	9
Light oil ($/bbl)	97.79	107.83	(9)	96.71	98.30	(2)
NGL ($/bbl)	39.58	41.46	(5)	39.32	41.51	(5)
Natural gas ($/mcf)	0.87	2.60	(67)	1.72	2.84	(39)
Total ($/boe)	73.62	80.22	(8)	74.05	69.29	7
Benchmark pricing
West Texas Intermediate (US$/bbl)	75.09	82.26	(9)	77.54	77.39	0
Western Canadian Select (WCS) (C$/bbl)	83.95	93.09	(10)	84.45	80.38	5
WCS differential (US$/bbl)	13.55	12.88	5	15.49	17.63	(12)
Edmonton Par (Cdn$/bbl)	97.85	107.90	(9)	98.43	100.63	(2)
Edmonton Par differential (US$/bbl)	3.35	1.85	81	5.21	2.61	100
Foreign Exchange (USD to CAD)	1.36	1.34	1	1.36	1.35	1
Operating netback ($/Boe)
Realized sales price, net of blending^(3)	73.62	80.22	(8)	74.05	69.29	7
Royalty expenses	(15.74)	(13.38)	18	(14.65)	(12.70)	15
Net production expenses^(3)	(8.62)	(8.47)	2	(9.12)	(9.72)	(6)
Transportation expenses	(2.36)	(4.13)	(43)	(3.47)	(4.00)	(13)
Carbon tax	(0.08)	-	nm	(0.40)	-	nm
Operating field netback ($/Boe)^(3)	46.82	54.24	(14)	46.41	42.87	8
Realized commodity hedging gain (loss)	0.03	(2.52)	(101)	(0.09)	(1.89)	(95)
Operating netback ($/Boe)^(3)	$         46.85	$        51.72	(9)	$        46.32	$        40.98	13
Adjusted funds flow ($/Boe)^(3)	$         36.85	$        40.44	(9)	$        35.93	$        30.80	17

2024 Production Guidance Update

In response to the continued strong well performance and benefits from infrastructure optimization during the year, the Company has increased the full-year production guidance range to 63,000 to 64,000 boe/d⁽⁶⁾.

The 2024 capital program, which is delivering higher production than originally budgeted, is forecasted to be achieved at a lower cost, benefitting from drilling and facilities efficiencies. Utilizing a portion of the CIP expansion proceeds, Tamarack will drill 4 (4.0 net) Charlie Lake wells in Q4/24, expand regional pipeline capacity in advance of the third-party plant commissioning in early 2025, and expand its waterflood investment program in the Clearwater. Tamarack anticipates spending for the year to be approximately $440MM⁽⁷⁾, consistent with prior guidance, which is inclusive of the incremental Charlie Lake wells and waterflood investment as the Company continues to out deliver against the capital deployed.

Tamarack is also updating its 2024 corporate costs guidance on the back of a continued focus on reducing costs and enhancing margins. Transportation cost guidance is reduced in response to improved oil transportation contracts and lower trucking costs. Guidance regarding carbon tax is updated to reflect savings related to anticipated taxable emissions reductions in 2024, resulting from ongoing Clearwater carbon abatement initiatives. Interest expense guidance was reduced primarily due to lower net debt and lower interest rates. The change to income tax guidance reflects Tamarack's profitability outperformance and the impact of the CIP expansion.

2024 Guidance Summary⁽⁸⁾

	Units	Prior (May 2024) Guidance	Guidance Change	Updated (October 2024) Guidance
2024 Capital Budget^(7)	$MM	$390– $440	-	$440
Annual Average Production^(6,9)	boe/d	61,000 – 63,000	+2,000 & +1,000	63,000 – 64,000
Average Oil & NGL Weighting	%	84% – 86%	-	84% – 86%
Expenses:
Royalty Rate (%)	%	20% – 22%	-	20% – 22%
Wellhead price differential – Oil^(10)	$/boe	$2.00 – $3.00	-	$2.00 – $3.00
Net Production	$/boe	$8.75 – $9.25	-	$8.75 – $9.25
Transportation	$/boe	$3.75 – $4.10	($0.30) & ($0.35)	$3.45 – $3.75
Carbon Tax^(11)	$/boe	$0.50 – $1.00	($0.25) & ($0.50)	$0.25 – $0.50
General and Administrative ^(12)	$/boe	$1.35 – $1.50	-	$1.35 – $1.50
Interest	$/boe	$3.80 – $4.20	($0.55) & ($0.45)	$3.25 – $3.75
Income Taxes^(13)	%	9% - 11%	2% & 2%	11% - 13%

Returns to Shareholders

The Company will raise its monthly dividend to $0.01275 per share, or $0.1530 per share annually, starting with the November dividend that is payable in December. This will represent the fourth increase, and a 53% uplift, since announcing the inaugural dividend in December 2021.

2024 Operations Update

Clearwater

Total Clearwater production averaged 43,300 boe/d⁽¹⁴⁾ (91% oil) in Q3/24, representing a 15% increase YoY (19% per share growth). This result was driven by the Nipisi and West Marten assets which averaged ~20,800 bbl/d of heavy oil Q3/24, demonstrating an increase of approximately 10% year-to-date. The strong growth reflects de-bottlenecking efforts, base optimization, better than forecast new well performance, and West Nipisi waterflood response. Investment in gas conservation has seen total sales gas from Tamarack's Clearwater assets more than double YoY.

At West Marten, the Company continues to see positive results from the C sand delineation program with an IP30 rate of ~200 bbl/d observed at 02/13-30-076-04W5/0. Stacked sand development continues in the area, where the Company rig released six B sand and two C sand wells in Q3/24 from its 14-23-076-05/W5 pad. Initial productivity is strong, and the Company plans to pursue waterflood in both sands.

The continued refinement of drilling designs, coupled with program optimizations, are driving efficiency enhancements and lower overall capital costs throughout the Clearwater asset base. This has resulted in a 5% reduction in per meter drilling costs across the Clearwater, highlighted by a 15% reduction in Marten Hills.

The application of fan well designs in the Clearwater is illustrative of this progression, where results have improved efficiencies through lower costs and increased recoveries in areas where economic secondary recovery potential has not yet been established. Success of the fan design is demonstrated through results in the South Clearwater. The two Newbrook 13-30-062-20/W4 pad wells brought onstream in 2024, continue to exhibit strong production, with average daily oil rates exceeding 235 bbl/d per well after seven months on production. This pad represents the best wells drilled by industry, across the trend to date, and Tamarack's overall South Clearwater fan production has grown to 1,650 bbl/d. Results to date have demonstrated the fan design contributes to shallower declines and higher per well estimated ultimate recoveries (EUR), compared to the conventional design historically applied in the area. This provides positive implications for future development by reducing long-term sustaining capital while optimizing project economics.

Waterflood – Production Response to Increased Injection at Nipisi and Marten Hills 

Clearwater secondary recovery initiatives are exhibiting strong early results across multiple areas and sands in the play. Pilots initiated by Tamarack continue to demonstrate strong performance from secondary recoveries with wells trending ahead of expectations, indicating the potential to more than double the primary EUR of the well. Total water injection across the Clearwater is currently ~8,650 bbl/d and forecasted to grow to 14,000 bbl/d by year end, representing >60% growth through Q4/24. Waterflood activity to date has resulted in an estimated 1,500 bbl/d of incremental oil production, and the Company expects to have >9% of its Clearwater production supported by waterflood by year-end 2024.

Year-to-date the company has drilled seven total injectors in Nipisi. Based on the strong results from waterflood in the area, the Company plans to drill five additional injectors from the 12-14-076-08/W5 pad in Q4/24. Tamarack's first C sand injector at West Marten commenced water injection in August 2024, and currently is injecting at a rate of 400 bbl/d.

At Marten Hills, the Company is now seeing oil response from all its implemented waterflood patterns. Oil production from Tamarack's first "W" pattern at 102/01-11-074-25/W4 is currently 25 bbl/d above its primary baseline and ramping up. The 100/16-02-075-25/W4 pattern, offsetting the highly successful 102/15-02-075-25/W4 pattern, is also seeing a strong initial response that is 25 bbl/d above its primary baseline. Based on these results, Tamarack plans to drill two water source wells in Q4/24 to accelerate further conversions in the area, which are designed to maximize per well injectivity, promoting quicker response times and delivering shorter payout periods. Total water injection at Marten Hills is currently at approximately 4,750 bbl/d.

At Canal, Tamarack implemented a pilot waterflood at the 100/16-16-70-23W4/0 well which has demonstrated strong initial injectivity greater than 800 bbl/d.

Charlie Lake

During the quarter, Tamarack achieved production of 16,200 boe/d⁽¹⁵⁾ from its Charlie Lake assets, which continued to benefit from sustained outperformance related to wells brought online during H1/24 in the Wembley area. Tamarack resumed drilling in the Charlie Lake play in July, rig releasing 4 (4.0 net) horizontal wells in Q3/24.

Late in Q3/24, Tamarack brought two wells online in the Pipestone area that were drilled from the 14-34-071-08/W6 pad. These two wells achieved average IP30 rates of 1,320 boe/d⁽¹⁶⁾ (86% oil & liquids) per well, which compare to outperforming wells brought on-stream by Tamarack in H1/24. Also, in Q3/24 the Company has brought online two Wembley area wells from the 11-11-074-08/W6 pad that have exhibited encouraging tests rates similar to the prior two Q4/23 drills from this location.

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 the reminder of 2024 and the first half of 2025, approximately ~50% of net after royalty oil production is hedged against WTI with an average floor price of ~US$67/bbl in Q4/24 and ~US$65/bbl in H1/25, with structures that allow for upside price participation at an average ceiling price of ~US$85/bbl. Our strategy provides protection to the downside while maximizing upside exposure. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca).

Quarterly Investor Call

9:30 AM MDT (11:30 AM EDT)

 

Tamarack will host a webcast at 9:30 AM MDT (11:30 AM EDT) on Thursday October 31, 2024, to discuss the Q3/24 financial results and provide an operational update. Participants can access the live webcast via this link or through links provided on the Company's website. A recorded archive of the webcast will be available on the Company's website following the live webcast.

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⁽³⁾ generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Clearwater and Charlie Lake 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
EOR	enhanced oil recovery
GJ	gigajoule
IFRS	International Financial Reporting Standards as issued by the International Accounting Standards Board
IP30	average peak production rate for the 30 days after the well is brought 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
YoY	Year-over-year
YTD	Year-to-date

Reader Advisories

Notes to Press Release

1)	Production of 65,024 boe/d: 39,047 bbl/day heavy oil, 13,203 bbl/d light and medium oil, 2,915 bbl/d NGL and 59,154 mcf/d natural gas.
2)	Q3 2023 Clearwater production of 37,600 boe/d is comprised of approximately 35,700 bbl/d heavy oil, 186 bbl/d NGL and 10,375 mcf/d natural gas.
3)	See "Specified Financial Measures".
4)	Return per share calculated based on the weighted average basic shares outstanding for the relevant periods.
5)	Q1/24-Q3/24 dividends of $61.4MM and share buybacks of $83.3MM.
6)	Production of 63,000 – 64,000 boe/d: 37,900-38,600 bbl/d heavy oil, 13,600-13,750 bbl/d light and medium oil, 2,300-2,400 bbl/d NGL and 55,000-55,500 mcf/d natural gas.
7)	Capital budget includes exploration and development capital, ESG initiatives, facilities land and seismic but excludes ARO, capital associated with the CIP and asset acquisitions and dispositions.
8)	Annual guidance numbers are based on 2024 average pricing assumptions of:

2024 Budget Pricing
Crude Oil – WTI ($US/bbl)	$75.00
Crude Oil – MSW Differential ($US/bbl)	($4.00)
Crude Oil – WCS Differential ($US/bbl)	($17.00)
Natural Gas – AECO ($CAD/GJ)	$2.50
Foreign Exchange – CAD/USD	1.3450

9)	Production of 61,000 – 63,000 boe/d: 12,800-13,200 bbl/d light and medium oil, 36,600-37,800 bbl/d heavy oil, 2,400-2,500 bbl/d NGL and 54,900-56,700 mcf/d natural gas.
10)	Wellhead price differential for oil shown in the guidance table.
11)	The Company's acquisitions in 2022 and a more stringent emissions regulatory framework increased taxable emissions in 2023 and 2024. Carbon tax of $0.50-$1.00/boe is anticipated in 2024, a significant increase from 2023 as the price of carbon escalates 23% to $80/tonne and the emissions intensity benchmark tightens. Carbon tax was previously included in net production costs but will be reported separately going forward. Tamarack's gas conservation initiatives that continue into 2024 are expected to substantively decrease the carbon tax burden in 2025 and subsequent years.
12)	G&A noted excludes the effect of cash settled stock-based compensation.
13)	Tamarack estimates a tax rate as a percentage of funds flow
14)	Production of 43,300 boe/d: 39,100 bbl/d heavy oil, 300 bbl/d light and medium oil, 360 bbl/d NGL and 21,500 mcf/d natural gas.
15)	Production of 16,200 boe/d: 8,300 bbl/d light and medium oil, 2,500 bbl/d NGL and 32,400 mcf/d natural gas
16)	Production of 1,320 boe/d: 1,030 bbl/d light and medium oil, 108 bbl/d NGL and 1,090 mcf/d natural gas

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 Production Rates. References in this press release to peak rates, initial production rates, IP30 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.

Forward Looking Information

This press 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 press release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; the Company's exploration and development plans and strategies; improved efficiencies and margin enhancements; future intentions with respect to debt repayment and reduction and the Company's ROC framework, including share buybacks and an increased monthly dividend; oil and natural gas production levels, adjusted funds flow and free funds flow; anticipated operational results for 2024 including, but not limited to, estimated or anticipated production levels (including in respect of Tamarack's updated 2024 production guidance, which is increased to the 63,000 to 64,000 boe/d range), capital expenditures, drilling plans and infrastructure initiatives (including use of proceeds from the CIP expansion), the Company's capital program, guidance and budget for 2024 and the funding thereof; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; decline rates and EOR, including waterflood initiatives; the continued successful integration of acquired assets; the ability of the Company to achieve drilling success consistent with management's expectations, including leveraging the "Fan" well design; ARO reduction; and risk management activities, including hedging positions and targets. 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.

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 2024 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); 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 between Russia and Ukraine and the recent crisis in Israel and Gaza 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 Company's annual information form 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 press 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 press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about generating sustainable long-term growth in free funds flow, dividends and share buybacks, prospective results of operations and production (including annual average production, average oil & NGL weighting), oil weightings, hedging, operating costs, 2024 capital budget, guidance and expenditures, decline rates, 2024 carbon tax, balance sheet strength, adjusted funds flow and free funds flow, net debt, debt repayments, total returns 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 "Petroleum and natural gas sales" section of the Company's Q1 2024 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. These performance measures are presented on a per boe basis as a non-GAAP financial ratio.

"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)" (previously referred to as "free adjusted funds flow breakeven") 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, Revenue, net of blending expense, 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, revenue, net of blending expense, 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. Blending expense includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications. The blending expense represents the difference between the cost of purchasing and transporting the diluent and the realized price of the blended product sold. In the MD&A, blending expense is recognized as a reduction to heavy oil revenues, whereas blending expense is reported as an expense in the financial statements. 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