Tamarack Valley Energy Announces Q1 2024 Financial Results, Provides Operational Update and Announces Investor Day

TSX: TVE

CALGARY, AB, May 8, 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 months ended March 31, 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 months ended March 31, 2024 and 2023 and December 31, 2023, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca.

Q1 2024 Financial and Operational Highlights

• Increasing Funds Flow⁽¹⁾ – Delivered Adjusted Funds Flow⁽¹⁾ of $181.6MM, representing a 15% YoY increase, and Free Funds Flow⁽¹⁾ of $53.3MM, which was directed to base dividends, enhanced returns and reinforcing our balance sheet strength.
• Delivering Enhanced Returns – Tamarack delivered on its return of capital commitment to shareholders. During Q1/24 the Company purchased and cancelled 7.6MM common shares, representing ~1.4% of the outstanding shares, for a total repurchase of $25.6MM. Total shareholder return for the quarter, including base dividends and enhanced returns was $46.4MM, or ~$0.08/share.
• Increased Oil Production Weighting – Delivered quarterly production of 62,022 boe/d⁽²⁾, inline with guidance. Tamarack's oil and liquids weighting as a percent of total production increased to 86% in Q1/24 compared to 82% in Q1/23.
• Realizing Higher Pricing Margins – The Company's heavy oil price differential, including transportation expenses⁽¹⁾ relative to the Hardisty Heavy benchmark price, improved by 53% over Q1/23. The average realized price of $69.34/boe was 13% higher than Q1/23, owing to improved market access and lower wellhead deductions, having >90% of production focused in the Clearwater and Charlie Lake.
• Improved Net Production Expenses – Production expense of $9.43/boe in Q1/24 reflected a 10% improvement over Q1/23 and is expected to benefit from further cost efficiencies through the year. This demonstrates the benefits of new gas gathering facilities, increased volumes delivered to Tamarack's Wembley gas plant at Charlie Lake, Clearwater asset area synergies at Nipisi and Marten Hills and the impact of non-core dispositions.
• DAP and Term Facility Repaid; Bank Facility Updated – During the quarter the Company fully repaid the Deferred Acquisition Payment notes ("DAP") and term facility associated with the prior Deltastream Energy Corporation acquisition that closed in Q4/22. Subsequent to the quarter Tamarack extended its $875.0MM revolving SLL Facility, of which $228.0MM is unutilized, and added an uncommitted accordion feature providing the ability to access an incremental $125.0MM of secured debt.
• Optimized Capital Spending – Total capital expenditures in Q1/24 of $128.2MM reflected the drilling of 32.9 net Clearwater heavy and 5.4 net Charlie Lake light oil wells. Spending included $7.3MM of gas conservation projects sanctioned with the Clearwater Infrastructure Limited Partnership (the "CIP"). Annual capital expenditure guidance for 2024 is maintained at $390 - $440MM.
• Significant ARO Reduction – Tamarack divested its producing Redwater assets, including ~400 boe/d⁽³⁾ of production for a nominal cash price, with the purchaser assuming approximately $30MM of the Alberta Energy Regulator ("AER") deemed liability.

Q1 2024 Financial & Operating Results

	Three months ended			Three months ended
	March 31,			December 31,
	2024	2023	% change	2023	% change
($ thousands, except per share)
Total oil, natural gas revenue	$        393,336	$       378,546	4	$        418,864	(6)
Cash flow from operating activities	165,201	59,624	177	215,981	(24)
Per share – basic	0.30	0.11	173	0.39	(23)
Per share – diluted	0.30	0.11	173	0.39	(23)
Adjusted funds flow ^(1)	181,556	157,271	15	194,771	(7)
Per share – basic ^(1)	0.33	0.28	18	0.35	(6)
Per share – diluted ^(1)	0.33	0.28	18	0.35	(6)
Free funds flow ^(1)	53,335	9,109	486	67,067	(20)
Per share – basic ^(1)	0.10	0.02	490	0.12	(20)
Per share – diluted ^(1)	0.10	0.02	491	0.12	(20)
Net income	(32,744)	2,505	nm	57,322	nm
Per share – basic	(0.06)	–	nm	0.10	nm
Per share – diluted	(0.06)	–	nm	0.10	nm
Net debt ^(1)	984,768	1,374,068	(28)	983,585	0
Capital expenditures	128,221	148,162	(13)	127,704	0
Weighted average shares outstanding (thousands)
Basic	552,345	556,548	(1)	556,699	(1)
Diluted	555,595	560,503	(1)	560,008	(1)
Average daily production
Heavy oil (bbls/d)	36,255	34,399	5	37,447	(3)
Light oil (bbls/d)	15,270	17,035	(10)	14,928	2
NGL (bbls/d)	1,925	4,122	(53)	2,769	(30)
Natural gas (mcf/d)	51,431	74,293	(31)	58,419	(12)
Total (boe/d)	62,022	67,938	(9)	64,881	(4)
Average sale prices
Heavy oil, net of blending expense^(1) ($/bbl)	$            75.75	$           61.60	23	$             74.09	2
Light oil ($/bbl)	86.52	94.97	(9)	99.79	(13)
NGL ($/bbl)	42.54	45.91	(7)	42.31	1
Natural gas ($/mcf)	2.93	3.50	(16)	2.82	4
Total ($/boe)	69.34	61.61	13	70.07	(1)
Benchmark pricing
West Texas Intermediate (US$/bbl)	76.96	76.13	1	78.32	(2)
Western Canadian Select (WCS/Hardisty Heavy) (Cdn$/bbl)	77.77	69.30	12	76.96	1
WCS differential (US$/bbl)	19.31	24.88	(22)	21.89	(12)
Edmonton Par (Cdn$/bbl)	92.15	99.01	(7)	99.69	(8)
Edmonton Par differential (Cdn$/bbl)	8.65	2.88	200	5.19	67
Foreign Exchange (USD to CAD)	1.35	1.35	(0)	1.36	(1)
Operating netback ($/Boe)
Average realized sales, net of blending expense ^(1)	69.34	61.61	13	70.07	(1)
Royalty expenses	(13.46)	(11.99)	12	(13.81)	(3)
Net production expenses ^(1)	(9.43)	(10.49)	(10)	(8.89)	6
Transportation expenses	(4.18)	(3.90)	7	(3.56)	17
Carbon tax	(0.62)	–	nm	(2.53)	nm
Operating field netback ($/Boe) ^(1)	41.65	35.23	18	41.28	1
Realized commodity hedging loss	0.37	(1.06)	(135)	0.80	(54)
Operating netback ($/Boe) ^(1)	$            42.02	$           34.17	23	$             42.08	(0)
Adjusted funds flow ($/Boe) ^(1)	$            32.17	$           25.72	25	$             32.63	(1)

Achieving Success: Tamarack's Transformation and Promising Future

Brian Schmidt, President and CEO of Tamarack stated:

"During the first quarter of 2024, Tamarack demonstrated its unwavering commitment to execution. After a strategic shift that began three years ago, high grading our asset quality and reconstructing the company with best-in-class resources, we delivered impressive results. Notably, during the quarter, Tamarack brought on-stream two of the best Charlie Lake oil wells ever drilled in the play. Our organic drilling success, combined with strict capital discipline, allowed us to deliver on our commitment to investors. During the quarter we returned $46.4MM to investors in the form of declared dividends and share buybacks. Looking ahead, we will remain focused on our core assets. Our strategy includes continuing to increase oil weighting, reduce sustaining capital requirements, improve pricing margins, and implement projects with multiple payouts. Anticipating strong free funds flow⁽¹⁾ in 2024, the Company is positioned for a promising year. Tamarack's transformational journey continues, and we're excited about the future."

2024 Operations Update

Charlie Lake

During the quarter, Tamarack achieved production of 16,800 boe/d⁽⁴⁾, from its Charlie Lake assets which included delivering a monthly record of 18,500 boe/d⁽⁵⁾ for March. These results include the two outstanding recent wells, that to date are the strongest Charlie Lake oil wells ever drilled in the play. The wells delivered a combined IP30 rate of 3,700 boe/d⁽⁶⁾ (84% oil & liquids) and continue to produce at over 2,300 boe/d⁽⁷⁾ after 60-days on-stream.

In total, five Charlie Lake wells were brought on-stream in Q1/24 with average IP30 rates exceeding 1,500 boe/d⁽⁸⁾ per well. In addition, during Q2/24 the company will bring two additional Wembley wells online which have shown encouraging test results. Sustained outperformance in this core area reaffirms the company's strategy of targeting high quality rock, capturing contiguous land positions to enable extended lateral well length and infrastructure ownership to reliably produce at scale.

Nipisi Production Update

Tamarack has worked diligently to recover volumes at Nipisi that had been shut-in as a result of the April 13, 2024, Mitsue third-party plant incident. Effective May 7, 2024, the Company has been able to restore all but 1,050 – 1,250 boe/d⁽⁹⁾ (~60% natural gas) of production that had been shut-in because of the incident. The production recovered to date is the result of the hard work, focus and creativity of our team, and the utilization of various temporary mitigation strategies. These strategies include redirection of gas to an alternative third-party gas plant, gas injection and storage. The Company continues to pursue additional solutions to bring the remaining volumes back on-line.

According to the operator of the Mitsue facility, the preliminary estimate to resume normal operations based on currently available information is June 30, 2024.  However, this estimate is subject to change as further information is received and is subject to a number of variables including availability of parts, materials, and third-party contractors.

Tamarack estimates that Q2/24 production will be impacted by 2,300 - 2,700 boe/d⁽¹⁰⁾ and annual average 2024 production could be impacted by 575 – 675 boe/d⁽¹¹⁾. Reflecting the strong performance of our Q1/24 program and existing base production, Tamarack's budget guidance of 61,000 – 63,000 boe/d remains unchanged, despite the unplanned downtime and impact of the disposition, as the Company continues to track within our original budget volumes.

Clearwater

West Marten Hills and Nipisi

Oil production from the North Clearwater assets grew to ~18,600 bopd in Q1/24, which compares to ~13,200 bopd in Q1/23 representing a YoY increase of ~41%, reflecting the success of Tamarack's drilling and development program.

• West Marten C Sand Success – Area C sand production has increased to over 1,800 bopd. This includes results from the 1W0/13-13-76-5W5 well which has produced at peak monthly rates of >230 bopd. Based on this success, Tamarack drilled multiple follow-ups from the 8-15-76-5W5 and 12-15-76-5W5 pads which are expected to come on-stream during the second quarter.
• West Marten B Sand Performance Strength – Tamarack continues to see strong performance from its B sand program. Three B sand wells drilled from the 8-15-76-5W5 pad delivered peak monthly rates of approximately 170 bopd per well and production has remained flat since coming on-stream.
• Key Infrastructure Reducing Emissions – Raw gas throughput from Tamarack's 10-02-077-05W5 Marten Creek Gas Plant now exceeds over 5.5 MMcf/d. This critical infrastructure underpins ongoing development at West Marten Hills and Tamarack expects plant throughput to continue to grow as the play expands, delivering on the Company's gas conservation initiatives and reducing carbon tax exposure.

Marten Hills

Tamarack finished the drilling of an eight well pad at 4-30-75-25W4 at Marten Hills during the first quarter. This pad is currently cleaning up with an initial production rate of over 1,100 bopd and realized a savings of 10% relative to budget.

South Clearwater

At South Clearwater, Tamarack continues to leverage the fan design to improve development efficiencies realized through reduced surface locations, driving lower capital expenditures, and increased estimated ultimate recovery ("EUR") per well that is supported by wider interleg spacing.

The pilot fan well at 100/12-29-063-23W4/00 has delivered cumulative production of 65 Mbbls of oil over the first 15 months on-stream. The shallow decline profile demonstrated by the fan design resulted in an EUR of 178 Mbbls being booked to the pilot at 2023YE on a proved plus probable basis, representing the highest EUR booked to date in the Perryvale area. The company drilled three fan wells that came on production in 2024. Two of the wells had IP30 rates of 245 bopd per well, in the Newbrook area, while the third well in Perryvale is currently cleaning up and producing over 200 bopd. A relatively shallow decline profile is also expected to be observed from these wells over the coming months as Tamarack continues to monitor performance.

Waterflood - Increasing Injection at Nipisi and Marten Hills 

Nipisi water injection is currently stable at 3,000 bbl/d as 18 injectors are now supporting 12 producing wells across the field. The Company plans to grow injection with injector drilling at West Nipisi in the second half of the year.  At Marten Hills, Tamarack has continued to expand its waterflood activity in the area, including drilling its first water source well into the Grand Rapids formation. Area injection now exceeds 3,500 bbl/d, and the Company plans to continue ramping water injection as additional wells are converted throughout 2024.

In addition, the Company plans to initiate its first C sand waterflood pilot at West Marten Hills in the second half of 2024 to begin development of stacked waterflood potential in an area exhibiting excellent primary production results to date.

Tamarack's most prolific producer in Marten Hills, 102/15-02-075-25W4/00, has now produced over 470 mbbl of oil to date and has seen an increase in oil rate from 110 bopd at the start of injection to more than 300 bopd in early May, representing an increase of nearly 300%.

Delineation and Exploration

West Nipisi – Tamarack continues to see promising results from two recently drilled C sand wells with peak monthly rates exceeding 200 bopd per well. Industry continues to extend this play to the west with ongoing activity further de-risking our contiguous land position.

2024 Production and Capital Guidance Maintained

Tamarack is maintaining prior production and capital guidance of 61,000 - 63,000 boe/d⁽¹²⁾ and $390 - $440MM respectively. Core asset performance and strength of the 2024 drilling program are expected to offset the Redwater disposition, which included ~400 boe/d⁽²⁾ of recent production, and the temporary Clearwater outage at Nipisi.

Production expense guidance for the full year remains unchanged as Tamarack expects to see overall cost improvements on a per unit basis through 2024. The Company's transportation expense guidance has been increased by $0.50/boe owing to the reclassification of a Nipisi heavy oil transportation contract to be reflected as gross transportation expense for accounting purposes rather than reduction to the realized heavy oil wellhead price. Overall, the change is neutral to operating netbacks or funds flows⁽¹⁾ for the year as it functions as an offset between revenues and transportation expenses.

With respect to the Charlie Lake, Tamarack will continue to monitor timing of the CSV Albright sour gas plant where the Company proactively secured firm processing capacity in support of its ongoing development program. Any decision to commence drilling associated with the project will be subject to prevailing commodity prices and expected CSV on-stream timing. The Company has the ability to swing production from existing wells to this facility to utilize its capacity ahead of implementing any additional drilling. An update will be provided in conjunction with the Q2/24 results in July.

2024 Guidance Summary⁽¹³⁾

	Units	Prior (Feb 28, 2024) Guidance	Guidance Change	Updated (May 8, 2024) Guidance
Capital Budget^(14)	$MM	$390– $440	-	$390 - $440
Annual Average Production^(12)	boe/d	61,000 – 63,000	-	61,000 – 63,000
Average Oil & NGL Weighting	%	84% – 86%	-	84% – 86%
Expenses:
Royalty Rate (%)	%	20% – 22%	-	20% – 22%
Wellhead price differential – Oil^(15)	$/boe	$2.50 – $3.50	($0.50)	$2.00 – $3.00
Net Production	$/boe	$8.75 – $9.25	-	$8.75 – $9.25
Transportation	$/boe	$3.25 – $3.60	$0.50	$3.75 – $4.10
Carbon Tax^(16)	$/boe	$0.50 – $1.00	-	$0.50 – $1.00
General and Administrative ^(17)	$/boe	$1.35 – $1.50	-	$1.35 – $1.50
Interest	$/boe	$3.80 – $4.20	-	$3.80 – $4.20
Income Taxes^(18)	%	9% - 11%	-	9% - 11%

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, approximately ~50% of net after royalty oil production is hedged against WTI with an average floor price of ~US$68.00/bbl with structures that allow for upside price participation at an average ceiling price of ~US$89.00/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).

Investor Day 2024

We are pleased to announce that Tamarack will be hosting an Investor Day on Monday, June 24, 2024, from 1:00 – 4:00pm MT (3:00 – 6:00pm ET) with members of Tamarack's management and senior technical team presenting. 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, at  www.tamarackvalley.ca.

We would like to thank our employees, shareholders and other stakeholders for their ongoing support. Tamarack's success in executing on its strategic plan is the result of the dedication and hard work of our employees and guidance of our Board of Directors. We look forward to continuing to develop our high-quality assets to create shareholder value in a sustainable and responsible way.

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 Wednesday, May 8, 2024 to discuss the first
quarter financial results and 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 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. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. 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
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
OOIP WCS	original oil in place Western Canadian select, the benchmark for conventional and oil sands heavy production at Hardisty in Western Canada
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade

Reader Advisories

Notes to Press Release

1)	See "Specified Financial Measures"
2)	Q1 2024 average production from net dispositions of 62,022 boe/d comprised of 1,510 bbl/d light and medium oil, 1,310 bbl/d NGL and 21,500 mcf/d natural gas.
3)	Production of 400 boe/d comprised of 390 bbl/d light and medium oil and 60 mcf/d natural gas.
4)	Production of 16,800 boe/d comprised of 9,800 bbl/d light and medium oil, 1,600 bbl/d NGL and 32,400 mcf/d
5)	Production of 18,500 boe/d comprised of 11,300 bbl/d light and medium oil, 1,500 bbl/d NGL and 34,500 mcf/d
6)	Production of 3,700 boe/d comprised of 3,000 bbl/d light and medium oil, 115 bbl/d NGL and 3,700 mcf/d natural gas.
7)	Production of 2,300 boe/d comprised of 1,400 bbl/d light and medium oil, 140 bbl/d NGL and 4,500 mcf/d natural gas
8)	Production of 1,500 boe/d comprised of 1,160 bbl/d light and medium oil, 54 bbl/d NGL and 1,720 mcf/d natural gas
9)	Production of 1,050 - 1,250 boe/d comprised of 400 - 500 bbl/d heavy oil, 30 - 35 bbl/d NGL and 3,700 - 4,300 mcf/d natural gas
10)	Production of 2,300 - 2,700 boe/d comprised of 1,420 - 1,660 bbl/d heavy oil, 40 - 48 bbl/d NGL and 5,050 – 5,950 mcf/d natural gas
11)	Production of 575 - 675 boe/d comprised of 355 - 415 bbl/d heavy oil, 10 - 12 bbl/d NGL and 1,250 – 1,475 mcf/d natural gas
12)	Production of 61,000 – 63,000 boe/d comprised of 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
13)	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
14)	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.
15)	Wellhead price differential for oil shown in the guidance table.
16)	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.
17)	G&A noted excludes the effect of cash settled stock-based compensation.
18)	Tamarack estimates a tax rate on funds flow of 9%-11%.

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; future consolidation activity, organic growth and development and portfolio rationalization; the Company's exploration and development plans and strategies; future intentions with respect to debt repayment and reduction and the Company's ROC framework, including enhanced dividends and share buybacks; 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 2024 production guidance, which is maintained at the 61,000 to 63,000 boe/d range), capital expenditures, drilling plans and infrastructure initiatives, including on-stream timing of the new CSV Albright sour gas plant in the Charlie Lake and the expansion o the Wembley gas plant and anticipated margin improvements; 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 and long term net asset value capture; the continued successful integration of acquired assets; the ability of the Company to achieve drilling success consistent with management's expectations, including leveraging the "Fan" well design; risk management activities; ARO reduction; risk management activities, including hedging positions and targets; Tamarack's continued capital flexibility under its 2024 capital program and expectation that this will not impact 2024 production guidance; Tamarack's commitment to ESG principles and sustainability, including gas conservation projects, emissions reductions and carbon tax savings; 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 are deemed to be forward-looking information as they involve the implied assessment, based on certain estimates and assumptions, that the reserves can be profitably produced in the future.

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

Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production, maintaining 2024 guidance and resumption of operations; risks with respect to unplanned third-party pipeline outages; 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 AIF for the year ended December 31, 2023 and the MD&A for the period ended March 31, 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.

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