Tamarack Valley Energy Announces Q2 2024 Financial Results, Achieves Milestone to Increase Shareholder Returns and Provides Operational Update

USA - English

TSX: TVE

CALGARY, AB, Aug. 1, 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 six months ended June 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 six months ended June 30, 2024 and 2023, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca.

Q2 2024 Financial and Operational Highlights

• Quarterly Production Growth – Achieved average daily production of 64,143 boe/d⁽¹⁾ during Q2/24, exceeding Q1/24 by >3%, reflecting strong performance from the Charlie Lake and Clearwater drilling programs, and outstanding response by our Clearwater team which successfully restored Nipisi production well in advance of the full recovery of operations at the third-party Mitsue facility.
• Increasing Funds Flow⁽²⁾ – Delivered Adjusted Funds Flow⁽²⁾ of $225.6MM, representing a 43% YoY increase, and Free Funds Flow⁽²⁾ of $137.2MM, reflecting demonstrated production outperformance relative to the 2024 budget and increased oil price realizations.
• Delivering Returns to Shareholders – During Q2/24 the Company repurchased 2.1MM common shares. In total, during H1/24 the Company bought back ~9.7MM shares, representing 1.7% of the year-end 2023 shares outstanding, for a total repurchase value of $33.7MM⁽³⁾. Total shareholder return value for H1/24, including base dividends of $41.1MM and enhanced returns, was $74.8MM⁽³⁾, or ~$0.14/share.
• Increasing Free Funds Flow Available for Shareholder Returns – Tamarack's exit net debt of $883MM marks a significant milestone arriving within the $500MM - $900MM net debt range and advances the Company to the next phase of the return of capital framework. This enables Tamarack to direct up to 60% of Free Funds Flow⁽²⁾ to base dividends and enhanced returns (up from 40% previously), with the remaining Free Funds Flow⁽²⁾ directed to ongoing net debt reduction and strategic growth capital allocation.
• Higher Pricing Margins – The Company's heavy and light oil sales price, improved by 21% and 16% respectively YoY. Oil realization increases exceeded performance by the underlying benchmarks owing to improved market access and lower wellhead deductions. Overall, Tamarack's average realized price of $79.04/boe was 20% higher on a YoY basis. Production expense of $9.34/boe in Q2/24 reflected a 9% YoY improvement and is expected to reduce further through the year.
• Capital Spending – Total capital expenditures in Q2/24 of $86.3MM reflected the drilling of 17 (13.8 net) Clearwater heavy oil wells and included $3.3MM for gas conservation projects sanctioned with the Clearwater Infrastructure Limited Partnership (the "CIP"). Site access, owing to wet spring conditions, limited Q2/24 activity with planned projects expected to proceed in H2/24. Full year capital guidance is maintained at $390MM - $440MM as Tamarack continues to monitor the status of the CSV Albright sour gas plant and commodity prices prior to allocating any incremental drilling capital for volumes associated with that project.

Q2 2024 Financial & Operating Results

	Three months ended			Six months ended
	June 30,			June 30,
	2024	2023	% change	2024	2023	% change
($ thousands, except per share)
Total oil, natural gas revenue	$         461,479	$        399,155	16	$          854,815	$        777,701	10
Cash flow from operating activities	225,370	156,265	44	390,571	215,889	81
Per share – basic	0.41	0.28	46	0.71	0.39	82
Per share – diluted	0.41	0.28	46	0.71	0.39	82
Adjusted funds flow ^(2)	225,554	157,253	43	407,110	314,524	29
Per share – basic ^(2)	0.41	0.28	46	0.74	0.57	30
Per share – diluted ^(2)	0.41	0.28	46	0.74	0.56	32
Free funds flow ^(2)	137,194	39,112	251	189,005	47,346	299
Per share – basic ^(2)	0.25	0.07	256	0.34	0.09	305
Per share – diluted ^(2)	0.25	0.07	256	0.34	0.08	305
Net income	94,887	25,735	269	62,143	28,240	120
Per share – basic	0.17	0.05	240	0.11	0.05	120
Per share – diluted	0.17	0.05	240	0.11	0.05	120
Net debt ^(2)	882,669	1,373,620	(36)	882,669	1,373,620	(36)
Capital expenditures	86,341	117,831	(27)	214,562	265,993	(19)
Weighted average shares outstanding (thousands)
Basic	548,012	556,461	(2)	548,449	556,504	(1)
Diluted	551,763	560,016	(1)	551,880	560,437	(2)
Average daily production
Heavy oil (bbls/d)	37,660	35,373	6	36,957	34,889	6
Light oil (bbls/d)	14,807	16,382	(10)	15,039	16,706	(10)
NGL (bbls/d)	2,533	3,645	(31)	2,229	3,882	(43)
Natural gas (mcf/d)	54,856	68,027	(19)	53,144	71,143	(25)
Total (boe/d)	64,143	66,738	(4)	63,082	67,334	(6)
Average sale prices
Heavy oil, net of blending expense^(2) ($/bbl)	$             88.19	$            73.02	21	$              82.09	$            67.42	22
Light oil ($/bbl)	106.24	91.74	16	96.23	93.38	3
NGL ($/bbl)	36.58	36.64	-	39.15	41.53	(6)
Natural gas ($/mcf)	1.51	2.39	(37)	2.20	2.97	(26)
Total ($/boe)	79.04	65.66	20	74.27	63.63	17
Benchmark pricing
West Texas Intermediate (USD$/bbl)	80.57	73.78	9	78.77	74.95	5
Western Canadian Select (WCS) (CAD$/bbl)	91.63	78.76	16	84.70	74.03	14
WCS differential (US$/bbl)	13.61	15.14	(10)	16.46	20.01	(18)
Edmonton Par (CAD$/bbl)	105.28	94.97	11	98.72	96.99	2
Edmonton Par differential (USD$/bbl)	3.63	3.08	18	6.14	2.98	106
Foreign Exchange (USD to CAD)	1.37	1.34	2	1.36	1.35	1
Operating netback ($/Boe)
Average realized sales, net of blending expense ^(2)	79.04	65.66	20	74.27	63.63	17
Royalty expenses	(14.67)	(12.70)	16	(14.08)	(12.34)	14
Net production expenses ^(2)	(9.34)	(10.25)	(9)	(9.39)	(10.37)	(9)
Transportation expenses	(3.93)	(3.98)	(1)	(4.05)	(3.94)	3
Carbon tax	(0.50)	–	nm	(0.56)	–	nm
Operating field netback ($/Boe) ^(2)	50.60	38.73	31	46.19	36.98	25
Realized commodity hedging loss	(0.67)	(2.05)	(67)	(0.16)	(1.56)	(90)
Operating netback ($/Boe) ^(2)	$             49.93	$            36.68	36	$              46.03	$            35.42	30
Adjusted funds flow ($/Boe) ^(2)	$             38.64	$            25.89	49	$              35.46	$            25.81	37

Achieving Success: Plan, Execute & Deliver

Brian Schmidt, President and CEO of Tamarack stated:

"Tamarack has been steadfast in our commitment to reducing debt, demonstrating operational excellence and delivering on our return of capital framework for shareholders. On a YoY basis, net debt has been reduced by ~$491MM or 36%. This reflects execution and delivery of results, driven by the successful transformation of the Company, that has enabled growth within our Clearwater and Charlie Lake core areas, where both plays delivered record high quarterly production in Q2/24. Leveraging our high quality heavy and light oil assets, Tamarack remains focused on execution of our strategic plan which underpins delivery of long-term value to our shareholders."

2024 Operations Update

Clearwater

West Marten and Nipisi

The North Clearwater assets achieved new record oil production, with rates growing to ~19,500 bopd in Q2/24, which compares to ~15,400 bopd in Q2/23. This represents a YoY increase of ~26%, reflecting the success of Tamarack's drilling and development program. Tamarack rig released 11 operated wells in Q2/24, including 8 (8 net) producing wells and 3 (3 net) water injection wells and participated in 4 (0.83 net) non-operated wells. An additional 32 (32 net) operated wells are planned for H2/24 which includes 24 (24 net) producing wells and 8 (8 net) water injection wells.

• Nipisi Outage Recovery Complete – Tamarack successfully recovered oil volumes that had been shut-in as a result of the April 13, 2024, Mitsue third-party plant incident prior to the plant coming back online June 24, 2024. Actions taken by our operations team successfully mitigated downtime impacts and reflect the hard work, focus and creativity of the team. Tamarack was able to deploy various temporary mitigation strategies including redirection of gas to an alternative third-party gas plant, gas injection and storage.
• Nipisi B Sand Performance Strength – Tamarack achieved strong results from the 12-14-76-8W5 Nipisi pad where the Company drilled 5 (5 net) B sand wells, with average IP30 rates of ~215 bopd per well, which have outperformed expectations to date. This is owing to higher oil quality (19-20 API), which is highly encouraging as Tamarack continues to step out development of the south end of the Nipisi pool.
• West Marten C Sand Success – The C sand program continued to demonstrate success with the two wells on the 12-15 pad (102/12-17-76-5W5 and 103/13-17-76-5W5) delivering average IP30 rates >200 bopd per well. In addition, four wells drilled off the 8-15 pad achieved peak monthly rates of >200 bopd per well. Tamarack plans to follow up on these results with additional C sand wells to be drilled from existing West Marten pads in H2/24. This will leverage the Company's existing infrastructure originally built for the initial B sand development driving enhanced full cycle efficiencies.

Marten Hills

Tamarack advanced key infrastructure at Marten Hills with the pipeline portion of the NW Connector project completed on schedule and under budget. The emulsion line was commissioned in Q2/24 and the gas line is expected to start up in August. The eight well pad at 4-30-75-25W4, which completed drilling in Q1/24, saw production increase to >1,400 bopd in June. The H2/24 program commenced at the end of June with plans to drill 22 wells for the balance of the year, including 20 producers and two source water wells.

South Clearwater

During the quarter the Company rig released two fan wells, with a total of six South Clearwater fan wells being drilled in H1/24. Plans for H2/24 include the drilling of an additional eight fans for a total of 14 fan wells during the year. Notable results were observed from the two Newbrook wells drilled off the 13-30-62-20W4 pad in 2024, which achieved the highest IP90 rates of all wells in the Southern Clearwater trend to date, at >225 bopd per well.

In support of ongoing regional gas conservation, expansion of Tamarack's Rochester gas plant was completed during the second quarter, raising throughput capacity to >3 MMcf/d.

Clearwater Waterflood - Increasing Injection Through H2/24

Tamarack, along with other regional operators, is highly encouraged with the waterflood response in the Clearwater to date. The Company will increase water injection activity in H2/24, supporting waterflood development to reduce future asset decline rates and sustaining capital requirements. Injection will commence in new zones, including the C sand in West Marten and Canal, where the Company has identified high quality targets for waterflood. Total Clearwater water injection is expected to increase by >110% from 7,000 bbl/d to 15,000 bbl/d exiting the year. 

Charlie Lake

Tamarack's Charlie Lake play continued to drive production growth having achieved the asset's highest quarterly production to date delivering Q2/24 average production of 17,900 boe/d⁽⁴⁾. In total, seven Tamarack operated Charlie Lake wells were brought on-stream in H1/24 with average IP90 rates exceeding 1,180 boe/d⁽⁵⁾ per well.

2024 Production and Capital Guidance Maintained

Tamarack reiterates prior annual production guidance of 61,000 - 63,000 boe/d⁽⁶⁾ and capital investment of $390MM - $440MM for 2024. Capital for the remainder of the year is expected to be allocated approximately 60% in Q3/24 and 40% in Q4/24. Tamarack continues to demonstrate discipline within our capital program and is monitoring the status of the CSV Albright sour gas plant onstream timing along with commodity prices. At this time, the Company is not allocating any incremental 2024 capital to expand the Charlie Lake program. The status of this decision will be updated in the fall.

2024 Guidance Summary⁽⁷⁾

	Units	Guidance
Base 2024 Capital Budget^(8)	$MM	$390– $440
Annual Average Production^(6)	boe/d	61,000 – 63,000
Average Oil & NGL Weighting	%	84% – 86%
Expenses:
Royalty Rate (%)	%	20% – 22%
Wellhead price differential – Oil^(9)	$/boe	$2.00 – $3.00
Net Production	$/boe	$8.75 – $9.25
Transportation	$/boe	$3.75 – $4.10
Carbon Tax^(10)	$/boe	$0.50 – $1.00
General and Administrative ^(11)	$/boe	$1.35 – $1.50
+Interest	$/boe	$3.80 – $4.20
Income Taxes^(12)	%	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$67.70/bbl with structures that allow for upside price participation at an average ceiling price of ~US$88.00/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's website.

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 August 1, 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. 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
IP90	average peak production rate for the 90 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
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. Production of 64,143 boe/d: 37,660 bbl/day heavy oil, 14,807 bbl/d light and medium oil, 2,533 bbl/d NGL and 54,856 mcf/d natural gas.
2. See "Specified Financial Measures".
3. Total repurchase value of $33.7MM includes taxes and commissions.
4. Production of 17,900 boe/d: 9,800 bbl/d light and medium oil, 2,300 bbl/d NGL and 34,600 mcf/d natural gas.
5. Production of 1,180 boe/d: 760 bbl/d light and medium oil, 80 bbl/d NGL and 2,020 mcf/d natural gas.
6. 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.
7. 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

8. 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.
9. Wellhead price differential for oil shown in the guidance table.
10. 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.
11. G&A noted excludes the effect of cash settled stock-based compensation.
12. 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, 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.

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 following the achievement of the milestone of arriving within the $500MM - $900MM net debt range enabling Tamarack to direct up to 60% of Free Funds Flow to base dividends and enhanced returns; 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; the Company's capital program, guidance and budget for 2024 and the funding thereof, including the CSV Albright commitment; 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; 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; 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.

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; 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 June 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