Tamarack Valley Energy Announces Strong Third Quarter 2022 Financial Results, Operational Update and Updated Pro Forma Q4 2022 Guidance

TSX: TVE

CALGARY, AB, Oct. 27, 2022 /CNW/ - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") (TSX: TVE) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2022. Selected financial and operating information is outlined below and should be read with Tamarack's consolidated financial statements and related management's discussion and analysis (MD&A) for the three and nine months ended September 30, 2022, which are available on SEDAR at www.sedar.com and on Tamarack's website at www.tamarackvalley.ca. The Company is also pleased to provide an operational update, fourth quarter 2022 guidance incorporating the acquisition of Deltastream Energy Corporation ("Deltastream") and confirmation of application to renew the Normal Course Issuer Bid (NCIB) program.

Brian Schmidt, President and CEO of Tamarack commented: "During the third quarter, we delivered positive operating and financial results which were bolstered by the resilient netbacks and full cycle profitability of the Clearwater and Charlie Lake oil assets. Furthermore, the acquisition of Deltastream further solidifies Tamarack as the largest producer in the Clearwater and builds on our core position and long-life inventory in what is recognized as the most economic oil play in North America."

Q3 2022 Financial and Operating Highlights

• Generated Q3/22 adjusted funds flow⁽¹⁾ of $177.8 million ($0.40/share basic and diluted).
• Achieved quarterly average production volumes of 43,476 boe/d⁽²⁾ in Q3/22.
• Generated free funds flow⁽¹⁾, excluding acquisition expenditures, of $79.4 million.
• Generated net income of $124.8 million ($0.28/share basic and diluted) during the quarter.
• Declared dividends of $13.6 million ($0.01 per common share per month) and, in conjunction with the Deltastream acquisition, announced an increase to the base dividend of 25% to $0.15 per common share annually ($0.0125 per month).
• Repurchased 3.1 million common shares under our NCIB for $12.8 million during the quarter for a total of 4.4 million shares and $18.6 million in consideration year to date.
• Invested $93.5 million in exploration and development (E&D) capital expenditures and $4.7 million on undeveloped land in the Clearwater and Charlie Lake areas during Q3/22, which contributed to the drilling of twenty-three (23.0 net) Clearwater oil wells and six (5.4 net) Charlie Lake oil wells.
• Exited the quarter with $286.8 million of net debt⁽¹⁾, inclusive of current tax payable, and net debt to Q3/22 annualized adjusted funds flow⁽¹⁾ of 0.4x.
• Successfully closed the disposition of certain assets in the Viking CGU for gross consideration of $70 million⁽³⁾ ($59.5 million net).
• Announced the acquisition of Deltastream during the quarter for total consideration of $1.425 billion consisting of 80.0 million shares of Tamarack, $300.0 million of deferred acquisition notes and $825.0 million in cash. The cash consideration was financed, in part, through a $100.0 million add-on offering to the Company's existing 7.25% senior unsecured sustainability linked Notes due May 2027 and a $137.3 million net equity financing – both of which closed in September 2022.

Financial & Operating Results

	Three months ended			Nine months ended
	September 30,			September 30,
	2022	2021	% change	2022	2021	% change
($ thousands, except per share)
Total oil, natural gas and processing revenue	329,304	212,265	55	1,035,394	457,867	126
Cash flow from operating activities	229,927	100,558	129	577,488	179,247	222
Per share – basic	$ 0.52	$ 0.25	108	$ 1.34	$ 0.53	153
Per share – diluted	$ 0.52	$ 0.24	117	$ 1.33	$ 0.52	156
Adjusted funds flow ^(1)	177,834	102,486	74	530,315	216,179	145
Per share – basic	$ 0.40	$ 0.25	60	$ 1.23	$ 0.64	92
Per share – diluted	$ 0.40	$ 0.25	60	$ 1.22	$ 0.63	94
Net income	124,793	20,032	523	294,757	250,060	18
Per share – basic	$ 0.28	$ 0.05	460	$ 0.68	$ 0.74	(8)
Per share – diluted	$ 0.28	$ 0.05	460	$ 0.68	$ 0.73	(7)
Net debt ^(1)	(286,762)	(519,708)	(45)	(286,762)	(519,708)	(45)
Capital expenditures ^(4)	98,451	69,978	41	333,301	149,487	123
Weighted average shares outstanding (thousands)
Basic	440,388	406,152	8	431,672	335,913	29
Diluted	443,351	414,342	7	435,053	344,072	26
Share Trading (thousands, except share price)
High	$ 4.62	$ 3.31	40	$ 6.48	$ 3.31	96
Low	$ 3.28	$ 2.05	60	$ 3.28	$ 1.25	162
Average daily share trading volume (thousands)	3,745	2,865	31	3,890	2,753	41
Average daily production
Light oil (bbls/d)	16,229	19,405	(16)	17,437	14,720	18
Heavy oil (bbls/d)	13,183	5,438	142	10,524	4,275	146
NGL (bbls/d)	3,659	4,257	(14)	3,769	3,243	16
Natural gas (mcf/d)	62,428	72,935	(14)	66,839	62,171	8
Total (boe/d)	43,476	41,256	5	42,870	32,600	32
Average sale prices
Light oil ($/bbl)	111.80	79.12	41	119.53	74.43	61
Heavy oil ($/bbl)	89.30	67.97	31	99.48	61.40	62
NGL ($/bbl)	49.18	33.67	46	56.23	36.37	55
Natural gas ($/mcf)	6.27	3.44	82	6.59	3.14	110
Total ($/boe)	81.98	55.73	47	88.28	51.27	72
Operating netback ($/Boe)
Average realized sales	81.98	55.73	47	88.28	51.27	72
Royalty expenses	(14.06)	(8.97)	57	(16.49)	(7.51)	120
Net production and transportation expenses	(13.12)	(10.53)	25	(12.74)	(10.75)	19
Operating field netback ($/Boe) ^(1)	54.80	36.23	51	59.05	33.01	79
Realized commodity hedging loss	(2.90)	(6.21)	(53)	(5.46)	(5.62)	(3)
Operating netback ($/Boe) ^(1)	51.90	30.02	73	53.59	27.39	96
Adjusted funds flow ($/Boe) ^(1)	44.46	27.00	65	45.31	24.29	87

Operations Update

Deltastream Clearwater Assets

Deltastream Assets – Deltastream rig released 56 (56.0 net) wells year-to-date through the end of Q3 2023: 25 (25.0 net) in Nipisi; 21 (21.0 net) in Marten Hills; and 10 (10.0 net) in Canal. Tamarack will continue to operate three rigs on the Deltastream lands through the end of 2022, focused entirely on the Marten Hills and Nipisi assets. The Company expects to drill an additional 22 gross (22.0 net) wells prior to year end. Total capital of $50.0 million has been allocated to the Deltastream assets for the fourth quarter, which will include costs associated with ongoing pipeline, facility and surface construction projects.

The Marten Hills development program has produced average well rates in-line with expectations, with ongoing waterflood injection in the area proceeding in-line with forecasts to date. Infrastructure improvement and expansion is ongoing with additional compression capacity being added. In addition, a significant expansion to the in-field pipeline infrastructure has resulted in approximately 60% of Marten Hills oil production connected to the main 11-04 facility, including 5 mmcf/d of conserved natural gas

In Nipisi, the 14-18-076-06W5, 02-19-076-06W5 and 09-19-076-06W5 pads drilled in H1 2022 are currently producing over 4,000 bopd, on a combined basis, from 3.25 sections of land. Performance from this area is ahead of forecast with all 22 wells having been onstream for more than five months and still averaging ~180 bopd per well. These results provide confidence that Tamarack's Nipisi waterflood fairway can be expanded to the east onto the acquired Deltastream lands. In addition, significant road construction was completed during Q3 to provide access to approximately 11 sections of high graded Nipisi inventory for future drilling.

Total production from the Deltastream assets averaged 20,400 boe/d⁽⁵⁾ (19,300 bopd) through the first three weeks of October, with 13,300 boe/d⁽⁵⁾ and 5,300 boe/d⁽⁵⁾ coming from the Marten Hills and Nipisi areas respectively. Nipisi has experienced substantial growth in 2022, from a 2021 exit rate of 240 bopd to over 5,000 bopd oil in early Q3, reflecting a very active and successful H1 2022 drilling program.

Clearwater

Peavine/Seal – Tamarack has licensed its first eight leg multi-lateral well in Peavine. Surface construction is ongoing, with an estimated spud date in mid-November. At Seal, we are on track to spud our first three well pad in early December testing three separate Clearwater sands.

West Marten Hills Exploration – Tamarack has rig released four West Marten Hills wells, including a step out well in the Clearwater A sand. Two of the four wells are on production, with the Clearwater A sand results exceeding Company expectations at over 200 bopd, despite being facility constrained while awaiting completion of construction on the permanent oil facility in this area which is anticipated to be completed in early November. Additionally, Tamarack has spud its first of three extended reach multi-laterals from the 14-07-076-04W5 pad.

West Nipisi – Tamarack's strategy at West Nipisi is focused on optimizing waterflood development moving forward. The Company has rig released 15 of 17 wells planned from four different pad sites, all of which are being developed under Tamarack's Nipisi Clearwater waterflood configuration. Currently, 14 of the 15 rig released wells are on production and average initial rates are exceeding expectations with the new 13-23-076-08W5 six well pad producing over 2,000 bopd. Injection commenced on three wells at Tamarack's waterflood pilot in early May, which is currently producing at 400 bopd, up from initial rates of 300 bopd. Tamarack has increased its H2 2022 injector drilling program from five wells to eight, including a trial three leg multi-lateral injector, given the positive response exhibited to date from the pilot. Currently three injectors from the 03-23-076-08W5 pad have been rig released.

Southern Clearwater – Tamarack continues to actively develop its Southern Clearwater assets with two rigs currently operating. Through area consolidation and development, Southern Clearwater production has increased from less than 500 bopd in Q4/21 to current rates of greater than 7,200 bopd. Development has been highlighted at West Perryvale, where production results have outperformed the area type curve and further inventory has been added through continued pool delineation. To date in 2022, 39 wells have been rig released, with 36 of those wells currently onstream. The wells currently producing have averaged peak oil rates of greater than 150 bopd. The Company plans to drill 45 gross (45.0 net) wells in the area in 2022 and execute on operational synergies on recently acquired production.

Charlie Lake

In the Charlie Lake, Tamarack has brought 15 of 18 planned wells onstream in 2022 and has achieved increased well performance by extending the average well length. During the quarter, the 100/15-24-071-09W6 well achieved an IP30 of 790 bopd (1,330 boe/d⁽⁶⁾).

During the quarter, the Company experienced downtime associated with scheduled third-party turnarounds which were included in our previous H2 2022 guidance, which resulted in a production impact of approximately 1,500 boe/d⁽⁷⁾ for the quarter. Further to this, turnaround activity extended into early October at one third-party facility. Production from the area is currently in-line with the corporate forecast.

Tamarack is continuing to advance plans to construct a new owned and operated gas plant in the Grande Prairie area, with engineering, planning and design work currently underway. Phase 1 of the plant will add approximately 15-20 MMcf/d of gas processing capacity and is forecasted to be commissioned in the second quarter of 2023.

Veteran/Eyehill Waterfloods

Tamarack has drilled 13 wells in 2022 targeting the Viking (6.0 net) and Sparky (7.0 net) formations at the Veteran and Eyehill properties, all of which were onstream prior to the end of Q1. Field-wide production from the Eyehill Sparky assets continued to grow throughout Q3, demonstrating waterflood response from water injection which commenced in 2021. September oil production of ~2,300 bopd is tracking ahead of expectations.

Non-Core Viking Disposition

Tamarack closed the disposition of approximately 2,000 boe/d⁽⁸⁾ (~44 % liquids) of non-core Viking production for total gross proceeds of $70 million⁽³⁾ in Q3/22_. This disposition is consistent with the Company's portfolio rationalization strategy which is focused on growing our core areas and long-term sustainable free funds flow⁽¹⁾ growth.

Updated Deltastream Pro Forma Q4/2022 Guidance

To reflect the Deltastream acquisition that closed on October 13, 2022, Tamarack is providing updated pro forma Q4/22 corporate guidance. The Company remains focused on capital discipline and sustainable free funds flow⁽¹⁾ growth. Tamarack expects to release its 2023 full year budget and guidance in early December 2022.

	Q4 2022 Guidance
E&D Capital Budget^(9) ($millions)	$125-$135
Q4 Average Production^(10) (boe/d)	62,000-64,000
Expenses:
Royalty Rate (%)	20–22%
Operating ($/boe)	$9.50–$10.00
Transportation ($/boe)	$2.50–$3.00
General and Administrative ($/boe)^(11)	$1.25–$1.35

Return of Capital Framework

The Company remains committed to balancing long-term sustainable free funds flow⁽¹⁾ growth with returning capital to shareholders. As previously disclosed with the Deltastream acquisition, the Company further refined its return of capital framework to balance debt repayment, enable future strategic acquisitions that bolster long-term inventory resiliency and increase clarity around delivering enhanced returns to shareholders through opportunistic share buybacks and/or enhanced dividends.

The return of capital framework includes a base dividend, which is a structural component of the financial framework and is set at a level equivalent to approximately 25% of corporate free funds flow⁽¹⁾ at our long-term 5-year plan price deck of US$55/bbl WTI and $2.50/GJ AECO. The base dividend can be sustainably covered at bottom cycle pricing of less than US$40/bbl WTI. In addition to the base dividend, the Company will direct up to a given percentage of excess quarterly funds flow⁽¹⁾ to enhanced return as certain debt thresholds are met, as outlined below.

Base Dividend

As previously announced, the Company will increase the base dividend by 25% to $0.15/share annually for the November dividend declaration payable in December. In total, Tamarack has increased its annual base dividend by 50% year to date, from $0.10/share to $0.15/share. The increase in the base dividend year to date is driven by the enhanced sustainable free funds flow⁽¹⁾ achieved in conjunction with the success of the Company's 2022 capital program and strategic Clearwater acquisitions which are accretive to the 5-year plan at flat pricing of US$55/bbl WTI and $2.50/GJ AECO.

Updated Enhanced Return Framework

In conjunction with the acquisition of Deltastream, Tamarack's balance sheet will remain a priority. The enhanced return framework corresponds with specific debt range targets as outlined below:

• Net debt of less than $1.1 billion but greater than $900 million, the Company will target to deliver up to 25% of excess funds flow from the prior quarter to shareholders through enhanced dividends and/or tactical share buybacks.
• Net debt of between $500 million and $900 million, the Company will target delivery of up to 50% of excess funds flow from the prior quarter to shareholders.
• Net debt reaches the long-term debt floor of $500 million, representing approximately 1.0x net debt to quarterly annualized funds flow at US$45/bbl WTI and $2.50/GJ AECO, the Company will target to return up to 75% of excess funds flow to shareholders.

Any enhanced dividend will be paid to shareholders on a quarterly basis, one month following the declaration date. Tamarack looks forward to continuing to deliver on shareholder returns in 2022 with further incremental returns in 2023 based on the current commodity price outlook.

Tamarack in in the process of applying to the TSX to renew the NCIB for November 2022 through October 2023. The Company expects to receive confirmation and approval of program renewal in early November 2022.

Risk Management

Consistent with the strategy of protecting the balance sheet, sustaining capital and base dividend, the Company manages commodity price risk and volatility through a prudent and systematic hedging program. Tamarack has approximately 60% of gross oil production hedged against WTI for the remainder of 2022, through instruments including swaps, puts and enhanced collars. Tamarack also has WTI-MSW and WCS differential hedges in place on approximately half of remaining 2022 production. For 2023, the Company has a combination of WTI swaps, put floors and enhanced collars on approximately 50% of first half production. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca).

Sustainability

On September 30, 2022, Tamarack released a report on sustainability performance target progress, detailing the progress that was made in 2021 on the key performance indicators outlined in the Company's sustainability linked debt instruments. A copy of the report can be found on Tamarack's website. The Company looks forward to sharing more information on the overall sustainability program in the annual sustainability report that will be published in early December 2022.

Investor Call Tomorrow

9:00 AM MDT (11:00 AM EDT)

 

Tamarack will host a webcast at 9:00 AM MDT (11:00 AM EDT) on Friday, October 28, 2022 to discuss the third quarter results and operations 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, Clearwater and EOR plays in Alberta. 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
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
WCS	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)	Comprised of 16,229 bbl/d light and medium oil, 13,183 bbl/d heavy oil, 3,659 bbl/d NGL and 62,428 mcf/d natural gas
^(3)	Total gross proceeds are comprised of $50.0 million cash and a $ 20.0 million promissory note. Net proceeds for the transaction of $59.9 million represent the $70.0 million total gross proceeds less transaction costs and net income adjustments back to the effective date of April 1, 2022.
^(4)	Capital expenditures include exploration and development capital, ARO, ESG initiatives, facilities, land and seismic but excludes asset acquisitions and dispositions.
^(5)	Comprised of approximately: 19,300 bbl/d heavy oil, 75 bbl/d NGL and 6,150 mcf/d natural gas (total production); 12,400 bbl/d heavy oil, 70 bbl/d NGL and 5,000 mcf/d natural gas (Marten Hills production); 5,100 bbl/d heavy oil, 10 bbl/d NGL and 1,150 mcf/d natural gas (total production);
^(6)	Comprised of approximately 790 bbl/d light and medium oil, 290 bbl/d NGL and 1,500 mcf/d natural gas
^(7)	Comprised of approximately 850 bbl/d light and medium oil, 350 bbl/d NGL and 1,800 mcf/d natural gas
^(8)	Comprised of approximately 640 bbl/d light and medium oil, 240 bbl/d NGL and 6,720 mcf/d natural gas
^(9)	Capital E&D budget includes exploration and development capital, ESG initiatives, and facilities but excludes asset acquisitions and dispositions, ARO, land and seismic.
^(10^)	Comprised of 17,500-18,000 bbl/d light and medium oil, 30,000-31,000 bbl/d heavy oil, 3,400-3,600 bbl/d NGL and 67,000-69,000 mcf/d natural gas
^(11)	Excludes the impact of transaction costs to G&A in the fourth quarter

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.

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; future intentions with respect to return of capital, including enhanced dividends and share buybacks; oil and natural gas production levels, adjusted funds flow, and free funds flow; anticipated operational results for Q3 2022 including, but not limited to, estimated or anticipated production levels, capital expenditures and drilling plans; the Company's capital program, guidance and budget for Q4 2022 and Q4 2022 capital program; use of proceeds from the Non-Core Viking disposition; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; successful integration of the Deltastream assets; the ability of the Company to achieve drilling success consistent with management's expectations; risk management activities, Tamarack's commitment to ESG principles and sustainability; 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 characteristics of recently acquired assets, including the Deltastream assets; the successful integration of recently 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: 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; 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; the COVID-19 pandemic; and Russia's military actions in Ukraine. 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 annual information form for the year ended December 31, 2021 and the MD&A for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedar.com.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, prospective results of operations and production, weightings, operating costs, Q4 2022 capital budget and expenditures, balance sheet strength, adjusted funds flow and free funds flow, including pro forma the acquisition of Deltastream and the Non-Core Viking Disposition, 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.

References in this press release to peak rates, test 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 test rates should be considered to be preliminary. 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 "NGLs" throughout this press release comprise pentane, butane, propane, and ethane, being all NGLs 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.

Specified Financial Measures

This press release includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios and capital management 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 taxes and adding back changes in non-cash working capital, expenditures on decommissioning obligations and transaction costs since Tamarack believes the timing of collection, payment or incurrence of these items is variable. While current income taxes will not be paid until Q1/23, management believes adjusting for estimated current income taxes in the period incurred 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 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.

"Free funds flow (capital management measure)" (previously referred to as "free adjusted funds flow") 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.

"Operating field netback (non-IFRS financial measure or ratio)" is calculated as 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 field netback an important measure to evaluate Tamarack's operational performance, as it demonstrates field level profitability relative to current commodity prices. See the MD&A for a detailed calculation and reconciliation of operating field netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS. 

"Operating netback (non-IFRS financial measure or ratio)" is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties, net production expenses and transportation expense (non-IFRS financial measure). This metrics can also be calculated on a per boe basis (non-IFRS financial ratio). Management considers operating netback an important measure to evaluate Tamarack's operational performance, as it demonstrates field level profitability relative to current commodity prices. See the MD&A for a detailed calculation and reconciliation of operating netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS.

"Net debt (capital management measure)" is calculated as credit facilities plus senior unsecured notes, plus working capital surplus or deficit, plus other liability, including the fair value of cross-currency swaps plus government loans, less notes receivable and excluding the fair value of financial instruments, decommissioning obligations, lease liabilities and the cash award incentive plan liability.

"Net debt to annualized adjusted funds flow (capital management measure)" is calculated as estimated period end net debt divided by the annualized adjusted funds flow for the preceding quarter (multiplied by 4 for annualization).

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.sedar.com.

SOURCE Tamarack Valley Energy

Brian Schmidt, President & CEO, Tamarack Valley Energy Ltd., Phone: [phone], www.tamarackvalley.ca; Steve Buytels, VP Finance & CFO, Tamarack Valley Energy Ltd., Phone: [phone], www.tamarackvalley.ca