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Tamarack Valley Energy Announces Second Quarter 2022 Financial Results, Non-core Asset Disposition, Operational Update, H2 2022 Guidance & Updated Return of Capital Framework

·28 min read

TSX: TVE

CALGARY, AB, July 28, 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 six months ended June 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 six months ended June 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 announce the disposition of non-core Viking assets (the "Non-Core Viking Disposition"), for total gross proceeds of $70 million(2), along with an operational update, H2 2022 guidance and an update to the return of capital framework.

Tamarack Valley Energy Logo (CNW Group/Tamarack Valley Energy)
Tamarack Valley Energy Logo (CNW Group/Tamarack Valley Energy)

Brian Schmidt, President and CEO of Tamarack commented: "We closed and successfully integrated the Rolling Hills Energy Clearwater oil acquisition during the quarter. In addition, our base dividend was increased by 20%, which was underpinned by our strategy and commitment to long-term sustainable free funds flow(1) per share growth, and we initiated our enhanced return framework in Q2 through the purchase of 1.2 million common shares under our Normal Course Issuer Bid (NCIB)"

Q2 2022 Financial and Operating Highlights

  • Achieved quarterly production volumes of 43,777 boe/d(3) in Q2/22, representing a 35% increase compared to the same period in 2021.

  • Generated Q2/22 adjusted funds flow(1) of $203.6 million ($0.47/share basic; $0.46/share diluted).

  • Generated free funds flow(1), excluding acquisition expenditures, of $94.1 million.

  • Generated net income of $143.5 million ($0.33/share basic and diluted) during the quarter.

  • Increased the monthly cash dividends on common shares by 20%, from $0.0083/share in April and May to $0.0100/share in June, and initiated the enhanced return of capital framework with the purchase of 1.2 million common shares under our NCIB.

  • Invested $80.3 million in exploration and development (E&D) capital expenditures and $29.0 million on undeveloped land in the Clearwater and Charlie Lake areas during Q2/22. This contributed to the drilling of 19 (19.0 net) Clearwater oil wells and three (2.8 net) Charlie Lake oil wells. The undeveloped purchases were partially funded through the disposition of a gross overriding royalty (GORR) on certain lands for net proceeds of $14.9 million.

  • Exited the quarter with $470.6 million of net debt(1), inclusive of assets held for sale with respect to the Non-Core Viking Disposition, and net debt to Q2/22 annualized adjusted funds flow(1) of 0.6x.

  • Closed the acquisition of Rolling Hills Energy Ltd. during the quarter, completing the consolidation of the Company's position in the Southern Clearwater fairway for consideration of 9.3 million common shares of Tamarack and $49.3 million in cash.

  • Subsequent to the quarter, completed the disposition of certain assets in the Viking for gross proceeds of $70 million(2). This is consistent with our portfolio rationalization strategy and focus on long-term sustainable free funds flow(1) growth.

Financial & Operating Results


Three months ended

Six months ended

June 30,

June 30,


2022

2021

  % change

2022

2021

  % change

($ thousands, except per share)







Total oil, natural gas and processing revenue

407,195

152,168

168

706,090

245,602

187

Cash flow from operating activities

214,708

40,253

433

347,561

78,689

342

    Per share – basic

$ 0.49

$ 0.12

308

$ 0.81

$ 0.26

212

    Per share – diluted

$ 0.49

$ 0.12

308

$ 0.81

$ 0.26

212

Adjusted funds flow (1)

203,622

71,741

184

352,481

113,693

210

    Per share – basic (1)

$ 0.47

$ 0.21

124

$ 0.83

$ 0.38

118

    Per share – diluted (1)

$ 0.46

$ 0.21

119

$ 0.82

$ 0.37

122

Net income

143,507

230,194

(38)

169,964

230,028

(26)

    Per share – basic

$ 0.33

$ 0.69

(52)

$ 0.40

$ 0.77

(48)

    Per share – diluted

$ 0.33

$ 0.67

(51)

$ 0.39

$ 0.75

(48)

Net debt (1)

(470,563)

(505,992)

(7)

(470,563)

(505,992)

(7)

Capital expenditures(4)

109,483

30,805

255

234,850

79,509

195

Weighted average shares outstanding (thousands)







   Basic

434,924

333,908

30

427,175

300,013

42

   Diluted

438,206

341,935

28

430,406

307,608

40

Share Trading (thousands, except share price)







High

$ 6.48

$ 2.90

123

$ 6.48

$ 2.90

123

Low

$ 4.12

$ 2.16

91

$ 3.90

$ 1.25

212

Trading volume (thousands)

261,745

155,905

68

495,434

337,037

47

Average daily production







   Light oil (bbls/d)

18,233

14,535

25

18,052

12,340

46

   Heavy oil (bbls/d)

10,805

4,701

130

9,172

3,683

149

   NGL (bbls/d)

3,540

3,032

17

3,825

2,728

40

   Natural gas (mcf/d)

67,195

60,887

10

69,082

56,699

22

   Total (boe/d)

43,777

32,416

35

42,563

28,201

51

Average sale prices







   Light oil ($/bbl)

135.66

75.30

80

123.07

70.69

74

   Heavy oil ($/bbl)

115.51

61.20

89

106.91

56.47

89

   NGL ($/bbl)

63.61

39.57

61

59.65

38.51

55

   Natural gas ($/mcf)

7.81

2.77

182

6.73

2.94

129

   Total ($/boe)

102.16

51.55

98

91.54

47.95

91

Operating netback ($/Boe)







   Average realized sales

102.16

51.55

98

91.54

47.95

91

   Royalty expenses

(19.64)

(7.20)

173

(17.75)

(6.43)

176

   Net production and transportation expenses

(13.00)

(10.74)

21

(12.55)

(10.91)

15

Operating field netback ($/Boe) (1)

69.52

33.61

107

61.24

30.61

100

   Realized commodity hedging loss

(9.40)

(6.20)

52

(6.79)

(5.19)

31

Operating netback ($/Boe) (1)

60.12

27.41

119

54.45

25.42

114

Adjusted funds flow ($/Boe) (1)

51.11

24.32

110

45.75

22.27

105








 

Operations Update

Clearwater

Peavine/Seal – Tamarack continued to be active with its Clearwater land expansion strategy to drive long-term sustainable free funds flow(1) growth. The Company accumulated an additional 15 net sections through crown land sales and a strategic farm-in executed during the quarter, bringing our total greater Peavine/Seal land holdings to 77.5 net sections in proximity to competitor activity with strong well results. The Company sees the potential of up to three separate Clearwater sands on the new lands and plans to begin its expanded appraisal program in Q4/22 which will consist of 4-5 wells along with road and drilling pad infrastructure.

West Marten Hills Exploration – Based on the successful West Marten Hills 02/8-33 appraisal well, which exhibited IP30 rates of approximately 150 bopd(5), Tamarack is in the process of building an all-season road into the area with plans to drill an additional seven wells at West Marten Hills in 2022, including an Upper Clearwater A appraisal well.

West Nipisi – Tamarack's strategy at West Nipisi is focused on waterflood development moving forward. The Company has rig released nine of 17 wells planned from 3 different pad sites, all of which are being developed under Tamarack's Nipisi Clearwater waterflood configuration.  Seven wells are currently on production and exhibiting rates within expectations of approximately 200 bopd(6).  Injection commenced on 3 wells at Tamarack's waterflood pilot in early May.  Initial results have been very encouraging, and Tamarack plans to drill an additional 5 injectors in H2/22. Tamarack is currently drilling an appraisal well to test the northwest Nipisi Clearwater sands based on encouraging offsetting competitor well results.

Southern Clearwater – Tamarack continues to actively develop its Clearwater assets in the Jarvie, Perryvale and Meanook areas with two rigs currently operating. 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.  Thirty-two wells have been rig released to date in 2022, with 25 wells currently onstream. The wells currently producing have averaged peak oil rates of greater than 150 bopd(7). The Company plans to drill 48 gross (48.0 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 nine of 17 planned wells onstream in 2022. Results continue to exceed expectations. Most notably, the 100/02-16-071-08W6 well achieved an IP30 of 1,155 bopd (1,685 boe/d(8)) .

During the quarter, the Company experienced significant third-party infrastructure downtime which resulted in a production impact of approximately 2,500 boe/d(9). Current production from the area has averaged approximately 13,500 boe/d(10) month to date in July. The second quarter production impact along with updated third quarter turnaround timing at the Tidewater Midstream Pipestone plant and CNRL TeePee Creek plant is reflected in our guidance for the second half of 2022 below.

Tamarack is advancing plans to construct a new owned and operated gas plant in the Grand 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 first half of 2023. This plant will serve to provide further egress enhancement and cost savings in the Charlie Lake moving forward and could be expanded as part of a Phase 2 development to support future development and processing capacity requirements.

Veteran/Eyehill Waterfloods

Tamarack drilled 13 wells in the H1/2022 capital program targeting the Viking (6.0 net) and Sparky (7.0 net) at its Veteran and Eyehill properties. Through Q2, Tamarack continued to add injection to its Veteran waterflood, completing 6 injector conversions.  The waterflood response in Eyehill is meeting expectations, reaffirming the value of the Sparky asset.

Non-Core Viking Disposition

Subsequent to the quarter, Tamarack closed the disposition of approximately 2,000 boe/d(11) (~44 % liquids) of non-core Viking production for total gross proceeds of $70 million(2). This disposition is consistent with the Company's portfolio rationalization strategy and driving long-term sustainable free funds flow(1) growth. The proceeds from the disposition will be directed towards both debt repayment and capital activity, including Tamarack's increased Clearwater appraisal expenditures in the greater Peavine and Seal area and West Nipisi waterflood programs.

2022 Second Half Capital Budget and Guidance

To reflect the disposition of non-core Viking assets on July 21, 2022, as well as changes in the commodity price environment and inflationary pressures facing the industry, Tamarack is providing H2/22 corporate guidance. The Company remains focused on capital discipline and growing sustainable free funds flow(1) and will proactively adapt our spending plans within the context of the market and inflationary pressures to maximize returns.

A 2022 capital reconciliation table is provided below to highlight the re-distribution of the Viking asset and GORR disposition proceeds into expanded Clearwater appraisal, Clearwater waterflood development and strategic Peavine/Seal land capture to manage overall capital outlay for the year. The Company continues to execute on its strategy of repositioning and growing its footprint in the top tier economic oil plays in North America.

Capital Budget

Exploration and development capital expenditures for the second half of 2022 have been updated to a range of $160-$170 million, totalling $340-$360 million for the year. This capital guidance is inclusive of the future E&D capital associated with the Company's expanded Clearwater appraisal at Peavine/Seal and the West Nipisi waterflood program. It is also inclusive of forecasted inflationary pressures with respect to the higher service and material costs, as well as supply chain constraints facing the industry at this time

Production

Second half production guidance has been updated to a range of 44,500 to 46,500 boe/d(12) to reflect the sale of the non-core Viking assets along with forecasted turnaround activity in the Charlie Lake operating area in the third quarter. The Clearwater appraisal program is expected to have minimal impact to the 2022 production, given the timing of the drill program, with appraisal success setting up development programs for 2023.


H2 2022 Guidance(13)

E&D Capital Budget(14) ($mm)

$160–$170

Annual Average Production(12) (boe/d)

44,500–46,500

Expenses:


Royalty Rate (%)

20–22%

Operating ($/boe)

$10.00–$10.25

Transportation ($/boe)

$3.00–$3.10

General and Administrative ($/boe)

$1.45–$1.55

Taxes ($/boe)(15)

$4.50–$5.00

Leasing Expenditures ($mm)

$1.8

Asset Retirement Obligations ($mm)

$5.0

Revenue:


Average Oil & Natural Gas Liquids Weighting

76 %

Light Oil Wellhead Differential

$3.00-$3.50

Heavy Oil Wellhead Differential

$5.50-$6.00

Price Assumptions:


WTI (US$/bbl)

$85.00

AECO (CAD$/GJ)

$4.00


2022 Annual Capital Expenditure Reconciliation


($mm)

2022 E&D Capital Budget(4) – May 2022 Guidance

$300

+ Strategic Land Acquisitions (Clearwater/Charlie Lake)

$55

+ H2/22 Clearwater Capital Additions:


Peavine/Seal Appraisal

$25

West Nipisi Waterflood Expansion

$15

+ H2/22 Capital Inflation Adjustment

$20

- GORR Disposition

($15)

- Viking Non-Core Disposition Total Proceeds

($70)

Adjusted 2022 Net Capital Expenditure Outlay

$330


Return of Capital Framework

The Company remains committed to balancing long-term sustainable free funds flow(1) growth with returning capital to shareholders and has further defined its return of capital framework to balance debt repayment, future potential acquisitions to bolster our long-term inventory resiliency and increased clarity around delivering enhanced return to shareholders through opportunistic share buybacks and/or enhanced dividends.

The return of capital framework includes the base dividend, which is a structural component of the financial framework and is set at a level approximated to 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, and can be sustainably covered at bottom cycle pricing of less than US$40/bbl WTI. In addition to the base dividend, the Company continues to allocate 50% of its free funds flow(1) to enhanced return of capital, inclusive of base dividends, when net debt(1) is less than $400 million with the remaining 50% allocated to further debt repayment and future acquisition opportunities.

Tamarack executed on its enhanced return during the quarter with the purchase of 1.2 million shares under the Company's NCIB. The incremental net debt(1) associated with the current H1 2022 tax expense, along with the cash considerations for the Rolling Hills Acquisition and the H1 2022 land purchases, were adjusted accordingly when considering the enhanced return debt target.

Base Dividend

As previously announced, the Company increased the base dividend by 20% during the quarter in conjunction with the close of the Rolling Hills acquisition to $0.01/share per month, payable in July. The base dividend increase was driven by the enhanced sustainable free funds flow(1) in conjunction with the base business and H1 2022 Clearwater acquisitions which were accretive to our five year plan at flat pricing of US$55/bbl WTI and $2.50/GJ AECO.

Updated Enhanced Return Framework

Based on the existing return of capital framework outlined above, Tamarack plans to deliver incremental shareholder return as follows:

  • Net debt(1) >$200 million and <$400 million: the Company continues to target to deliver 50% of discretionary free funds flow(1), inclusive of base dividends, from the prior quarter through tactical share buybacks and/or enhanced dividends.

  • Net debt reaches the $200 million floor: the Company will target delivering 75% of discretionary free funds flow(1), inclusive of base dividends, from the prior quarter through tactical share buybacks and/or enhanced dividends.

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 enhanced shareholder returns in 2022 based on the current commodity price outlook.  

Executive Changes

The Company announces the resignation of Mr. Martin Malek as VP Engineering of the Company. As a result of this change, Tamarack is also pleased to announce the promotion of Mr. Ben Stoodley, Director, Clearwater Development, to the role of VP Engineering. Mr. Stoodley has been with Tamarack since August 2021. He brings more than 17 years of industry experience in production engineering, business development and field development, most recently serving as Manager, Development at West Lake Energy (formerly Twin Butte Energy), where he led their development group, focused on conventional heavy and medium oil assets in East Central Alberta.

"On behalf of the Board of Directors, executive management team and all of our staff, I would like to extend sincere appreciation to Martin for his many contributions during the transformation of the Company. His hard work and dedication have been instrumental during the many acquisitions across Tamarack's history" said Brian Schmidt, President and Chief Executive Officer. "We wish him luck in all his future endeavours. I would also like to congratulate Ben on his new role. We are excited to have Ben's contributions and talent as part of our senior leadership team".

Risk Management

The Company manages commodity price risk and volatility through a prudent hedging management program, with approximately 54%, on average, of gross oil production hedged against WTI for the remainder of 2022, through instruments including puts and enhanced collars. Tamarack also has WTI-MSW and WCS differential hedges in place on approximately 42% of our production in 2022. For 2023, the Company has entered into WTI put floors and enhanced collars as it systematically rolls the risk management program forward on approximately 25% of first half production. Tamarack's strategy provides protection to the sustainability of the business and dividend while maximizing upside. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca).  

Investor Webcast

Tamarack will host a webcast at 9:00 AM MDT (11:00 AM EDT) on July 29, 2022 to discuss the second 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

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

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)   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.  

(3)  Comprised of 18,233 bbl/d light and medium oil, 10,805 bbl/d heavy oil, 3,540 bbl/d NGL and 67,195 mcf/d natural gas

(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 150 bbl/d heavy oil

(6)  Comprised of approximately 200 bbl/d heavy oil 

(7)  Comprised of approximately 150 bbl/d heavy oil

(8)  Comprised of 1,155 bbl/d light and medium oil, 285 bbl/d NGL and 1,470 mcf/d natural gas

(9)   Comprised of 1,500 bbl/d light and medium oil, 350 bbl/d NGL and 3,900 mcf/d natural gas

(10) Comprised of 8,150 bbl/d light and medium oil, 1,850 bbl/d NGL and 21,000 mcf/d natural gas

(11) Comprised of 640 bbl/d light and medium oil, 240 bbl/d NGL and ~6,720 mcf/d natural gas

(12) Comprised of 16,500-17,500 bbl/d light and medium oil, 14,000-15,000 bbl/d heavy oil, 3,000-3,500 bbl/d NGL and 63,000-65,000 mcf/d natural gas

(13) Reflective of the Viking Non-Core disposition effective July 21, 2022, with H2/22 average pricing assumptions of: $85.00USD/bbl WTI; 4.00 CAD/GJ AECO; 1.305 CAD/USD; 4.00 USD/bbl MSW; and 21.00 USD/bbl WCS

(14) Capital E&D budget includes exploration and development capital, ESG initiatives, and facilities but excludes asset acquisitions and dispositions, ARO, land and seismic.

(15) Tax costs per boe are particularly sensitive to changes in commodity pricing and are represented here under the Company's best outlook of budget and strip pricing but may change significantly under alternate price conditions in the second half of the year.

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, free funds flow; anticipated operational results for H2 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 H2 2022 and H2 2022 capital program; use of proceeds from the Non-Core Viking Disposition and GORR disposition; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; 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, is 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 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; 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 react 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, H2 2022 capital budget and expenditures, balance sheet strength, adjusted funds flow and free funds flow, including pro forma the acquisition of Rolling Hills 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.

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. 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 loss 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. 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. 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 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 netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS.

"Net debt (capital management measure)" is calculated as bank debt 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 assets held for sale (net of liabilities associated with assets held for sale), 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

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