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Tamarack Valley Energy Ltd. Announces Second Quarter Financial Results, Operational Update & Executive Changes


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These translations are done via Google Translate

CALGARY, ABJuly 27, 2021 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company”) is pleased to announce its financial and operating results for the three and six months ended June 30, 2021. Selected financial and operational information is outlined below and should be read in conjunction with Tamarack’s unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2021 and related management’s discussion and analysis (“MD&A”) which are available on SEDAR at www.sedar.com and on Tamarack’s website at www.tamarackvalley.ca.

Brian Schmidt, President and CEO of Tamarack commented: “We are proud to report another very strong quarter driven by the successful integration of Anegada Oil Corp. (“Anegada”) along with the continued execution of our Clearwater and Waterflood operations. The Anegada acquisition complements our balanced asset portfolio and provides further upside and resiliency to our free adjusted funds flow(1) and potential return of capital profile. In addition, we remain focused on advancing the 2021 initiatives and targets set within our robust environmental, social and governance (“ESG”) reporting.”

Q2 2021 Financial and Operating Highlights

  • Successfully closed the acquisition of Anegada on June 1, 2021, providing the Company an entrance into the Charlie Lake light oil play (“Charlie Lake”), one of the most profitable oil plays in North America.
  • The Company’s syndicate of lenders increased the Company’s credit facilities to $600 million and extended the revolving period to May 31, 2022.
  • Achieved quarterly production volumes of 32,416 boe/d(2) in Q2/21, representing a 54% increase compared to the same period in 2020.
  • Generated adjusted funds flow(1) of $71.7 million in Q2/21 ($0.21 per share basic and diluted) compared to $21.0 million in the same period in 2020 ($0.09 per share basic and diluted).
  • Generated free adjusted funds flow(1), excluding acquisition expenditures, of $40.9 million and net income of $230.2 million during the quarter.
  • Invested $30.8 million in exploration and development capital expenditures, excluding acquisitions, during the second quarter of 2021, which contributed to the drilling of 20 (20.0 net) wells, comprised of 10 (10.0 net) Viking oil wells, 8 (8.0 net) Clearwater oil wells and 2 (2.0 net) Charlie Lake oil wells.
  • Exited the second quarter with $506 million of net debt; with a forecasted year end 2021 net debt to Q4 annualized adjusted funds flow(1) of less than 1.2x.

Charlie Lake Update

Tamarack brought on its first two operated Charlie Lake light oil wells in June (12-16-071-08W6 and 02/16-22-073-07W6) with IP30 rates of approximately 1,367 boe/d(3) (1,157 bopd) and 1,048 boe/d(4) (650 bopd), respectively. This compares to the internal TVE Tier 8 development type curve of 482 bbls/d. Production for June and July was impacted by third party plant outages due to the extreme temperatures that plagued the province. However, the Company remains on track with its planned production range of 12,000-13,000 boe/d(5) for the asset going forward, with current production of approximately 13,000 boe/d(5). Tamarack currently has three rigs running with the third and fourth wells in the program rig released.

Clearwater Update

In the quarter Tamarack drilled 8 gross (8.0 net) Clearwater wells in the Nipisi area bringing the yearly total to 23.5 net wells for the year in Nipisi and Jarvie. All the wells in the second quarter were drilled with 8 legs, and Tamarack plans to continue with this strategy throughout the remainder of 2021. Average well production from the second quarter program is 210bbls/d(6) (8-leg laterals) after cleanup versus the 160 bbls/d(6) winter program 6-leg average in the core Nipsi development area with well costs for the eight leg laterals averaging an incremental $105 thousand per well, driving significant capital efficiency gains. Total Clearwater production averaged 4,550bbls/d(7) for the quarter with June averaging approximately 5,000bbls/d(7).

Tamarack plans to drill another 13-14 net wells in Nipisi keeping one rig working throughout the year with a second rig planned to start up in December. Additionally, Tamarack plans to participate in 3-4 net (6-8 gross) wells in the Jarvie area. Gas conservation work is slated to begin at Nipisi in July with commissioning and start up in late September.  In addition to this, technical work continues on a waterflood pilot and high graded areas for a trial have been selected.  Tamarack anticipates drilling the pilot in early Q4 with injection slated to start in late Q4 2021 or early Q1 2022.

Executive Changes

Tamarack wishes to congratulate Mr. Floyd Price, Chairman of the Board, on his retirement effective July 27, 2021. Mr. Price has served on the Board of Directors since inception and successfully guided the company through several key acquisitions and market events. His imprint on strategy and guidance has been key to Tamarack’s success.

Tamarack also congratulates Mr. Dave Christensen, Vice President, Engineering on his retirement effective August 31st, 2021. Mr. Christensen has been an officer of the Company since 2014. We would like to thank him for his many contributions to the company over the years.

As a result of the strategic organizational changes and retirements, Tamarack has made the following executive appointments:

  • Mr. John Rooney, a director of the Company, has been elected to be Chair of the Board of Directors. Mr. Rooney has run several oil and gas companies most recently CEO of Northern Blizzard and Tusk Energy. He currently serves as Chairman of Kara Technologies and is on the Board of Western Energy Services.
  • Mr. Kevin Screen has been promoted to Chief Operating Officer. Mr. Screen has served as Vice President, Production & Operations since he joined the Company in 2011 and has been instrumental in the strategic development and effective operational execution that have driven Tamarack’s success to date.
  • Mr. Martin Malek has been appointed as successor to Mr. Christensen as Vice President, Engineering. Mr. Malek has served in various roles across the organization since joining in 2014. He most recently served as Vice President, Business Development and has been a pivotal driver in Tamarack’s acquisition activity over the past year.

Tamarack is also pleased to announce the appointment of Ms. Christine Ezinga as Vice President, Corporate Planning and Business Development, and Mr. Scott Shimek as Vice President, Production and Operations. Ms. Ezinga brings more than 20 years of industry experience in finance, investor relations and business development, including mergers and acquisitions. Most recently, she held the role of Vice President, Strategy & Planning at Black Swan Energy. Mr. Shimek brings more than 15 years of engineering and operations experience, most recently serving as Vice President, Resource Development at Bonavista Energy Corp. The Company is excited to add the skills and perspectives of these bright young leaders to the strong existing team.

“On behalf of the Board of Directors, executive management team and all of our staff, I would like to extend sincere appreciation to Floyd and Dave for their many contributions which are imprinted in our success. They have been instrumental in building the Company into what it is today” said Brian Schmidt, President and Chief Executive Officer. “We wish them well in retirement. I would also like to congratulate both Kevin and Martin on their new roles and welcome Christine and Scott to Tamarack. We are excited to be able to bring in this exceptional talent to complement our executive team”.

Financial & Operating Results

Three months ended

Six months ended

June 30,

June 30,

2021

2020

  % change

2021

2020

  % change

($ thousands, except per share)

Total oil, natural gas and processing revenue

152,168

33,127

359

245,602

99,410

147

Cash flow from operating activities

40,253

28,107

43

78,689

74,466

6

Per share – basic

$ 0.12

$ 0.13

(8)

$ 0.26

$ 0.34

(24)

Per share – diluted

$ 0.12

$ 0.13

(8)

$ 0.26

$ 0.34

(24)

Adjusted funds flow (1)

71,741

20,972

242

113,693

63,017

80

Per share – basic (1)

$ 0.21

$ 0.09

133

$ 0.38

$ 0.28

36

Per share – diluted (1)

$ 0.21

$ 0.09

133

$ 0.37

$ 0.28

32

Net income (loss)

230,194

(36,067)

738

230,028

(287,388)

180

Per share – basic

$ 0.69

$ (0.16)

531

$ 0.77

$ (1.30)

159

Per share – diluted

$ 0.67

$ (0.16)

519

$ 0.75

$ (1.30)

158

Net debt (1)

(505,992)

(213,066)

137

(505,992)

(213,066)

137

Capital expenditures (8)

30,805

6,218

395

79,509

80,091

(1)

Weighted average shares outstanding
(thousands)

Basic

333,908

221,142

51

300,013

221,612

35

Diluted

341,935

221,142

55

307,608

221,612

39

Share Trading (thousands, except share
price)

High

$ 2.90

$ 1.09

166

$ 2.90

$ 2.27

28

Low

$ 2.16

$ 0.43

402

$ 1.25

$ 0.39

221

Trading volume (thousands)

155,905

66,702

134

337,037

125,647

168

Average daily production

Light oil (bbls/d)

14,535

11,107

31

12,340

11,988

3

Heavy oil (bbls/d)

4,701

156

2,913

3,683

168

2,092

NGL (bbls/d)

3,032

1,466

107

2,728

1,565

74

Natural gas (mcf/d)

60,887

49,610

23

56,699

51,261

11

Total (boe/d)

32,416

20,997

54

28,201

22,265

27

Average sale prices

Light oil ($/bbl)

75.30

24.92

202

70.69

36.46

94

Heavy oil ($/bbl)

61.20

15.47

296

56.47

33.81

67

NGL ($/bbl)

39.57

12.73

211

38.51

16.30

136

Natural gas ($/mcf)

2.77

1.37

102

2.94

1.50

96

Total ($/boe)

51.55

17.42

196

47.95

24.47

96

Operating netback ($/Boe) (1)

Average realized sales

51.55

17.42

196

47.95

24.47

96

Royalty expenses

(7.20)

(2.12)

240

(6.43)

(3.00)

114

Net production and transportation expenses (1)

(10.74)

(10.01)

7

(10.91)

(9.99)

9

Operating field netback ($/Boe) (1)

33.61

5.29

535

30.61

11.48

167

Realized commodity hedging gain (loss)

(6.20)

8.46

(173)

(5.19)

6.68

(178)

Operating netback (1)

27.41

13.75

99

25.42

18.16

40

Adjusted funds flow ($/Boe) (1)

24.32

10.98

121

22.27

15.55

43

Investor Webcast

Tamarack will host a webcast at 9:00 AM MT (11:00 AM ET) on July 28, 2021 to discuss the second quarter financial results and provide an investor 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 long-term growth and the identification, evaluation and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack’s strategic direction is focused on three key principles: (i) targeting repeatable and relatively predictable plays that provide long-life reserves; (ii) using a rigorous, proven modeling process to carefully manage risk and identify opportunities; and (iii) operating as a responsible corporate citizen with a focus on environmental, social and governance (ESG) commitments and goals. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily in the Charlie Lake, Cardium, Clearwater and Viking fairways in Alberta that are economic over a range of oil and natural gas prices. With this type of portfolio and an experienced and committed management team, Tamarack intends to continue delivering on its strategy to maximize shareholder returns while managing its balance sheet.

Abbreviations

AECO

the natural gas storage facility located at Suffield, Alberta connected to TC Energy’s Alberta System

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

Mcf

thousand cubic feet

mcf/d

thousand cubic feet per day

MSW

Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil 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 “Non-IFRS Measures”

(2)

Comprised of 14.535 bbl/d light and medium oil, 4.701 bbl/d heavy oil, 3,032 bbl/d NGL and 60,887 mcf/d natural gas 

(3)

Comprised of 1,157 bbl/d light and medium oil, 38 bbl/d NGL and 1,030 mcf/d natural gas

(4)

Comprised of 650 bbl/d light and medium oil, 74 bbl/d NGL and 1,942 mcf/d natural gas

(5)

Comprised of 6,550-7,200 bbl/d light and medium oil, 1,950-2,000 bbl/d NGL and 21,000-22,800 mcf/d natural gas

(6)

Comprised of 210 bbl/d of heavy oil and 160 bbl/d of heavy oil, respectively

(7)

Comprised of 4,550 bbl/d of heavy oil for Q2 2021 and 5,000 bbl/d of heavy oil for June 2021 

(8)

Capital expenditures include exploration and development expenditures but exclude asset acquisitions and dispositions 

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. Boe may be misleading, particularly if used in isolation.

Type Curves. Certain type curves disclosure presented herein represents estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves represent what management thinks an average well will achieve, based on methodology that is analogous to wells with similar geological features. Individual wells may be higher or lower but over a larger number of wells, management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Additional details on well performance and management’s type curves are available in the presentation on Tamarack’s website at www.tamarackvalley.ca.

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, including with respect to Charlie Lake; expectations with respect to reserves, oil and natural gas production levels, operating field netbacks, decline rates, adjusted funds flow, free adjusted funds flow and net debt to Q4 annualized adjusted funds flow relating Tamarack, including pro forma the acquisition of Anegada; development and drilling plans for Anegada’s assets, including the drilling locations associated therewith and timing of results therefrom; anticipated operational results for 2021 including, but not limited to, estimated or anticipated production levels, capital expenditures and drilling plans; the Company’s capital program, guidance and budget for 2021; expectations regarding commodity prices in 2021; deployment of the Company’s 2021 capital program; the expected allocation of the Company’s 2021 capital expenditure budget; 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; Tamarack’s commitment to ESG principles; the source of funding for the Company’s activities including development costs; development costs, operating costs, general and administrative costs, costs of services and other costs and expenses; and projections of commodity prices and costs, and exchange rates.

The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including relating to: the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack’s properties; the characteristics of Anegada’s assets; the successful integration of Anegada’s 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; 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: unforeseen difficulties in integrating Anegada’s assets into Tamarack’s operations; incorrect assessments of the value of benefits to be obtained from acquisitions and exploration and development programs (including with respect to Anegada); 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; health, safety, litigation and environmental risks; access to capital; and the COVID-19 pandemic. 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, 2020 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 Tamarack’s prospective results of operations and production, weightings, operating costs, capital budget and expenditures, decline rates, profit, operating field netbacks, balance sheet strength, adjusted funds flow, free adjusted funds flow, free adjusted funds flow breakeven, net debt, net debt to Q4 annualized adjusted funds flow, 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 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.

References in this press release to 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.

Non-IFRS Measures

Certain measures commonly used in the oil and natural gas industry referred to herein, including, “adjusted funds flow”, “free adjusted funds flow”, “free adjusted funds flow breakeven”, “net production and transportation expenses”, “operating field netback”, “operating netback”, “net debt” and “net debt to annualized adjusted funds flow”, do not have a standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other companies. These non-IFRS measures are further described and defined below. Such non-IFRS measures are not intended to represent operating profits nor should they be viewed as an alternative to cash flow provided by operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS.

“Adjusted funds flow Adjusted funds flow is calculated by taking cash-flow from operating activities and adding back changes in non-cash working capital and expenditures on decommissioning obligations 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 adjusted funds flow is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions, Management believes that free adjusted 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 adjusted funds flow breakeven” is determined by calculating the minimum WTI price in US/bbl required to generate Free Adjusted Funds Flow equal to zero with no production growth and all other variables held constant. Management believes that Free Adjusted Funds Flow Breakeven provides a useful measure to establish corporate financial sustainability.

“Net debt” is calculated as bank debt plus working capital surplus or deficit, including the fair value of cross-currency swaps and excluding the fair value of financial instruments and lease liabilities.

Net production and transportation expenses” 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 revenue.  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. Transportation expense are an IFRS measure but are included with net production expenses for simplicity of presentation. Full details of these expenses are outlined in the Company’s MD&A.

Operating Field Netback” equals total petroleum and natural gas sales, less royalties and net production and transportation expenses.

“Operating Netback” is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity, interest rate and foreign exchange derivative contracts, less royalties and net production and transportation costs.

“Net Debt to Annualized Adjusted Funds Flow” is calculated as net debt divided by the annualized adjusted funds flow for the most recently completed quarter. 

Please refer to the MD&A for additional information relating to Non-IFRS 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

For further information: Brian Schmidt, President & CEO, Tamarack Valley Energy Ltd., Phone: 403.263.4440, www.tamarackvalley.ca; Steve Buytels, VP Finance & CFO, Tamarack Valley Energy Ltd., Phone: 403.263.4440, www.tamarackvalley.ca

Related Links

www.tamarackvalley.ca



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