CALGARY, AB, May 4, 2021 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company”) is pleased to announce its financial and operating results for the three months ended March 31, 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 months ended March 31, 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 effective execution of our drilling program and integration of the Clearwater acquisitions. The Company exceeded our Clearwater winter drilling program exit production expectations with volumes greater than 4,000 bbl/d(1). Furthermore, we continued to deliver on our strategy of enhancing the sustainability and resilience of our free adjusted funds flow(2) with the closing of the Greater Nipisi and Provost acquisitions on March 25th, which added ~2,800 boe/d(3) of low decline oil production under waterflood and grew our highly economic Clearwater oil inventory. These transactions, combined with our recently announced Anegada Oil Corp. acquisition continue to drive down our sustaining free adjusted funds flow breakeven price(2) to the mid US$30/bbl, while offering significant upside to shareholders through a sector leading total return profile. In addition, we remain focused on advancing the 2021 initiatives and targets set within our robust environmental, social and governance (“ESG”) reporting.”
Q1 2021 Financial and Operating Highlights
- Closed two separate agreements in March 2021 to acquire assets in the Greater Nipisi and Provost areas of Alberta, including approximately 2,800 boe/d(3)of low decline (~16%) oil weighted assets under waterflood and approximately 38,400 net acres in the Clearwater oil play of Alberta for a net cash purchase price of approximately $121 million. These acquisitions were financed through a combination of debt, a $68.2 million bought deal financing (30.3 million common shares at $2.25 per share) and a gross overriding royalty (“GORR”) disposition on the newly acquired Greater Nipisi Clearwater and Slave Point lands for proceeds of approximately $13.5 million.
- Achieved quarterly production of 23,938 boe/d in Q1/21, a 2% increase over the same period in 2020.
- Generated adjusted funds flow(2)of $41.2 million in Q1/21 ($0.16 per share basic and diluted).
- Invested $48.7 million in exploration and development (“E&D”) capital expenditures, excluding acquisitions, during Q1/21, which contributed to the drilling of 44 (42.3 net) wells, comprised of 22 (22.0 net) Viking oil wells, 16 (15.5 net) Clearwater oil wells, two (0.8 net) Falher gas wells and four (4.0 net) water source and injector wells. The Company continued to direct significant capital to our Viking waterflood program which represented approximately 34% of the total E&D capital expenditures.
- Successfully executed on our Viking waterflood program, with first quarter production exit volumes of approximately 2,540 bbls/d of light oil, delivering 91% growth on Q1/21 average volumes versus Q1/20.
Tamarack executed a successful winter capital program with the drilling of 16 (15.5 net) wells, with the faster execution of drilling operations enabling three wells from our planned second quarter to be accelerated to the first quarter. The winter drilling program exit production volumes in excess of 4,000 bbl/d(1) exceeded previous expectations. The outperformance was driven by better than forecast well results, with the winter program exhibiting stabilized average IP30 rates (6 leg horizontal wells) of approximately 170 bbl/d, exceeding Tamarack’s Nipisi internal type 1 curve of 147 bbl/d (see the Company’s investor presentation for additional details). Drilling results on the Company’s newly acquired Nipisi have exhibited some of the strongest results seen to date with IP30 rates of 235, 300 and 253 bbl/d respectively. Well costs continue to track below internal estimates, averaging approximately $1.06 million (drill, complete, equip and tie-in) versus our planned costs of $1.1 million per well.
The Company plans to keep one rig active through Q2/21 with a seven well program, ramping back up to two rigs in Q3/21, with plans to convert 27 six-leg wells to 23 seven to eight leg wells. The seven to eight leg wells are expected to enhance the economics of the play, with internal estimates of an incremental $950,000 of net present value (discounted at 10%) per section. In total, Tamarack plans to drill 38 horizontal Clearwater wells on a total capital program investment of $54 million, driving Q4/21 production from the play to over 5,000 bbl/d(4). In addition, the Company has commenced construction of a gas gathering system to further gas conservation efforts and plans to pilot our first waterflood in the Nipisi area in Q4/21.
Anegada Transaction & Updated Guidance
Subsequent to the end of the quarter, Tamarack entered into a definitive agreement to acquire Anegada Oil Corp. (“Anegada”) – a privately held, pure play, Charlie Lake light oil producer – for total net consideration of $494 million (the “Acquisition”), after deducting the proceeds from a newly created 2% GORR on the acquired assets. As announced on April 28th, 2021, the Company has received written consent from shareholders holding a majority of the issued and outstanding shares to approve the Acquisition and as such will not be holding a special meeting on the Acquisition. Furthermore, on May 4, 2021, Tamarack and Anegada received the required approval from Competition Bureau under the Competition Act (Canada) with respect to the Acquisition. With receipt of the Competition Act approval, the parties intend to work expeditiously towards closing the Acquisition and anticipate closing will occur on or about May 31, 2021.
Concurrent with the Acquisition, Tamarack provided updated 2021 pro-forma guidance effective June 1, 2021.
|Preliminary 2021 Guidance||Tamarack March
|Capital Budget ($MM)||125 – 130||165 – 175|
|Average Production(5) (boe/d)||26,000||33,000|
|% Oil and NGL||66 – 68||67 – 69|
|Adjusted Funds Flow(2) ($MM)||215 – 220||290 – 295|
|Free Adjusted Funds Flow(2) ($MM)||85 – 90||120 – 125|
|Year End Net Debt to Q4 Annualized Adj. Funds Flow(2)||<1.0x||<1.2x|
|Free Adjusted Funds Flow Breakeven(2) (US$/bbl WTI)||~$40||<$36|
Pro-Forma acquisition guidance numbers are based on pricing assumptions of: a WTI price of US$58.65/bbl; an MSW/WTI differential of US$4.00/bbl; an AECO price of $2.45/GJ; and a USD/CAD exchange rate of $1.2545.
Tamarack congratulates Mr. Ken Cruikshank, Vice President Land, on his retirement effective June 30, 2021. Tamarack would like to thank Mr. Cruikshank for his contributions to the Company since its inception, which span more than eleven years. The Company has planned for succession and has senior experience that will ensure efficient execution moving forward.
“On behalf of the board of directors, executive management team and all of our staff, I would like to extend sincere appreciation to Ken for his many contributions which are imprinted in our success. He has been instrumental in building the Company to what it is today” said Brian Schmidt, President and Chief Executive Officer. “We wish him well in his retirement.”
Financial & Operating Results
|Three months ended|
|($ thousands, except per share)|
|Total oil, natural gas and processing revenue||93,434||66,283||41|
|Cash flow from operating activities||38,436||46,359||(17)|
|Per share – basic||$ 0.14||$ 0.21||(33)|
|Per share – diluted||$ 0.14||$ 0.21||(33)|
|Adjusted funds flow(2)||41,236||42,045||(2)|
|Per share – basic(2)||$ 0.16||$ 0.19||(16)|
|Per share – diluted(2)||$ 0.16||$ 0.19||(16)|
|Per share – basic||(0.00)||$ (1.13)||100|
|Per share – diluted||(0.00)||$ (1.13)||100|
|Weighted average shares outstanding (thousands)|
|Share Trading (thousands, except share price)|
|High||$ 2.46||$ 2.27||9|
|Low||$ 1.25||$ 0.39||221|
|Trading volume (thousands)||181,132||58,945||207|
|Average daily production|
|Light oil (bbls/d)||10,120||12,867||(21)|
|Heavy oil (bbls/d)||2,654||180||1,374|
|Natural gas (mcf/d)||52,466||52,912||(1)|
|Average sale prices|
|Light oil ($/bbl)||64.01||46.42||38|
|Heavy oil ($/bbl)||48.00||49.76||(4)|
|Natural gas ($/mcf)||3.15||1.61||96|
|Operating netback ($/Boe)(2)|
|Average realized sales||43.03||30.76||40|
|Net production and transportation expense(2)||(11.17)||(9.98)||12|
|Operating field netback ($/Boe)(2)||26.49||17.01||56|
|Realized commodity hedging gain (loss)||(3.81)||5.10||(175)|
|Adjusted funds flow ($/Boe)(2)||19.14||19.64||(3)|
Tamarack will host a webcast at 9:00 AM MT (11:00 AM ET) on May 5, 2021 to discuss the first 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 two 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 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.
|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|
|IFRS||International Financial Reporting Standards as issued by the International
Accounting Standards Board
|MMboe||million barrels of oil equivalent|
|MMcf/d||million 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
Notes to Press Release
|(1)||Comprised of 4,000 bbl/d heavy oil; winter drilling program exit corresponds to April production month|
|(2)||See “Non-IFRS Measures”|
|(3)||Comprised of 2,370 bbl/d light and medium oil, 50 bbl/d NGL and 2,280 mcf/d natural gas|
|(4)||Comprised of 5,000 bbl/d heavy oil|
|(5)||March 2021 comprised of 11,200 bbl/d light and medium oil, 4,400 bbl/d heavy oil, 2,100 bbl/d NGL and 49,800 mcf/d natural gas; Post-acquisition guidance comprised of 15,400 bbl/d light and medium oil, 4,400 bbl/day heavy oil, 3,000 bbl/d NGL and 61,200 mcf/d natural gas|
|(6)||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.
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; the Acquisition, the GORR and the timing thereof; satisfaction or waiver of the closing conditions to the Acquisition; the purchase price of the Acquisition net proceeds from the GORR and closing adjustments; the anticipated benefits of the Acquisition, including the impact of the Acquisition and the GORR on the Company’s operations, inventory and opportunities, financial condition, access to capital and overall strategy; expectations with respect to reserves, oil and natural gas production levels (including the ability to support current production for the next decade), operating field netbacks, decline rates, adjusted funds flow, free adjusted funds flow and net debt to Q4 annualized adjusted funds flow relating to the Anegada and Tamarack following the Acquisition; 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 receipt of all approvals and satisfaction of all conditions to the completion of the Acquisition; 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: counterparty risk to closing the Acquisition; 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 the Acquisition); 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, 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 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.
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 “year-end net debt to Q4 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.
“Year-End Net Debt to Q4 Annualized Adjusted Funds Flow” is calculated as estimated year-end Net Debt divided by the annualized estimated Adjusted Funds Flow for the fourth 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