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CALGARY, AB, Oct. 27, 2021 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company”) is pleased to announce its financial and operating results for the three and nine months ended September 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 nine months ended September 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: “The third quarter was very strong operationally and included the successful integration of the Charlie Lake assets into our portfolio. I am very proud and confident in our team’s ability to execute and drive outperformance in our assets, which is evident through our production guidance increase for 2021. Tamarack is pleased to announce its inaugural dividend and return of capital framework. Our plan to initiate a sustainable base monthly dividend commencing in January 2022, with the framework working towards distributing up to 50% of our free funds flow(1) as we reach our long-term debt target. The successful repositioning of the Company into the Clearwater and Charlie Lake oil plays, coupled with our strong portfolio of waterflood assets is expected to generate sustainable long-term growth in free funds flow(1) and return of capital to shareholders.”
Q3 2021 Financial and Operating Highlights
- Achieved quarterly production volumes of 41,256 boe/d(2)in Q3 2021, representing a 92% increase compared to the same period in 2020.
- Generated adjusted funds flow(1)of $102.5 million in Q3 2021 ($0.25 per share basic and diluted) compared to $30.8 million in the same period in 2020 ($0.14 per share basic and diluted) and $216.2 million for the nine months ended September 30, 2021 ($0.64 per share basic and $0.63 per share diluted) compared to $93.9 million in the same period in 2020 ($0.42 per share basic and diluted).
- Generated free funds flow(1), excluding acquisition expenditures, of $32.5 million and net income of $20.0 million during the quarter.
- Invested $70.0 million in exploration and development (“E&D”) capital expenditures, excluding acquisitions, during the third quarter of 2021. This contributed to the drilling of 8 (8.0 net) Clearwater oil wells, 7 (7.0 net) Charlie Lake oil wells and 3 (3.0 net) Viking oil wells along with the investment in the Nipisi Clearwater gas gathering project, which currently is conserving 2.0 mmcf/d of natural gas, and other Clearwater infrastructure initiatives.
- Exited the third quarter with $519.7 million of net debt(1)with a forecasted 2021 year-end net debt to Q4 annualized adjusted funds flow(1) of less than 1.2x.
- Successfully executed $42.9 million of further tuck-in acquisitions in the Clearwater oil (previously announced Southern Clearwateracquisition) and Charlie Lake light oil plays which included 53 net sections of land and 63 gross (59.7 net) future drilling locations(3) in the Clearwater and added 20 gross (12.5 net) sections in the Charlie Lake. These acquisitions further our strategy of both adding to and enhancing the resiliency of our drilling inventory and free funds flow(1)
2021 Guidance Increase & Preliminary 2022 Capital Program
Given the strong operational outperformance, Tamarack is pleased to provide updated production guidance for both the second half and full year 2021.
- Production Guidance Increase –Second half 2021 production guidance is increased to 40,500 boe/d(4) with full year production guidance of 34,250 boe/d(4) up from 33,000 boe/d.
- Preliminary 2022 Capital Program – Tamarack plans to spend $200 to $225 million in 2022 and plans to announce its comprehensive 2022 budget in January 2022.
Dividend Policy and Return of Capital Framework
Tamarack is pleased to announce the implementation of its dividend policy and return of capital framework. The free funds flow(1) return will be achieved through modest, sustainable base dividend growth, special dividends and tactical share buybacks.
- Sustainable Base Dividend –Providing shareholders with a sustainable base monthly dividend which grows in conjunction with earnings over time is a key focus for the Company. Tamarack will initiate a base dividend of up to 25% of free funds flow(1) predicated on the Tamarack five-year plan price deck of US$55/bbl WTI and $2.50/GJ AECO. The remainder of free funds flow(1) will primarily be allocated to net debt(1) reduction and strategic asset acquisitions in existing core areas.
- Enhanced Return to Shareholders – Once the Company reaches its long term $250 to $300 million net debt(1)target, Tamarack plans to return up to 50% of the previous quarter’s free funds flow(1) inclusive of base dividends, taking into consideration market conditions, to its shareholders through tactical share buybacks and/or special dividends. The long-term debt target is predicated on a forecasted year-end net debt to trailing annual adjusted funds flow(1) of 1.0x at US$45/bbl WTI. The remaining 50% of free funds flow(1) will be allocated to further debt repayment and future acquisitions.
Given the continued success of our development program and strong free funds flow(1) generation, Tamarack expects the inaugural monthly cash dividend of $0.0083 per share to be payable on February 15, 2022, to holders of common shares (“Common Shares”) of the Company of record at the close of business on January 31, 2022. The base dividend is modelled to be sustainable down to less than US$35/bbl WTI and at US$70/bbl WTI would only represent 7% of 2022 adjusted funds flow(1), highlighting the resiliency of the dividend level. On current strip pricing, the Company looks to achieve its long-term debt target of $250 to $300 million in the second half of 2022. The base dividend will be designated as an “eligible dividend” for Canadian federal and provincial income tax purposes. Dividends paid to shareholders who are non-residents of Canada will be subject to Canadian non-resident withholding taxes.
Strategic and opportunistic M&A remains a key focus for Tamarack in enhancing and growing the sustainable free funds flow(1) for the Company and shareholders. The Company will continue to execute potential M&A in a disciplined manner with a focus on free funds flow breakeven(1) levels and debt adjusted free funds flow(1) per share accretion within our five-year plan.
NCIB Application
Tamarack has applied to the TSX for approval of a normal course issuer bid (“NCIB”). If approved, the NCIB would allow Tamarack to purchase up to approximately 20,354,360 common shares (representing approximately 5% of the 407,087,206 outstanding Common Shares as of October 25, 2021) over a period of twelve months. The actual number of Common Shares which may be purchased pursuant to the NCIB would be determined by management of the Company. Any Common Shares that are purchased under the NCIB would be cancelled upon their purchase by Tamarack.
The NCIB would provide an additional tool for the reinvestment of excess free funds flow(1) to increase long-term total shareholder returns. Tamarack believes that, at times, the prevailing share price does not reflect the underlying value of the Common Shares and the repurchase of Common Shares represents an opportunity to improve per share metrics. As with all expenditures, if the NCIB is approved, Tamarack will remain vigilant in ensuring it retains flexibility and liquidity on its balance sheet.
Operations & Sustainability Update
Tamarack has one rig active in the Charlie Lake with 2 (2.0 net) wells planned to be drilled during the fourth quarter and has two rigs active in the Clearwater play (one operated and one non-operated) with plans for 8 (7.0 net) wells to be drilled. The Company continues to achieve production rates ahead of our internal type curves in both the Charlie Lake and Clearwater oil plays. Tamarack remains on track with its planned production range of 12,000-13,000 boe/d(5) for the Charlie Lake asset going forward, with current production in excess of 13,000 boe/d(5). Total Clearwater production averaged 5,450 boe/d(6) for the third quarter with current production of approximately 5,750 boe/d(6). The Company is also pleased to announce the completion of its Nipisi Clearwater gas gathering project during the third quarter which is currently conserving approximately 2.0 mmcf/d of natural gas. In addition, technical work continues to progress on an initial Clearwater waterflood pilot which is expected to be initiated in the first quarter of 2022 in West Nipisi.
Tamarack’s commitment to progressing our environment, social and governance (“ESG”) initiatives continued during the third quarter with the commissioning of our Nipisi Clearwater gas conservation project in addition to furthering our community engagement and Indigenous partnerships. Tamarack plans to release our 2021 Sustainability Report in November of this year.
Investor Webcast
Tamarack will host a webcast at 9:00 AM MT (11:00 AM ET) on October 28, 2021 to discuss the third 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.
Financial & Operating Results
| Three months ended | Nine months ended | |||||
| September 30, | September 30, | |||||
| 2021 | 2020 | % change | 2021 | 2020 | % change | |
| ($ thousands, except per share) | ||||||
| Total oil, NGL, natural gas and processing revenue | 212,265 | 57,790 | 267 | 457,867 | 157,200 | 191 |
| Cash flow from operating activities | 100,558 | 26,965 | 273 | 179,247 | 101,431 | 77 |
| Per share – basic | $ 0.25 | $ 0.12 | 108 | $ 0.53 | $ 0.46 | 15 |
| Per share – diluted | $ 0.24 | $ 0.12 | 100 | $ 0.52 | $ 0.46 | 13 |
| Adjusted funds flow (1) | 102,486 | 30,837 | 232 | 216,179 | 93,854 | 130 |
| Per share – basic (1) | $ 0.25 | $ 0.14 | 79 | $ 0.64 | $ 0.42 | 52 |
| Per share – diluted (1) | $ 0.25 | $ 0.14 | 79 | $ 0.63 | $ 0.42 | 50 |
| Net income (loss) | 20,032 | (5,776) | 447 | 250,060 | (293,164) | 185 |
| Per share – basic | $ 0.05 | $ (0.03) | 267 | $ 0.74 | $ (1.32) | 156 |
| Per share – diluted | $ 0.05 | $ (0.03) | 267 | $ 0.73 | $ (1.32) | 155 |
| Net debt (1) | (519,708) | (199,561) | 160 | (519,708) | (199,561) | 160 |
| Capital expenditures (7) | 69,978 | 10,364 | 575 | 149,487 | 90,455 | 65 |
| Weighted average shares outstanding (thousands) | ||||||
| Basic | 406,152 | 221,611 | 83 | 335,913 | 221,610 | 52 |
| Diluted | 414,342 | 221,611 | 87 | 344,072 | 221,610 | 55 |
| Share Trading (thousands, except share price) | ||||||
| High | $ 3.31 | $ 1.09 | 204 | $ 3.31 | $ 2.27 | 46 |
| Low | $ 2.05 | $ 0.70 | 193 | $ 2.05 | $ 0.39 | 426 |
| Trading volume (thousands) | 180,490 | 56,013 | 222 | 346,720 | 181,659 | 91 |
| Average daily production | ||||||
| Light oil (bbls/d) | 19,405 | 10,309 | 88 | 14,720 | 11,424 | 29 |
| Heavy oil (bbls/d) | 5,438 | 159 | 3,320 | 4,275 | 165 | 2,491 |
| NGL (bbls/d) | 4,257 | 2,162 | 97 | 3,243 | 1,766 | 84 |
| Natural gas (mcf/d) | 72,935 | 53,420 | 37 | 62,171 | 51,986 | 20 |
| Total (boe/d) | 41,256 | 21,533 | 92 | 32,600 | 22,019 | 48 |
| Average sale prices | ||||||
| Light oil ($/bbl) | 79.12 | 46.77 | 69 | 74.43 | 39.58 | 88 |
| Heavy oil ($/bbl) | 67.97 | 38.31 | 77 | 61.40 | 35.27 | 74 |
| NGL ($/bbl) | 33.67 | 23.57 | 43 | 36.37 | 19.29 | 89 |
| Natural gas ($/mcf) | 3.44 | 1.61 | 114 | 3.14 | 1.53 | 105 |
| Total ($/boe) | 55.73 | 29.02 | 92 | 51.27 | 25.97 | 97 |
| Operating netback ($/Boe) (1) | ||||||
| Average realized sales | 55.73 | 29.02 | 92 | 51.27 | 25.97 | 97 |
| Royalty expenses | (8.97) | (2.87) | 213 | (7.51) | (2.95) | 155 |
| Net production and transportation expenses (1) | (10.53) | (10.64) | (1) | (10.75) | (10.21) | 5 |
| Operating field netback ($/Boe) (1) | 36.23 | 15.51 | 134 | 33.01 | 12.81 | 158 |
| Realized commodity hedging gain (loss) | (6.21) | 2.42 | (357) | (5.62) | 5.28 | (206) |
| Operating netback | 30.02 | 17.93 | 67 | 27.39 | 18.09 | 51 |
| Adjusted funds flow ($/Boe) (1) | 27.00 | 15.57 | 73 | 24.29 | 15.56 | 56 |
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to free funds flow generation and financial stability through 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 on Charlie Lake, Clearwater and EOR plays 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 | barrels |
| bbls/d | barrels per day |
| boe | barrels of oil equivalent |
| boe/d | barrels of oil equivalent 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 |
| 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 |
Reader Advisories
| Notes to Press Release | |
| (1) | See “Non-IFRS Measures”; free funds flow and free funds flow breakeven were previously referred to as free adjusted funds flow and free adjusted funds flow breakeven, respectively |
| (2) | Comprised of 19,405 bbl/d light and medium oil, 5,438 bbl/d heavy oil, 4,257 bbl/d NGL and 72,935 mcf/d natural gas |
| (3) | See “Disclosure of Oil and Gas Information – Drilling Locations” |
| (4) | Comprised of 17,500-18,0000 bbl/d light and medium oil, 6,500-7,000 bbl/d heavy oil, 4,000-4,200 bbl/d NGL and 69,500-70,500 mcf/d natural gas for second half and 15,250-15,750 bbl/d light and medium oil, 4,800-5,000 bbl/d heavy oil, 3,300-3,500 bbl/d NGL and 64,000-65,000 mcf/d natural gas for full year |
| (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 5,450 bbl/d heavy oil for the third quarter with 5,475-5,525 bbl/d heavy oil and 15-20 bbl/d NGL and 1,200-1,500 mcf/d natural gas for current production |
| (7) | 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 (“NI 51-101”). 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.
Drilling Locations. This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company’s internal reserves evaluation as prepared by a member of management who is a qualified reserves evaluator in accordance with NI 51-101 and the most recent publication of the most recent publication of the Canadian Oil and Gas Evaluations Handbook effective October 1, 2021 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s assumptions as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the total 63 (59.7 net) drilling locations identified herein, 21 (21.0 net) are proved locations, 11 (11.0 net) are probable locations and 31 (27.7 net) are unbooked locations. Unbooked locations have been identified by management as an estimation of Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations considered for future development will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by the drilling of existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
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 the Company’s five year plan and the anticipated benefits thereof; future consolidation activity and organic growth; future intentions with respect to return of capital including dividends and share buybacks; net debt reduction and debt targets; Tamarack’s intention to return free funds flow to shareholders; the timing and implementation of the dividend policy; the granting of any special dividends or the implementation of any share buyback program or other supplements to the base dividend; statements regarding plans or expectations for the declaration of future dividends and the amount thereof; oil and natural gas production levels, decline rates, adjusted funds flow, free funds flow and net debt to Q4 annualized adjusted funds flow; anticipated operational results for 2021 including, but not limited to, estimated or anticipated production levels, capital expenditures and drilling plans; the Company’s revised capital program, guidance and budget for 2021 and preliminary 2022 capital program; 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; Tamarack’s commitment to ESG principles; the source of funding for the Company’s activities including development costs; Without limitation of the foregoing, future dividend payments, if any, and the level thereof, is uncertain, as the Company’s dividend policy and the funds available for the payment of dividends 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 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 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; 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 Tamarack is unable to implement the dividend policy, or that 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; 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 five year plan, including generating sustainable long-term growth in free funds flow, dividends and share buybacks, 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 funds flow, free funds flow breakeven, net debt, net debt to Q4 annualized adjusted funds flow, year-end net debt to trailing annual adjusted funds flow, debt targets, 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.
Non-IFRS Measures
Certain measures commonly used in the oil and natural gas industry referred to herein, including, “adjusted funds flow”, “free funds flow”, “free funds flow breakeven”, “net production and transportation expenses”, “operating field netback”, “operating netback”, “net debt”, “net debt to Q4 annualized adjusted funds flow” and “year-end net debt to trailing 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 funds flow” (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.
“Free funds flow breakeven” (previously referred to as “free adjusted funds flow breakeven”) is determined by calculating the minimum WTI price in US/bbl required to generate free funds flow equal to zero sustaining current production levels and all other variables held constant. Management believes that free funds flow breakeven provides a useful measure to establish corporate financial sustainability.
“Net debt” 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 Q4 Annualized Adjusted Funds Flow” is calculated as net debt divided by the annualized adjusted funds flow for the most recently completed, or referenced, quarter.
“Year-end Net Debt to Trailing Annual Adjusted Funds Flow” is calculated as estimated year-end net debt divided by the estimated adjusted funds flow for the four preceding quarters at year-end.
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
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