Calgary, Alberta--(Newsfile Corp. - November 6, 2019) - Tamarack Valley Energy Ltd. (TSX: TVE) ("Tamarack" or the "Company") is pleased to announce its financial and operating results for the three and nine months ended September 30, 2019. 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, 2019 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.
Q3 2019 Financial and Operating Highlights
Production averaged 24,171 boe/d (62% oil and NGL weighting), consistent with the previous quarter and reflecting the Company's compliance with the production curtailment order imposed by the Government of Alberta that came into effect on January 1, 2019 (the "Curtailment Order").
Effective October 1, 2019, the Government of Alberta increased the base limit under the Curtailment Order to 20,000 bbls/d and as a result, Tamarack is no longer subject to the Curtailment Order based on its current production levels. Current oil production in Alberta is approximately 14,000 bbls/d.
Total adjusted operating field netback (see "Non-IFRS Measures") in Q3/19 was $49.3 million ($0.22/share basic and diluted), 15% lower than the $57.9 million generated in Q2/19 ($0.26/share basic and $0.25/share diluted) due to lower realized prices partially offset by lower operating costs.
Operating netback (see "Non-IFRS Measures") of $24.50/boe in Q3/19 was 16% lower than the Q2/19 netback of $29.14/boe primarily due to lower realized commodity prices for crude oil and NGL compared to the previous quarter.
Net production and transportation expenses in Q3/19 declined 2% to $9.87/boe compared to $10.12/boe in Q2/19 primarily due to increased production from the lower-cost Veteran area and an increase in processing income.
Invested $58.9 million in the quarter to drill, complete and equip 40.6 net Viking oil wells, 2.0 net water injectors, 2.0 net water source wells and 0.9 net Cardium wells. In addition, the Company completed and brought on production 5.0 net Viking oil wells and 3.5 net Cardium oil wells that were drilled in late Q2/19 and drilled 11.0 net Viking oil wells that will be brought on production in Q4/19.
Completed a Viking oil "tuck-in" acquisition in the Veteran/Consort area of Alberta for $3.8 million, resulting in the addition of 72 boe/d (81% oil and NGL) and 8.5 net sections of undeveloped Viking lands to Tamarack's portfolio.
Encouraging waterflood results to date with corporate declines forecasted to reduce to 34% in 2020 and be under 30% in 2021. In addition, oil production improvements as a result of waterflood reached 860 bbls/d at the end of October, 2019 and internal estimates for Proved plus Probable ("2P") waterflood reserves could be in the 8 to 9 million barrel range by year end.
Financial & Operating Results
|Three months ended||Nine months ended|
|September 30,||September 30,|
|2019||2018 3||% change||2019||2018 3||% change|
|($ thousands, except per share)|
|Total oil, natural gas and processing revenue ||90,542||119,304||(24)||284,686||325,961||(13)|
|Adjusted operating field netback 1||49,283||68,579||(28)||164,692||188,129||(12)|
|Per share - basic 1||$0.22||$0.30||(27)||$0.73||$0.83||(12)|
|Per share - diluted 1||$0.22||$0.29||(24)||$0.71||$0.81||(12)|
|Net income (loss)||(111)||13,004||(101)||11,535||19,358||(40)|
|Per share - basic||(0.00)||$0.06||(100)||$0.05||$0.08||(38)|
|Per share - diluted||(0.00)||$0.06||(100)||$0.05||$0.08||(38)|
|Net debt 1||(213,140)||(192,184)||11||(213,140)||(192,184)||11|
|Capital expenditures 2||58,867||78,149||(25)||156,012||200,453||(22)|
|Weighted average shares outstanding (thousands)|
|Share Trading (thousands, except share price)|
|Trading volume (thousands)||27,820||77,479||(64)||144,882||196,506||(26)|
|Average daily production|
|Light oil (bbls/d)||12,748||14,417||(12)||12,892||13,636||(5)|
|Heavy oil (bbls/d)||440||621||(29)||481||484||(1)|
|Natural gas (mcf/d)||55,224||49,943||11||53,101||51,393||3|
|Average sale prices|
|Light oil ($/bbl)||65.10||76.98||(15)||66.96||73.76||(9)|
|Heavy oil ($/bbl)||56.74||69.33||(18)||54.45||64.29||(15)|
|Natural gas ($/mcf)||1.54||1.63||(6)||2.00||1.84||9|
|Operating netback ($/Boe) 1|
|Average realized sales||40.28||52.29||(23)||43.60||49.60||(12)|
|Net production and transportation expenses||(9.87)||(10.38)||(5)||(10.06)||(10.53)||(4)|
|Operating field netback ($/Boe) 1||26.05||36.61||(29)||29.08||33.89||(14)|
|Realized commodity hedging loss||(1.55)||(4.16)||(63)||(1.21)||(2.75)||(56)|
|Adjusted operating field netback ($/Boe) 1||22.16||30.10||(26)||25.34||28.65||(12)|
(1) Adjusted operating field netback, net debt, operating field netback and operating netback do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other issuers. See "Oil and Gas Metrics" and "Non-IFRS Measures".
(2) Capital expenditures include exploration and development expenditures, but exclude asset acquisitions and dispositions.
(3) IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
Third Quarter Review
Tamarack continued to realize operational efficiencies and drive down costs through the third quarter of 2019, while maintaining production volumes and complying with the Curtailment Order. Third quarter production was consistent with Q2/19, averaging 24,171 boe/d (62% oil and NGL weighting). Tamarack's production of 23,807 boe/d (63% oil and NGL weighting) during the first nine months of 2019 was in the range of its annual guidance of 23,500 boe/d to 24,500 boe/d, despite continued uncertain market egress conditions and the impact of the Curtailment Order. Effective October 1, 2019, the base limit under the Curtailment Order increased from 10,000 to 20,000 bbls/d (the "Curtailment Limit Increase"). Due to the Curtailment Limit Increase, Tamarack is no longer subject to the Curtailment Order based on its current production levels. Current oil production in Alberta is approximately 14,000 bbls/d.
During Q3/19, the Company invested approximately $58.9 million into the continued development of its high-quality, light oil-weighted asset base, advanced its ongoing waterflood program and closed a $3.8 million Viking oil tuck-in acquisition. These capital outlays were largely funded by Tamarack's adjusted operating field netback of $49.3 million with the remainder funded by an increase in net debt (see "Non-IFRS Measures") of $13.4 million. For the nine months ended September 30, 2019, Tamarack invested $156.0 million in total capital, which was fully funded by the $164.7 million of adjusted operating field netback generated during the period. These practices are in-line with the Company's goal of underspending funds generated in order to allocate capital to share buybacks.
Consistent with the Company's commitment to generating per share value, Tamarack invested $3.8 million to purchase and cancel 1,745,100 of its common shares ("Common Shares") under its normal course issuer bid ("NCIB") program during the first nine months of 2019. Subsequent to the end of the quarter, the Company purchased an additional 715,300 Common Shares under the NCIB program for $1.3 million. In addition, the Company directed $1.1 million during Q3/19 to purchase 548,865 Common Shares in the open market, which are held in trust by Tamarack's trustee and used to settle restricted share units ("RSUs") upon future exercises. The NCIB program and open market purchases provide management with an instrument that can be employed when there is a perceived misalignment between Tamarack's prevailing share price and the underlying current and future potential value of its assets. In addition, these programs help to offset the dilutive impact that may be associated with the exercise and settlement of options, RSUs and performance share units issued under Tamarack's stock-based compensation programs. As at September 30, 2019, Tamarack's trustee held a total of 1,016,885 Common Shares in trust.
During the third quarter of 2019, the Company drilled, completed and equipped 42 (40.6 net) Viking oil wells and one (0.9 net) Cardium oil well. In addition to the third quarter drilling program, the Company also completed and brought on production 5.0 net Viking oil wells and four (3.5 net) Cardium oil wells that were drilled in late Q2/19. The Company also drilled 11.0 net Viking oil wells that will be brought on production in Q4/19, resulting in total drilling for the quarter of 53 (51.6 net) Viking oil wells and one (0.9 net) Cardium oil well. Tamarack also directed capital to the continued development of a waterflood program in the Company's Veteran, Alberta area by drilling two injection wells and two water source wells. The waterflood project is designed to improve oil recoveries, reduce corporate decline rates and increase production rates while utilizing Tamarack's existing and owned infrastructure.
In Q3/19, the Company's oil and NGL weighting was 62% compared to 63% in Q2/19. In order to comply with the Curtailment Order during the third quarter, Tamarack redirected capital to drilling Viking wells in Saskatchewan where the oil and NGL weighting tends to be lower. With the Curtailment Limit Increase, the Company can allocate capital back to its Alberta Viking development program in Q4/19.
The Company's operating netback averaged $24.50/boe in Q3/19, which is 16% lower than in Q2/19. This decrease is primarily due to an 11% decrease in revenue per boe and a 4% increase in royalty expenses from Q2/19, which were offset by a 2% reduction in net production and transportation expenses from $10.12/boe in Q2/19 to $9.87/boe in Q3/19.
Tamarack's net debt, including working capital deficiency but excluding the fair value of financial instruments and lease liabilities, totaled $213.1 million as at September 30, 2019 and reflects the draw during Q3/19 to partially fund the capital program. Comparatively, net debt of $195.9 million and $192.2 million were recorded at June 30, 2019 and September 30, 2018, respectively. Tamarack's Q3/19 net debt to annualized adjusted operating field netback ratio (see "Non-IFRS Measures") was 1.1 times. With lower planned capital expenditures in Q4/19, Tamarack expects its net debt to decrease by $25 to $30 million by December 31, 2019.
Veteran Area Waterflood Update
The Company continues to gain positive indications of increasing oil recoveries in the greater Veteran area waterflood project. The Company expects to spend approximately $28 million in 2019, bringing the total spend to $56 million over the past two years. Tamarack currently has 20 water injector wells, six in East Veteran and 14 in the Veteran Unit, plus four horizontal and two vertical water source wells.
Since early 2019, the original two (200 meter spaced) wells in the East Veteran waterflood project have increased oil production from 50 bbls/d in aggregate to 345 bbls/d by the end of October 2019. During the third quarter, the Company drilled and brought on production an additional six wells into the original waterflood pattern where reservoir pressures have increased as a result of water injection since February of 2019. The six new wells were producing an aggregate 415 bbls/d of oil by the end of October 2019, with rates still rising. The Company expects these wells will continue to increase reaching peak production rates in mid-2020, and start to decline thereafter.
To date, the Company focused its Veteran Unit waterflood to a small three injector pattern which covered approximately one section in the area. The Company has seen positive indications of reservoir pressures increasing, nearby well declines shallowing and an estimated 100 bbls/d of increased production from the wells within the pattern. Based on these results, Tamarack has increased the number of injectors in the Veteran Unit from three to 14 during Q3/19. Subsequently, water injection rates in the Veteran Unit increased to 12,000 bbls/d in late October, 2019, compared to an average of 2,260 bbls/d during Q2/19. The impact of water injection increases in the Veteran Unit is not anticipated to result in any production uplift until late 2020 or early 2021.
Based on the growth in production due to the waterflood response, the Company estimates approximately 1.3 to 1.8 million barrels of 2P oil reserves could be converted to the Proved Reserves category with 3.0 to 4.0 million barrels of incremental 2P oil reserves additions within its year-end 2019 independent reserves evaluation. This internal estimate of reserve additions, together with the 5.0 million barrels of oil that were booked in the 2018 third party report, brings the potential total 2P waterflood oil reserves to an estimated 8.0 to 9.0 million barrels. These internal reserves are in line with the expectations the Company had when it initially made the investment decision to commence its waterflood project back in early 2018.
Q4/19 and 2020 Outlook
With a continued focus on optimizing balance sheet strength and enhancing its per share metrics, the Company's capital allocation decisions are regularly assessed. For 2019, Tamarack built its capital plan around being fully self-funded using commodity prices that were, at the time, below strip prices. Based on a Q4/19 WTI average of US$54/bbl and on the 2019 capital program targeting development of its inventory of Viking and Cardium locations that payout in 1.5 years or less (see "Non-IFRS Measures"), Tamarack anticipates generating adjusted operating field netback that exceeds budgeted capital expenditures (excluding tuck-in acquisitions) by approximately $35 to $40 million. The Company's full year production guidance remains intact for 2019, including its plan to invest between $170 million and $180 million (excluding tuck-in acquisitions), which is expected to be fully funded by total adjusted operating field netback based on the Q4/19 WTI forecast. Although total capital levels for 2019 remain unchanged, as a result of the better-than-expected response in the East Veteran waterflood, Tamarack has adjusted its remaining 2019 expenditures to ensure more capital is allocated to this area than originally budgeted.
Having flexibility around capital allocation affords Tamarack the ability to pursue activities that result in the greatest value creation for shareholders in the current environment. As such, the Company may elect to defer further asset enhancements and production growth in favor of continued waterflood expansion and increased share buy backs under its NCIB program, both of which result in longer-term shareholder value creation.
Tamarack's preliminary 2020 budget has been designed to optimize returns, allowing the Company to enhance per share metrics and fully fund its capital expenditure program at commodity prices below the current forward strip. The 2020 preliminary budget reflects the continued volatility in the equity markets, uncertainty of future oil pricing given backwardation of the forward curve, as well as the uncertain prognosis for additional pipeline takeaway capacity from western Canada. In light of management's belief that the Company's prevailing share price does not adequately reflect the underlying value of its assets, Tamarack intends to shift focus from production growth in the near term to a strategy of maximizing adjusted operating field netback relative to capital expenditures. This is expected to ensure that the Company will be able to continue to purchase shares through its NCIB program even if commodity prices remain low. With this strategy, the Company intends to continue to spend approximately half of excess adjusted operating field netbacks to share repurchases under the NCIB program, further optimizing per share metrics and underpinning shareholder value creation. The balance of the adjusted operating field netback can be earmarked for debt repayment or continued accretive tuck-in acquisitions. This strategy will be supported by continued advancement of the Veteran waterflood, which has shown successful results to date and is designed to reduce corporate declines and enhance future reserves bookings.
Tamarack's preliminary 2020 budget anticipates that capital expenditures and average production will remain consistent with 2019 levels and range between $170 to $180 million and 23,500 to 24,500 boe/d, respectively, while the oil and NGL weighting is expected to increase to a range of 64% to 66%. The maintenance capital requirements associated with this spending and production profile are estimated to be in the $115 to $125 million range, with the balance of approximately $55 million earmarked for waterflood projects, which would not be expected to impact decline rates or production materially until 2021. The 2020 plan assumes corporate declines decrease to 34% in 2020, down from 38% in 2019 and the Company estimates that corporate declines reduce to under 30% in 2021 due to the $55 million of waterflood investment planned for 2020. The current 2020 plan is expected to generate approximately $10 million of adjusted operating field netback above required capital expenditure levels assuming US$53/bbl WTI, $1.70/GJ AECO, $0.76 Cdn/US exchange ratio and an MSW / WTI differential of US$7.40/bbl. The formal 2020 capital expenditure program and budget will be finalized and disseminated in mid-January, 2020.
In addition to enhancing its asset base through the waterflood program, Tamarack has also successfully assembled 125 net sections of prospective land for the Lower Mississippian adjacent to its existing Penny assets in Southern Alberta. The Company believes this new targeted play offers low-risk potential to develop light oil opportunities near the Company's existing owned infrastructure. The initial development of the asset will demonstrate the Company's ability to apply new technology to successfully drill and complete a well within this play while generating the level of economics needed to achieve a payout at current strip prices in 1.5 years or less. Should the Lower Mississippian play prove capable of competing for capital with other opportunities within the Company's current portfolio, Tamarack anticipates that an incremental 12 to 15 low-risk locations could be added to its drilling inventory with further upside to delineate.
Since inception, Tamarack has remained committed to enhancing its long-term sustainability through conservative financial management and strong operational execution. This approach has proven successful, as the Company maintained its balance sheet strength through a continued challenging operating environment, while also reducing its corporate decline rate and continuing to buy-back stock. While Tamarack's preliminary 2020 plan is conservative in light of current commodity prices, with lower overall corporate decline rates, the potential of its new Lower Mississippian play and ample liquidity on its credit facility, Tamarack is well positioned to rapidly ramp-up activity to accelerate growth as the broader market becomes more supportive.
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; and (ii) using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily in the Cardium 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.
|bbls/d||barrels per day|
|boe||barrels of oil equivalent|
|boe/d||barrels of oil equivalent per day|
|Mboe||thousand barrels of oil equivalent|
|mcf||thousand cubic feet|
|MMcf||million cubic feet|
|mcf/d||thousand cubic feet per day|
|WTI||West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade|
|AECO||the natural gas storage facility located at Suffield, Alberta connected to TransCanada's Alberta System|
|IFRS||International Financial Reporting Standards as issued by the International Accounting Standards Board|
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 National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. Boe may be misleading, particularly if used in isolation.
Reserves Disclosure. All reserve references in this press release are "Company interest reserves". Company interest reserves are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests payable the Company. It should not be assumed that the present worth of estimated future cash flow presented herein represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Tamarack's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
Oil and Gas Metrics. This press release contains metrics commonly used in the oil and natural gas industry, such as operating field netback and operating netback.
"Operating field netback" is calculated as total petroleum and natural gas sales, less royalties and net production and transportation costs.
"Operating netback" is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity, foreign exchange and interest rate derivative contracts, less royalties and net production and transportation costs.
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; operational execution and the ability of the Company to achieve drilling success consistent with management's expectations; commodity prices; market conditions impacting realized prices; the Company's ability to withstand commodity price volatility; drilling plans including the timing of drilling; 2019 waterflood projects and the impact thereon on oil recoveries, corporate decline rates and production rates; the payout of wells and the timing thereof; expectations regarding timing of development of current inventory; oil and natural gas production levels, including annual average production and exit production in 2019; changes in decline rates and reserve bookings and the timing realization thereof; oil and liquids weighting and changes thereto; the Company's Q4/19 and preliminary 2020 capital budget; finalizing the Company's formal 2020 capital program and budget and timing thereof; the Company's expectations to be self-sustaining in 2019; the Company's expectation of generating adjusted operating field netback that exceeds its budgeted capital expenditures (excluding tuck-in acquisitions) by approximately $35 to $40 million; Tamarack electing to defer asset enhancements and production growth in favor of continued waterflood expansion and increased share buy backs under the NCIB program; Tamarack's intent to use excess total adjusted operating field netback to purchase Common Shares under the NCIB program; future settlements of RSUs; liquidity on existing credit facilities; shareholder returns; enhanced per share metrics; the duration and impact of the Curtailment Order; the Company's compliance with the Curtailment Order; the Company's expectation that Viking oil wells will be brought on production in Q4/19; estimate of adjusted operating field netback generated from Tamarack's 2019 capital program; the re-evaluation of Tamarack's capital allocation strategy; expectations of the Veteran waterflood projects, including estimated capital requirements, corporate decline rates and reserves related thereto; expectations regarding the prospective land for the Lower Mississippian; and Tamarack's position to accelerate growth. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including relating to: 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 lifting of the Curtailment Order and the timing thereof; lower corporate decline rates in 2020 and 2021; accumulating an inventory of Viking and Cardium locations that payout in 1.5 years or less at current commodity prices; 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; and the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation.
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: 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; and access to capital. 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 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 and the Company's annual information form for the year ended December 31, 2018.
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, production, net debt, debt-adjusted production per share, estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio 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 made 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.
Certain financial measures referred to in this press release, such as net debt, debt-adjusted production per share, adjusted operating field netbacks, net debt to annualized adjusted operating field netback ratio and payout, are not prescribed by IFRS. Tamarack uses these measures to help evaluate its financial and operating performance as well as its liquidity and leverage. These non-IFRS financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers.
"Adjusted operating field netback" is calculated by taking net income or loss before taxes and adding back items, including transaction costs, and certain non-cash items including stock-based compensation; accretion expense on decommissioning obligations; depletion, depreciation and amortization; impairment; unrealized gain or loss on financial instruments; and gain or loss on dispositions.
"Net debt" is calculated as long-term debt plus working capital surplus or deficit excluding the fair value of financial instruments and lease liabilities.
"Net debt to annualized adjusted operating field netback ratio" is calculated as net debt divided by annualized adjusted operating field netback for the most recent quarter.
"Payout" is achieved when revenues, less royalties, production and transportation costs are equal to the total capital costs associated with drilling, completing, equipping and tying-in a well.
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.
For additional information, please contact:
President & CEO
Tamarack Valley Energy Ltd.
VP Finance & CFO
Tamarack Valley Energy Ltd.
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