CALGARY, AB, May 10, 2023 /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, 2023. Selected financial and operating information is outlined below and should be read with Tamarack's consolidated financial statements and related management's discussion and analysis (MD&A) for the three months ended March 31, 2023, which are available on SEDAR at www.sedar.com and on Tamarack's website at www.tamarackvalley.ca.
Message to Shareholders
The first quarter of 2023 marked Tamarack's most active quarter in the Company's history, peaking at nine active drilling rigs. Tamarack drilled 40 (39.8 net) horizontal wells in Q1 2023, including 32 (32.0 net) wells in the Clearwater and 8 (7.8 net) wells in the Charlie Lake. The Clearwater program was highlighted by the exploration success at Seal, West Marten Hills and West Nipisi. The Company's first three wells at Seal delivered positive results with production from three stacked Clearwater sands. All three wells came on production from a single pad in March and achieved a combined IP30 rate of 380 bopd(2). Individual well performance IP30 rates include the 'C' sand (6 legs) at 206 bopd(2), 'B' sand (6 legs) at 130 bopd(2) and the 'D' sand (3 legs) at 43 bopd(2).
Total capital spending for the quarter of $148.2 million included approximately $30 million related to the construction of Tamarack's Wembley gas plant and investment in the Clearwater Nipisi pipeline and terminal project. These two major infrastructure projects remain on-time and on budget, with the Wembley plant expected to be commissioned in June 2023. This sweet gas plant is a key component of Tamarack's strategy to increase its egress capacity and concurrently reduce its operating cost structure related to ongoing development of the highly economic Charlie Lake oil play. The Clearwater Nipisi pipeline and terminal project is expected to be on-line at the end of third quarter and will drive operating cost savings along with netback enhancement from blending. When combining both projects, the Company expects to see both operating and transport costs driven lower throughout the year. These two initiatives have the potential to reduce the Company's free funds flow breakeven by US$0.95 – US$1.10/bbl WTI and are key to enhancing free funds flow generation within the context of Tamarack's five-year plan and return of capital framework.
Corporately, production for Q1 2023 averaged 67,938 boe/d(3), representing a 64% year-over-year increase and a 6% increase over the fourth quarter of 2022. Production through January and February averaged over 68,800 boe/d. the success of our drilling and exploration program, however, was somewhat muted by an unplanned TC Energy pipeline outage in March, which reduced total quarterly production by approximately 1,000 boe/d(4). Adjusting for this unplanned third-party event, production for Q1 was on track to exceed budget expectations.
The synergies from the combined Tamarack and Deltastream Energy Corp. ("Deltastream") assets are delivering benefits through the scaled-up Clearwater development program. The combined multi-rig program across Nipisi and Marten Hills has enabled coordinated, shared services and the scale to enhance priority access to materials and equipment with our major service providers. The Deltastream assets continue to perform at or above the acquisition forecast, with additional upside and capital efficiency improvement opportunities underway.
Adjusted funds flow(1) of $157.3 million and free funds flow(1) of $9.1 million in the first quarter reflect the production impact of the unplanned third-party outages and a wider year-over-year WCS differential. Subsequent to the end of Q1 2023, the WCS differential has narrowed materially and current forward pricing indicates narrower WCS differentials through the balance of 2023. Looking ahead, management expects second quarter realized pricing to improve relative to the first quarter. As part of our ongoing risk management program, Tamarack has been proactive in responding to these differential improvements by locking in a portion of our heavy oil production with WCS differential swaps through to Q2 2024, which will reduce our exposure to potential heavy oil price volatility.
Subsequent to the end of the quarter, Tamarack extended and increased the existing 3-year covenant-based sustainability-linked lending (SLL) facility. The amended SLL has an increased capacity of $875 million (up from $700 million) and a new maturity date of May 10, 2026.
Financial & Operating Results
Three months ended
($ thousands, except per share)
Total oil, natural gas and processing revenue
Cash flow from operating activities
Per share – basic
Per share – diluted
Adjusted funds flow(1)
Per share – basic
Per share – diluted
Net income (loss)
Per share – basic
Per share – diluted
Weighted average shares outstanding (thousands)
Average daily share trading volume (thousands)
Average daily production
Light oil (bbls/d)
Heavy oil (bbls/d)
Natural gas (mcf/d)
Average sale prices
Light oil ($/bbl)
Heavy oil, net of blending expense(1) ($/bbl)
Natural gas ($/mcf)
Operating netback ($/Boe)
Average realized sales, net of blending expense(1)
Net production and transportation expenses(1)
Operating field netback ($/Boe)(1)
Realized commodity hedging loss
Operating netback ($/Boe)(1)
Adjusted funds flow ($/Boe)(1)
2023 Outlook & Guidance Update
The Company's 2023 capital guidance range remains unchanged at $425 million to $475 million(5). Management continues to monitor commodity prices and will remain flexible with its second half capital program. Tamarack continues to target spending at the lower half of the range with a focus on maximizing free funds flow(1) for debt repayment and enhancing shareholder returns as debt thresholds are met. Our 2023 capital guidance maximizes free funds flow(1) generation over both the short and long term, with a significant amount capital in 2023 directed towards waterflood and infrastructure initiatives to set up lower sustaining capital and operating cost requirements throughout our five-year plan.
Subsequent to the first quarter, Tamarack disposed of certain non-core natural gas assets and decommissioning obligations for approximately $2.3 million in gross proceeds consisting of approximately 400 boe/d(6) of production. Our 2023 annual production guidance range has been updated to 67,000 to 71,000 boe/d(7) accounting for the disposition and the unplanned production downtime during the first quarter. Tamarack will provide further updates regarding the impact of the wildfires as additional information becomes available. Our operating cost, transportation expense, royalty, G&A and interest guidance range remain unchanged.
Capital Budget ($mm)(5)
$425 – $475
$425 – $475
Annual Average Production (boe/d)(7)
68,000 – 72,000
67,000 – 71,000
Average Oil & NGL Weighting
81% – 83%
81% – 83%
Royalty Rate (%)
19% – 21%
19% – 21%
$9.00 – $9.50
$9.00 – $9.50
$3.50 – $4.00
$3.50 – $4.00
General and Administrative ($/boe)(9)
$1.25 – $1.35
$1.25 – $1.35
$3.80 – $4.00
$3.80 – $4.00
10% – 12%
$3.75 – $4.10
Leasing Expenditures ($mm)
$3.5 – $4.5
$3.5 – $4.5
Production and Development
The safety of our people and the integrity of our assets is Tamarack's primary focus. The Alberta wildfire situation is currently evolving and as such, we are monitoring this with respect to the potential direct and indirect impacts associated with third party infrastructure and facility disruptions which may impact production. In addition, we are monitoring the impact of these fires to Indigenous and local communities in the areas where we operate to determine ways to assist. Potential downtime estimates and overall impact to Q2 2023 volumes will be a function of overall duration of the events and impacts to regional operations.
Clearwater production averaged 36,800 boe/d(11) in the first quarter representing 54% of corporate production. The Company drilled and brought onstream 32 (32.0 net) wells and commenced injection to 6 (6.0 net) wells in the first quarter. West Marten Hills continues to exceed the Company's expectations, where production has grown organically from approximately 400 boe/d(12) in Q4 2022 to over 3,400 boe/d(12). Initial rates from Tamarack's 2022 drilling at Nipisi and West Marten Hills showed considerable improvement versus the prior year, with an increase of approximately 30% in the average IP30 of 200 bopd(13) relative to the Company's 2021 wells which delivered IP30 rates of approximately 150 bopd(13). This trend has continued in 2023 with IP30 rates of 300 bopd(13) at West Marten Hills as the Company continues to delineate the pool and target areas with favourable viscosity. Building on results in this area Tamarack plans to drill an additional 22 (22.0 net) wells in the second half of 2023.
Tamarack has now drilled 14 (14.0 net) water injection wells at West Nipisi as part of the waterflood expansion. To drive further capital efficiency into the waterflood program Tamarack is utilizing multilateral injectors with two of the wells. The application of multilateral injection in this area is expected to lower overall project costs while achieving similar recoveries relative to single leg injection schemes. The original waterflood pilot producer at 102/13-19-076-07W5 has produced approximately 180,000 bbls to date and the water cut remains stable at approximately 20%. After more than 500 days of production this well is still producing approximately 400 bopd(13). In Marten Hills, Tamarack had two active drilling rigs throughout Q1 and plans to drill a total of 41 (41.0 net) wells in 2023. This activity includes further delineation of the Northwest area of the pool from the 12-26-75-25W4 pad, which will be on production in May 2023. Additionally, Tamarack has converted the first Marten Hills "W" pattern water injector and plans to commence injection in Q2 2023.
To support ongoing development, the Nipisi Battery expansion, complete with terminal connection, is in the final engineering stages and construction will commence in Q2 2023. Once the expansion is operational ~70% of Tamarack's Nipisi oil production will be shipped to sales by pipeline. This project provides for long term value creation through enhanced netback opportunities and blending upside.
Leveraging off our large contiguous land base within the Charlie Lake fairway, Tamarack is successfully deploying pad development and utilizing longer laterals to drive enhanced cost efficiencies and realized free funds flow(1) generation. During the quarter, Charlie Lake production exceeded 16,000 boe/d(14), an almost 20% increase from the preceding quarter on the back of a successful Q4 and Q1 drilling program. The Company drilled 8 (7.8 net) wells during the quarter with 5 (4.8 net) wells commencing production. The Company plans to drill 11 (11.0 net) wells through the balance of 2023 and is driving down costs by increasing multi-well pad operations. The Company is currently completing Tamarack's first three well Charlie Lake pad at 02-12-073-10W6 with an additional three well offsetting pad awaiting completion and drilling underway on a two well pad at 15-32-073-7W6. Continued cost improvement is expected with the second quarter program with an additional four well pad planned for Q4 2023.
Construction of the new Wembley gas plant is key to the multi-well pad strategy. This facility will provide Tamarack with operated, reliable processing capacity backstopped by a firm egress path for Tamarack's ongoing regional development. With an initial capacity of 15 MMcf/d, this plant is expandable and offers visibility to tying-in production from an expanded field program.
Looking ahead, Tamarack is planning a waterflood pilot in Saddle Hills in Q4 2023. This project will capitalize on existing development well spacing that is conducive to successful multistage frac waterflood. Successful pilot results would have material impacts across our Charlie Lake fairway asset base with the long-term potential to tie production into our Wembley facility.
Tamarack continues to drive further inventory expansion through both our Seal Clearwater exploration results and our continued success on the West Nipisi Joint Venture. At Seal, the Company drilled and tested three separate Clearwater equivalent sands off one pad. Total production from the three wells on a peak IP30 basis is approximately 380 bopd(2). The lowermost sand was drilled with only three legs to test the commerciality of the sand, whereas the middle and upper sands were developed with 6-leg multilaterals and laterals approximately 1.25 miles in length. Owing to the strong results, Tamarack will advance to full development on these lands. Given the multiple zones, management expects development at Seal to drive strong capital efficiencies and economics with large-scale multi-well pads pushing lateral lengths to 1.5 miles. Anticipated development would result in pad costs of approximately $34 to $40 million and production rates of 2,200 – 3,000 bopd(2) per pad. At Seal, Tamarack owns 17 net sections with multizone potential and has a farm-in on 7 additional sections to accommodate future delineation.
At West Nipisi, the second well of the joint venture exploration program exhibited a peak IP30 rate of 175 bopd(13) with the first well showing low decline, delivering an IP90 rate of 160 bopd(13). Together, these results push the fairway of two Clearwater sands further to the west. Tamarack expects additional future drilling on these lands given the success of the program.
Return of Capital
The Company remains committed to balancing long-term sustainable free funds flow growth with returning capital to shareholders. The base dividend is currently $0.15/share annually which represents a 4.3% yield at the current share price. Debt repayment remains the immediate focus to achieve our enhanced return of capital thresholds whereby the Company will return from 25% up to 75% of excess funds flow(1) on a quarterly basis.
The Company takes a systematic approach to manage commodity price risk and volatility to ensure sustaining capital, debt servicing requirements and the base dividend are protected through a prudent hedging management program. For the remainder of 2023, approximately ~45% of net after royalty oil production is hedged against WTI with an average floor price of greater than US$65/bbl. Our strategy focuses on downside protection while maintaining upside exposure. Tamarack will continue to utilize financial instruments, including base commodity, associated differentials and foreign exchange. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca) or Tamarack's consolidated financial statements and related management's discussion and analysis for the three months ended March 31, 2023, which are available on SEDAR (www.sedar.com).
Investor Call Tomorrow
9:30 AM MDT (11:30 AM EDT)
Tamarack will host a webcast at 9:30 AM MDT (11:30 AM EDT) on Thursday, May 11, 2023, to discuss the first quarter financial results and an operational update. Participants can access the live webcast via this link or through links provided on the Company's website. A recorded archive of the webcast will be available on the Company's website following the live webcast.
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake, Clearwater and EOR plays in Alberta. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. For more information, please visit the Company's website at www.tamarackvalley.ca.
the natural gas storage facility located at Suffield, Alberta connected to TC Energy's Alberta System
asset retirement obligation; may also be referred to as decommissioning obligation
barrels per day
barrels of oil equivalent
barrels of oil equivalent per day
barrels of oil per day
International Financial Reporting Standards as issued by the International Accounting Standards Board
average production for the first 30 days that a well is onstream
average production for the first 90 days that a well is onstream
thousand cubic feet
thousand cubic feet per day
million cubic feet per day
Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil in Western Canada
Natural gas liquids
Western Canadian select, the benchmark for conventional and oil sands heavy production at Hardisty in Western Canada
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade
Notes to Press Release
See "Specified Financial Measures"
All production and IP30 rates quoted for the Seal development program are comprised entirely of heavy oil.
Q1 2023 production of 67,938 boe/d was comprised of 17,035 bbl/d light and medium oil, 34,399 bbl/d heavy oil, 4,122 bbl/d NGL and 74,293 mcf/d natural gas.
Production impacts of approximately 1,000 boe/d comprised of approximately 200 bbl/d light and medium oil, 650 bbl/d heavy oil, 15 bbl/d NGL and 800 mcf/d natural gas.
Capital expenditures include exploration and development capital, ESG initiatives, facilities land and seismic but exclude asset acquisitions and dispositions as well as ARO. Capital budget includes exploration and development capital, ARO, ESG initiatives, facilities land and seismic but excludes asset acquisitions and dispositions. The key difference between these two metrics is the inclusion (capital budget) or exclusion (capital expenditures) of ARO.
Production of 400 boe/d associated with the non-core asset disposition is comprised of 2,400 mcf/d natural gas.
Target production is comprised of 16,500-17,500 bbl/d light and medium oil, 34,750-36,500 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 71,000-75,000 mcf/d natural gas.
Transportation expense differs from the previously released 2023 guidance due to a change in the classification of pipeline tariffs in our corporate model. Some pipeline tariffs were originally included as a revenue deduction, are now included as transportation expense.
G&A noted excludes the effect of cash settled stock-based compensation.
Tax numbers in the annual guidance numbers are based on 2023 average pricing assumptions of: US$80.00/bbl WTI; US$22.00/bbl WCS; US$3.00/bbl MSW; $4.00/GJ AECO; and $1.3200 CAD/USD.
Q1 2023 Clearwater production of 36,800 boe/d is comprised of approximately 35,100 bbl/d heavy oil, 170 bbl/d NGL and 9,200 mcf/d natural gas.
Q4 2022 West Marten Hills production of approximately 400 boe/d is comprised of 400 bbl/d heavy oil while Q1 2023 West Marten Hills production of approximately 3,400 boe/d is comprised of 3,400 bbl/d heavy oil.
All production and IP30 rates quoted for the Nipisi and West Marten Hills development program are entirely comprised of heavy oil.
Q1 2023 Charlie Lake production of 16,000 boe/d is comprised of approximately 8,850 bbl/d light and medium oil, 2,150 bbl/d NGL and 30,000 mcf/d natural gas.
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.
References in this press release to "crude oil" or "oil" refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to "NGL" throughout this press release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51-101. References to "natural gas" throughout this press release refers to conventional natural gas as defined by NI 51-101.
Forward Looking Information
This press release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; future consolidation activity, organic growth and development and portfolio rationalization; future intentions with respect to debt repayment and return of capital, including enhanced dividends and share buybacks; oil and natural gas production levels, adjusted funds flow and free funds flow; anticipated operational results for 2023 including, but not limited to, estimated or anticipated production levels, capital expenditures, drilling plans and infrastructure initiatives; the anticipated benefits of the Company's major infrastructure projects and the costs and timing thereof; the Company's capital program, guidance and budget for 2023 and flexibility with respect thereto; the potential damage to the Company's facilities and other impacts on operations and production from the Alberta wildfires; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; decline rates and enhanced recovery, including waterflood initiatives; exploration activities; continued integration of the Deltastream assets; the ability of the Company to achieve drilling success consistent with management's expectations; risk management activities, Tamarack's commitment to ESG principles and sustainability; and the source of funding for the Company's activities including development costs. Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the Company's return of capital framework and the funds available for such activities from time to time is dependent upon, among other things, free funds flow financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tamarack to pay dividends and buyback shares will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.
The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack; the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack's properties; the characteristics of recently acquired assets, including the Deltastream assets; the continued integration of recently acquired assets into Tamarack's operations; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products; the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the drilling, completion and tie-in of wells being completed as planned; the performance of new and existing wells; the application of existing drilling and fracturing techniques; prevailing weather and break-up conditions; royalty regimes and exchange rates; impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack's ability to execute its plans and strategies.
Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks relating to the Alberta wildfires, including in respect of safety, asset integrity, shutting in production, impact on production, maintaining 2023 guidance and resumption of operations; risks with respect to unplanned third-party pipeline outages; the risk that future dividend payments thereunder are reduced, suspended or cancelled; unforeseen difficulties in integrating of recently acquired assets into Tamarack's operations, including the Deltastream assets; incorrect assessments of the value of benefits to be obtained from acquisitions and exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); commodity prices; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; volatility in the stock market and financial system; health, safety, litigation and environmental risks; access to capital; the COVID-19 pandemic; and Russia's military actions in Ukraine. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the Company's AIF for the period ended December 31, 2022 and the MD&A for the period ended March 31, 2023 for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedar.com.The forward-looking statements contained in this press release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.
This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about generating sustainable long-term growth in free funds flow, dividends and share buybacks, prospective results of operations and production, weightings, operating costs, 2023 capital budget and expenditures, decline rates, balance sheet strength, realized pricing, adjusted funds flow and free funds flow, net debt, debt repayments, 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 and its management believe that FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Tamarack's guidance. The Company's actual results may differ materially from these estimates.
References in this press release to peak rates, IP30, IP90 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.
Specified Financial Measures
This press release includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios, capital management measures and supplemental financial measures as further described herein. These measures do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and, therefore, may not be comparable with the calculation of similar measures by other companies.
"Adjusted funds flow (capital management measure)" is calculated by taking cash-flow from operating activities, on a periodic basis, deducting current income tax expense and interest expense (excluding fees) and adding back income tax paid, interest paid, expenditures on decommissioning obligations and transaction costs, and deducting or adding back changes in non-cash working capital, as required. since Tamarack believes the timing of collection, payment or incurrence of these items is variable. Management believes adjusting for estimated current income taxes and interest in the period expensed is a better indication of the adjusted funds generated by the Company. 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, pay dividends 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 income per share, which results in the measure being considered a supplemental financial measure. Adjusted funds flow can also be calculated on a per boe basis, which results in the measure being considered a supplemental financial measure.
"Free funds flow and Capital Expenditures (capital management measure)". Fee funds flow is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Capital expenditure is calculated as property, plant and equipment additions (net of government assistance) plus exploration and evaluation additions. 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.
"Net Production Expenses, Revenue, net of blending expense, Operating Netback and Operating Field Netback (Non-IFRS Financial Measures, and Non-IFRS Financial Ratios if calculated on a per boe basis)" Management uses certain industry benchmarks, such as net production expenses, revenue, net of blending expense, operating netback and operating field netback, to analyze financial and operating performance. 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. Blending expense includes the cost of blending diluent to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications and is shown as a reduction to heavy oil revenues rather than an expense as in the financial statements under IFRS. Operating netback equals total petroleum and natural gas sales (net of blending), including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties, net production expenses and transportation expense. Operating field netback equals total petroleum and natural gas sales, less royalties, net production expenses and transportation expense. These metrics can also be calculated on a per boe basis, which results in them being considered a non-IFRS financial ratio. Management considers operating netback and operating field netback important measures to evaluate Tamarack's operational performance, as it demonstrates field level profitability relative to current commodity prices. See the MD&A for a detailed calculation and reconciliation of Tamarack's netbacks per boe to the most directly comparable measure presented in accordance with IFRS.
"Net debt (capital management measure)" is calculated as credit facilities plus senior unsecured notes, plus deferred acquisition payment notes, plus working capital surplus or deficiency, plus other liability, including the fair value of cross-currency swaps, plus government loans, plus facilities acquisition payments, less notes receivable and excluding the current portion of fair value of financial instruments, decommissioning obligations, lease liabilities and the cash award incentive plan liability.
SOURCE Tamarack Valley Energy Ltd.
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