Tamarack Valley Energy Announces Q3 2024 Financial Results, Updated Corporate Guidance and Dividend Increase
TSX: TVE
Q3 2024 Financial and Operational Highlights
-
Quarterly Production Growth –
Production averaged 65,024 boe/d(1), exceeding the high end of prior guidance, reflecting ongoing strength in corporate performance driven by the
Clearwater andCharlie Lake drilling programs and waterflood initiatives. Q3/24Clearwater production increased to 43,300 boe/d(2) reflecting a 15% (19% per share) increase YoY as Tamarack continues to expand its heavy oil operations. -
Increasing Funds Flow
(3) – Delivered Adjusted Funds Flow(3) of
$220 .4MM ($0.41 per share), and Free Funds Flow(3) of$108 .7MM. YTD Tamarack has generated$297 .7MM of Free Funds Flow(3) which, on a per share basis, represents a 72% increase YoY(4). - Margin Enhancement – Continued cost reductions and better wellhead realizations are driving stronger margins across the business. Per boe transportation expense demonstrated a 43% improvement YoY. Higher pipeline flows, reduced trucking and a one-time royalty cost recovery all contributed to the improvement. Wellhead price realizations continue to improve due to enhanced blending, sales of CWH oil (Clearwater Heavy) and strong trading differentials driven by the TMX pipeline.
-
Delivering Returns to Shareholders
– Total shareholder return value for first nine months of 2024, was
$144 .7MM, or~$0.26 /share(5), including base dividends of$61 .4MM and share buybacks.- Continued Debt Reduction – Exit net debt of
$807 .4MM reflected a further strengthening of the balance sheet. Net debt has been reduced by$176 .2MM YTD. - Increased Share Buybacks – During Q3/24, Tamarack repurchased 12.3MM common shares. During the first nine months of 2024, the Company bought back and cancelled 4.0% of the year-end 2023 shares outstanding.
- Dividend Increase – Tamarack's per share monthly dividend will increase by 2% for the November dividend, payable in December, to
$0.01275 from$0.0125 previously, which equates to$0.1530 annually.
- Continued Debt Reduction – Exit net debt of
-
Expanded Clearwater Infrastructure Partnership – Added a 13th Indigenous community to theClearwater Infrastructure Limited Partnership (the "CIP") arrangement. Tamarack transferred an additional$50 .8MM ofClearwater assets to the partnership for$43 .2MM in cash and retained 15% operated working interest in the assets.
Achieving Success: Plan, Execute & Deliver
"Tamarack's Q3/24 results continue to highlight the quality of the
Q3 2024 Financial & Operating Results
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Three months ended |
Nine months ended |
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|
2024 |
2023 |
% |
2024 |
2023 |
% |
($ thousands, except per share amounts) |
|
|
|
|
|
|
Oil and natural gas sales, before blending |
$ 439,435 |
$ 506,365 |
(13) |
|
$ 1,284,066 |
1 |
Cash provided by operating activities |
240,843 |
199,756 |
21 |
631,414 |
415,645 |
52 |
Per share – basic(3) |
0.45 |
0.36 |
25 |
1.15 |
0.75 |
53 |
Per share – diluted(3) |
0.44 |
0.36 |
22 |
1.15 |
0.74 |
55 |
Adjusted funds flow(3) |
220,419 |
255,199 |
(14) |
627,529 |
569,723 |
10 |
Per share – basic(3) |
0.41 |
0.46 |
(11) |
1.15 |
1.02 |
13 |
Per share – diluted(3) |
0.40 |
0.46 |
(13) |
1.14 |
1.02 |
12 |
Free funds flow(3) |
108,688 |
128,857 |
(16) |
297,693 |
176,203 |
69 |
Per share – basic(3) |
0.20 |
0.23 |
(13) |
0.54 |
0.32 |
72 |
Per share – diluted(3) |
0.20 |
0.23 |
(14) |
0.54 |
0.31 |
72 |
Net income |
93,694 |
8,634 |
985 |
155,837 |
36,874 |
323 |
Per share – basic |
0.17 |
0.02 |
750 |
0.28 |
0.07 |
300 |
Per share – diluted |
0.17 |
0.02 |
750 |
0.28 |
0.07 |
300 |
Net debt(3) |
807,401 |
1,128,030 |
(28) |
807,401 |
1,128,030 |
(28) |
Investments in oil and natural gas assets |
109,032 |
122,759 |
(11) |
323,594 |
388,752 |
(17) |
Weighted average shares outstanding |
|
|
|
|
|
|
Basic |
540,990 |
556,708 |
(3) |
547,074 |
556,399 |
(2) |
Diluted |
545,266 |
558,569 |
(2) |
551,091 |
559,958 |
(2) |
Average daily production |
|
|
|
|
|
|
Heavy oil (bbls/d) |
39,047 |
35,900 |
9 |
37,659 |
35,229 |
7 |
Light oil (bbls/d) |
13,203 |
16,974 |
(22) |
14,422 |
16,797 |
(14) |
NGL (bbls/d) |
2,915 |
3,623 |
(20) |
2,460 |
3,795 |
(35) |
Natural gas (mcf/d) |
59,154 |
72,597 |
(19) |
55,162 |
71,633 |
(23) |
Total (boe/d) |
65,024 |
68,597 |
(5) |
63,735 |
67,760 |
(6) |
Average sale prices |
|
|
|
|
|
|
Heavy oil, net of blending expense ($/bbl)(3) |
$ 85.25 |
$ 92.85 |
(8) |
$ 83.19 |
$ 76.15 |
9 |
Light oil ($/bbl) |
97.79 |
107.83 |
(9) |
96.71 |
98.30 |
(2) |
NGL ($/bbl) |
39.58 |
41.46 |
(5) |
39.32 |
41.51 |
(5) |
Natural gas ($/mcf) |
0.87 |
2.60 |
(67) |
1.72 |
2.84 |
(39) |
Total ($/boe) |
73.62 |
80.22 |
(8) |
74.05 |
69.29 |
7 |
Benchmark pricing |
|
|
|
|
|
|
West Texas Intermediate (US$/bbl) |
75.09 |
82.26 |
(9) |
77.54 |
77.39 |
0 |
Western Canadian Select (WCS) (C$/bbl) |
83.95 |
93.09 |
(10) |
84.45 |
80.38 |
5 |
WCS differential (US$/bbl) |
13.55 |
12.88 |
5 |
15.49 |
17.63 |
(12) |
Edmonton Par (Cdn$/bbl) |
97.85 |
107.90 |
(9) |
98.43 |
100.63 |
(2) |
Edmonton Par differential (US$/bbl) |
3.35 |
1.85 |
81 |
5.21 |
2.61 |
100 |
Foreign Exchange (USD to CAD) |
1.36 |
1.34 |
1 |
1.36 |
1.35 |
1 |
Operating netback ($/Boe) |
|
|
|
|
|
|
Realized sales price, net of blending(3) |
73.62 |
80.22 |
(8) |
74.05 |
69.29 |
7 |
Royalty expenses |
(15.74) |
(13.38) |
18 |
(14.65) |
(12.70) |
15 |
Net production expenses(3) |
(8.62) |
(8.47) |
2 |
(9.12) |
(9.72) |
(6) |
Transportation expenses |
(2.36) |
(4.13) |
(43) |
(3.47) |
(4.00) |
(13) |
|
(0.08) |
- |
nm |
(0.40) |
- |
nm |
Operating field netback ($/Boe)(3) |
46.82 |
54.24 |
(14) |
46.41 |
42.87 |
8 |
Realized commodity hedging gain (loss) |
0.03 |
(2.52) |
(101) |
(0.09) |
(1.89) |
(95) |
Operating netback ($/Boe)(3) |
$ 46.85 |
$ 51.72 |
(9) |
$ 46.32 |
$ 40.98 |
13 |
Adjusted funds flow ($/Boe)(3) |
$ 36.85 |
$ 40.44 |
(9) |
$ 35.93 |
$ 30.80 |
17 |
2024 Production Guidance Update
In response to the continued strong well performance and benefits from infrastructure optimization during the year, the Company has increased the full-year production guidance range to 63,000 to 64,000 boe/d(6).
The 2024 capital program, which is delivering higher production than originally budgeted, is forecasted to be achieved at a lower cost, benefitting from drilling and facilities efficiencies. Utilizing a portion of the CIP expansion proceeds, Tamarack will drill 4 (4.0 net)
Tamarack is also updating its 2024 corporate costs guidance on the back of a continued focus on reducing costs and enhancing margins. Transportation cost guidance is reduced in response to improved oil transportation contracts and lower trucking costs. Guidance regarding carbon tax is updated to reflect savings related to anticipated taxable emissions reductions in 2024, resulting from ongoing
2024 Guidance Summary(8)
|
Units |
Prior
( Guidance |
Guidance Change |
Updated
( Guidance |
2024 Capital Budget(7) |
$MM |
$390– |
- |
|
Annual Average Production(6,9) |
boe/d |
61,000 – 63,000 |
+2,000 & +1,000 |
63,000 – 64,000 |
Average Oil & NGL Weighting |
% |
84% – 86% |
- |
84% – 86% |
|
|
|
|
|
Expenses: |
|
|
|
|
Royalty Rate (%) |
% |
20% – 22% |
- |
20% – 22% |
Wellhead price differential – Oil(10) |
$/boe |
|
- |
|
Net Production |
$/boe |
|
- |
|
Transportation |
$/boe |
|
( |
|
Carbon Tax(11) |
$/boe |
|
( |
|
General and Administrative (12) |
$/boe |
|
- |
|
Interest |
$/boe |
|
( |
|
Income Taxes(13) |
% |
9% - 11% |
2% & 2% |
11% - 13% |
Returns to Shareholders
The Company will raise its monthly dividend to
2024 Operations Update
Total
At West Marten, the Company continues to see positive results from the C sand delineation program with an IP30 rate of ~200 bbl/d observed at 02/13-30-076-04W5/0. Stacked sand development continues in the area, where the Company rig released six B sand and two C sand wells in Q3/24 from its 14-23-076-05/W5 pad. Initial productivity is strong, and the Company plans to pursue waterflood in both sands.
The continued refinement of drilling designs, coupled with program optimizations, are driving efficiency enhancements and lower overall capital costs throughout the
The application of fan well designs in the
Waterflood – Production Response to Increased Injection at Nipisi and
Year-to-date the company has drilled seven total injectors in Nipisi. Based on the strong results from waterflood in the area, the Company plans to drill five additional injectors from the 12-14-076-08/W5 pad in Q4/24. Tamarack's first C sand injector at West Marten commenced water injection in
At
At Canal, Tamarack implemented a pilot waterflood at the 100/16-16-70-23W4/0 well which has demonstrated strong initial injectivity greater than 800 bbl/d.
During the quarter, Tamarack achieved production of 16,200 boe/d(15) from its
Late in Q3/24, Tamarack brought two wells online in the
Risk Management
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 reminder of 2024 and the first half of 2025, approximately ~50% of net after royalty oil production is hedged against WTI with an average floor price of
Quarterly Investor Call
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Tamarack will host a webcast at |
About
Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow(3) generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on
Abbreviations
AECO |
the natural gas storage facility located at Suffield, |
ARO |
asset retirement obligation; may also be referred to as decommissioning obligation |
bbls |
barrels |
bbls/d |
barrels per day |
boe |
barrels of oil equivalent |
boe/d |
barrels of oil equivalent per day |
bopd |
barrels of oil per day |
EOR |
enhanced oil recovery |
GJ |
gigajoule |
IFRS |
International Financial Reporting Standards as issued by the |
IP30 |
average peak production rate for the 30 days after the well is brought onstream |
Mcf |
thousand cubic feet |
mcf/d |
thousand cubic feet per day |
MM |
Million |
MMcf/d |
million cubic feet per day |
MSW |
Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil in |
NGL |
Natural gas liquids |
WTI |
West Texas Intermediate, the reference price paid in |
YoY |
Year-over-year |
YTD |
Year-to-date |
Reader Advisories
Notes to Press Release
1) |
Production of 65,024 boe/d: 39,047 bbl/day heavy oil, 13,203 bbl/d light and medium oil, 2,915 bbl/d NGL and 59,154 mcf/d natural gas. |
2) |
Q3 2023 Clearwater production of 37,600 boe/d is comprised of approximately 35,700 bbl/d heavy oil, 186 bbl/d NGL and 10,375 mcf/d natural gas. |
3) |
See "Specified Financial Measures". |
4) |
Return per share calculated based on the weighted average basic shares outstanding for the relevant periods. |
5) |
Q1/24-Q3/24 dividends of |
6) |
Production of 63,000 – 64,000 boe/d: 37,900-38,600 bbl/d heavy oil, 13,600-13,750 bbl/d light and medium oil, 2,300-2,400 bbl/d NGL and 55,000-55,500 mcf/d natural gas. |
7) |
Capital budget includes exploration and development capital, ESG initiatives, facilities land and seismic but excludes ARO, capital associated with the CIP and asset acquisitions and dispositions. |
8) |
Annual guidance numbers are based on 2024 average pricing assumptions of: |
2024 Budget Pricing |
|
Crude Oil – WTI ($US/bbl) |
|
Crude Oil – MSW Differential ($US/bbl) |
( |
Crude Oil – WCS Differential ($US/bbl) |
( |
Natural Gas – AECO ($CAD/GJ) |
|
Foreign Exchange – CAD/USD |
1.3450 |
9) |
Production of 61,000 – 63,000 boe/d: 12,800-13,200 bbl/d light and medium oil, 36,600-37,800 bbl/d heavy oil, 2,400-2,500 bbl/d NGL and 54,900-56,700 mcf/d natural gas. |
10) |
Wellhead price differential for oil shown in the guidance table. |
11) |
The Company's acquisitions in 2022 and a more stringent emissions regulatory framework increased taxable emissions in 2023 and 2024. |
12) |
G&A noted excludes the effect of cash settled stock-based compensation. |
13) |
Tamarack estimates a tax rate as a percentage of funds flow |
14) |
Production of 43,300 boe/d: 39,100 bbl/d heavy oil, 300 bbl/d light and medium oil, 360 bbl/d NGL and 21,500 mcf/d natural gas. |
15) |
Production of 16,200 boe/d: 8,300 bbl/d light and medium oil, 2,500 bbl/d NGL and 32,400 mcf/d natural gas |
16) |
Production of 1,320 boe/d: 1,030 bbl/d light and medium oil, 108 bbl/d NGL and 1,090 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.
Product Types. 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.
Short-Term Production Rates. References in this press release to peak rates, initial production rates, IP30 and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Tamarack. The Company cautions that such results should be considered to be preliminary.
Forward Looking Information
This press release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; the Company's exploration and development plans and strategies; improved efficiencies and margin enhancements; future intentions with respect to debt repayment and reduction and the Company's ROC framework, including share buybacks and an increased monthly dividend; oil and natural gas production levels, adjusted funds flow and free funds flow; anticipated operational results for 2024 including, but not limited to, estimated or anticipated production levels (including in respect of Tamarack's updated 2024 production guidance, which is increased to the 63,000 to 64,000 boe/d range), capital expenditures, drilling plans and infrastructure initiatives (including use of proceeds from the CIP expansion), the Company's capital program, guidance and budget for 2024 and the funding thereof; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; decline rates and EOR, including waterflood initiatives; the continued successful integration of acquired assets; the ability of the Company to achieve drilling success consistent with management's expectations, including leveraging the "Fan" well design; ARO reduction; and risk management activities, including hedging positions and targets. 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 continued successful integration of 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 with respect to unplanned third party pipeline outages and risks relating to inclement and severe weather events and natural disasters, such as fire, drought and flooding, including in respect of safety, asset integrity and shutting-in production, delivering on 2024 guidance; the risk that future 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, including the impact of the actions of
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 (including annual average production, average oil & NGL weighting), oil weightings, hedging, operating costs, 2024 capital budget, guidance and expenditures, decline rates, 2024 carbon tax, balance sheet strength, 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.
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, changes in non-cash working capital, expenditures on decommissioning obligations and transaction costs settled during the applicable period. 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.
"Differential including transportation expense" The calculation of the Company's heavy oil differential including transportation expenses is presented in the "Petroleum and natural gas sales" section of the Company's Q1 2024 MD&A and is determined by comparing the Company's realized price to the published benchmark price, plus transportation expenses. The Company and others utilize these performance measures to assess the value of net revenue received by Tamarack for each barrel sold relative to the published market price during that period. These performance measures are presented on a per boe basis as a non-GAAP financial ratio.
"Free funds flow (capital management measure)" 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 (capital management measure)" (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 (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.
"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 income. 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 in the MD&A. Blending expense includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications. The blending expense represents the difference between the cost of purchasing and transporting the diluent and the realized price of the blended product sold. In the MD&A, blending expense is recognized as a reduction to heavy oil revenues, whereas blending expense is reported as an expense in the financial statements. 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.
Please refer to the MD&A for additional information relating to specified financial measures including non-IFRS financial measures, non-IFRS financial ratios and capital management measures. The MD&A can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca.
SOURCE