TSX: TVE
Q2 2023 Financial and Operating Highlights
- Commissioned a newly constructed, owned and operated Wembley gas plant
June 9 , delivering the project on budget and ahead of schedule with production ramping to the nameplate 15 MMcf/d of initial capacity; - Achieved quarterly volumes of 66,738 boe/d(2), representing a 52% year-over-year increase (or 21% on a per share basis). A successful second quarter development program was partially offset by the Company's loss of ~1,500 boe/d(3) of production owing to the direct and indirect impacts of the
Alberta wildfires situation and unplanned third-party outages. Production impacts were largely restored prior toJune 30 , with second half production levels forecasted to average between 68,000-70,000 boe/d(5); - Despite the wildfire impacts, full year production guidance maintained at 67,000 to 71,000 boe/d(5) on the strength of better than anticipated drilling results in the
Clearwater andCharlie Lake programs; - Invested
$117.8 million during the quarter, including drilling, completion and equipping of 19 (19.0 net)Clearwater wells and five (5.0 net)Charlie Lake wells. The enhanced scale and scope of ourClearwater operations has led to greater capital efficiencies offsetting the increase in unit cost inflation that occurred through 2022 and delivering costs not seen since the first quarter of 2022; - Allocated
$20 million in Q2/23 to strategic infrastructure, including costs associated with the Wembley plant and the Nipisi pipeline terminal. Both projects will drive lower operating and transportation costs enhancing free funds flow(1) in the second half of 2023 forward; - Generated Q2/23 adjusted funds flow(1) of
$157.3 million and free funds flow(1) of$39.4 million reflecting production impacts from the wildfires and third-party outages, along with lower year-over-year commodity prices and a wider WCS differential; - Looking ahead the strengthening of WCS differentials coupled with the completion of our infrastructure initiatives will contribute to a stronger forecasted netback through the back half of the year and five-year plan;
- Published the 2023 annual sustainability report highlighting Tamarack's commitment to environmental, social and governance (ESG) principles and sustainable practices during 2022; and
- Subsequent to the quarter, entered into a definitive agreement for the sale of a minority interest in the Wembley gas plant and a gross overriding royalty (GORR) on select
Clearwater andCharlie Lake properties for total consideration of$39.5 million . Following closing of the sale, Tamarack will continue to be the operator of theWembley gas plant and will retain full access to 100% of the capacity.
Financial & Operating Results
Three months ended | Six months ended | ||||||
2023 | 2022 | % | 2023 | 2022 | % | ||
($ thousands, except per share) | |||||||
Total oil, natural gas and processing revenue | 398,319 | 407,195 | (2) | 777,774 | 706,090 | 10 | |
Cash flow from operating activities | 156,265 | 214,708 | (27) | 215,889 | 347,561 | (38) | |
Per share – basic | (43) | (52) | |||||
Per share – diluted | (43) | (52) | |||||
Adjusted funds flow (1) | 157,253 | 203,622 | (23) | 314,524 | 352,481 | (11) | |
Per share – basic (1) | (40) | (31) | |||||
Per share – diluted (1) | (39) | (32) | |||||
Net income | 25,735 | 143,507 | (82) | 28,240 | 169,964 | (83) | |
Per share – basic | (85) | (88) | |||||
Per share – diluted | (85) | (87) | |||||
Net debt (1) | (1,373,620) | (470,563) | 192 | (1,373,620) | (470,563) | 192 | |
Capital expenditures (4) | 117,831 | 109,483 | 8 | 265,993 | 234,850 | 13 | |
Weighted average shares outstanding | |||||||
Basic | 556,461 | 434,924 | 28 | 556,504 | 427,175 | 30 | |
Diluted | 560,016 | 438,206 | 28 | 560,437 | 430,406 | 30 | |
Share Trading | |||||||
High | (34) | (25) | |||||
Low | (27) | (23) | |||||
Average daily share trading volume (thousands) | 2,332 | 4,155 | (44) | 2,694 | 3,963 | (32) | |
Average daily production | |||||||
Light oil (bbls/d) | 16,382 | 18,233 | (10) | 16,706 | 18,052 | (7) | |
Heavy oil (bbls/d) | 35,373 | 10,805 | 227 | 34,889 | 9,172 | 280 | |
NGL (bbls/d) | 3,645 | 3,540 | 3 | 3,882 | 3,825 | 1 | |
Natural gas (mcf/d) | 68,027 | 67,195 | 1 | 71,143 | 69,082 | 3 | |
Total (boe/d) | 66,738 | 43,777 | 52 | 67,334 | 42,563 | 58 | |
Average sale prices | |||||||
Light oil ($/bbl) | 91.74 | 135.66 | (32) | 93.38 | 123.07 | (24) | |
Heavy oil, net of blending expense(1) ($/bbl) | 73.02 | 115.51 | (37) | 67.42 | 106.91 | (37) | |
NGL ($/bbl) | 36.64 | 63.61 | (42) | 41.53 | 59.65 | (30) | |
Natural gas ($/mcf) | 2.39 | 7.81 | (69) | 2.97 | 6.73 | (56) | |
Total ($/boe) | 65.66 | 102.16 | (36) | 63.63 | 91.54 | (30) | |
Operating netback ($/Boe) | |||||||
Average realized sales, net of blending expense (1) | 65.66 | 102.16 | (36) | 63.63 | 91.54 | (30) | |
Royalty expenses | (12.70) | (19.64) | (35) | (12.34) | (17.75) | (30) | |
Net production and transportation expenses (1) | (14.23) | (13.00) | 9 | (14.31) | (12.55) | 14 | |
Operating field netback ($/Boe) (1) | 38.73 | 69.52 | (44) | 36.98 | 61.24 | (40) | |
Realized commodity hedging loss | (2.05) | (9.40) | (78) | (1.56) | (6.79) | (77) | |
Operating netback ($/Boe) (1) | 36.68 | 60.12 | (39) | 35.42 | 54.45 | (35) | |
Adjusted funds flow ($/Boe) (1) | 25.89 | 51.11 | (49) | 25.81 | 45.75 | (44) |
2023 Outlook & Guidance Update
The Company's capital budget range remains unchanged at
Tamarack is maintaining prior 2023 production guidance of 67,000 to 71,000 boe/d(5) which was outlined in
Unchanged Current | ||
as presented | ||
Capital Budget ($MM)(4) | ||
Annual Average Production (boe/d)(5) | 67,000 – 71,000 | |
Average Oil & NGL Weighting | 81% – 83% | |
Expenses: | ||
Royalty Rate (%) | 19% – 21% | |
Operating ($/boe) | ||
Transportation ($/boe) | ||
General and Administrative ($/boe)(6) | ||
Interest ($/boe) | ||
Taxes ($/boe)(7) | ||
Leasing Expenditures ($MM) |
Operations Update
Infrastructure
Tamarack completed the construction and commissioning of its owned and operated 15 MMcf/d
As development continues to expand across Tamarack's
The Nipisi terminal and pipeline project continues to track on time, affording enhanced netback realizations through blending cost benefits and reduced transportation expense. In addition, Tamarack is working with third parties to establish a new Clearwater Heavy Oil benchmark which could provide for improved pricing over time.
Tamarack has significantly expanded its
Strong well results at
Expansion of the Nipisi waterflood program is ongoing following the successful 102/13-19-076-08W5 pilot which continues to produce at ~390 bopd with cumulative production of over 190,000 barrels of oil to date. Water injection rates at Nipisi averaged ~2,100 bbl/d in June and completion of the centralized water facility at the 15-22-076-07W5 battery in Q4/23 will support the ongoing ramp of total injection exiting the year.
At
Activity in the
Tamarack drilled five (5.0 net) wells ahead of the
Return of Capital
The Company remains committed to balancing long-term sustainable free funds flow(1) growth with returning capital to shareholders. The base dividend is currently
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 remainder of 2023, approximately 56% of net after royalty oil production is hedged against WTI with an average floor price of greater than
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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 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 |
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 |
GJ | gigajoule |
IFRS | International Financial Reporting Standards as issued by the International |
IP30 | average production for the first 30 days that a well is 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 |
NGL | Natural gas liquids |
WCS | Western Canadian select, the benchmark for conventional and oil sands |
WTI | West Texas Intermediate, the reference price paid in |
Reader Advisories
Notes to Press Release
(1) | See "Specified Financial Measures" |
(2) | Q2 2023 production of 66,738 boe/d comprised of 16,382 bbl/d light and medium oil, 35,373 bbl/d heavy oil, 3,645 bbl/d NGL and 68,027 mcf/d natural gas. |
(3) | Production impacts of approximately 1,500 boe/d comprised of 548 bbl/d light and medium oil, 473 bbl/d heavy oil, 86 bbl/d NGL and 2,349 mcf/d natural gas. |
(4) | 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. |
(5) | Target production is comprised of 17,000-17,500 bbl/d light and medium oil, 34,700-36,500 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 71,000-75,000 mcf/d natural gas. |
(6) | G&A noted excludes the effect of cash settled stock-based compensation. |
(7) | Tax numbers in the annual guidance numbers are based on 2023 average pricing assumptions of: |
(8) | Q2 2023 Clearwater production of 37,800 boe/d is comprised of approximately 35,930 bbl/d heavy oil, 120 bbl/d NGL and 10,479 mcf/d natural gas. |
(9) | Q2 2023 |
(10) | |
(11) | |
(12) | |
(13) |
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; the completion of the sale of the minority interest in the
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 satisfaction of all conditions to the completion of the sale of the minority interest in the gas plant and the GORR; 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 (including expectations concerning narrowing WCS differentials); 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 inclement and severe weather events and natural disasters, including fire, drought and flooding, 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
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, material debt reduction, total returns, the GORR 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 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 Measures)" 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.
"Free Funds Flow and Capital Expenditures (Capital Management Measures)" is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Capital expenditures 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 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 this 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.
"Net Debt (Capital Management Measures)" 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.
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