Tamarack Valley Energy Announces Third Quarter 2023 Financial Results and Provides Operational Update
TSX: TVE
CALGARY, AB, Oct. 26, 2023 /CNW/ - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") is pleased to announce its financial and operating results for the three and nine months ended September 30, 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 and nine months ended September 30, 2023, which will be available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca.
Q3 2023 Financial and Operating Highlights
- Record Corporate Production - Delivered on average 68,597 boe/d(2) during the third quarter resulting in the highest quarterly production in Tamarack's history. This represents a 58% year over year increase and 16% uplift to debt adjusted per share production on a quarter over quarter basis;
- Reduced Production Expense - Net production expense(1) improved by 17% year-over-year to $8.47/boe reflecting the impact of the Company's Wembley gas plant in the Charlie Lake light oil play, additional infrastructure development in the Clearwater area and higher production during the quarter;
- Focused Capital Deployment - Capital expenditures(1) of $122.8 million in the quarter included $85.7 million of development capital and $37.1 million of facility capital. Third quarter activity included 41 (40.3 net) Clearwater heavy oil wells and 1 (1.0 net) Charlie Lake light oil well. Year to date the Company has drilled, completed and equipped 93 (91.6 net) Clearwater heavy oil wells and 14 (13.8 net) Charlie Lake light oil wells;
- Quarterly Adjusted Funds Flow(1) - Record production and strong Canadian oil prices generated adjusted funds flow(1) of $255.2 million in Q3/23, which was 44% higher than the same quarter in 2022;
- Free Funds Flow(1) Generation - Free funds flow(1) of $132.4 million was $53 million, or 40%, higher on a year over year basis. Year to date, the Company has generated $181.0 million of free funds flow(1);
- Debt Reduction – Net debt(1) decreased to $1,128.0 million at September 30, 2023, reflecting the benefit of free funds flow(1), non-core dispositions and assets held for sale at the end of the quarter.
Brian Schmidt (Aakaikkitstaki), Tamarack's President and CEO commented: "Tamarack's third quarter results reflect the successful execution of ongoing drilling and field activity across our portfolio of core development prospects. We remain focused on disciplined capital deployment and strategic dispositions as net debt continues to be reduced and our asset base is high graded. Benefitting from infrastructure investment through the first half of 2023, the Company has increased our ownership and control of strategic facilities in our key plays resulting in enhanced market access and driving our cost structure lower. Tamarack provides investors with differentiated and focused exposure to two of North America's most economic plays. Exiting 2023, we expect 88% of our production to be derived from our remaining core holdings in the Clearwater and Charlie Lake plays."
Financial & Operating Results
Three months ended |
Nine months ended |
|||||
September 30, |
September 30, |
|||||
2023 |
2022 |
% |
2023 |
2022 |
% |
|
($ thousands, except per share) |
||||||
Total oil, natural gas revenue |
506,365 |
327,910 |
54 |
1,284,066 |
1,033,135 |
24 |
Cash flow from operating activities |
199,756 |
229,927 |
(13) |
415,645 |
577,488 |
(28) |
Per share – basic |
$ 0.36 |
$ 0.52 |
(31) |
$ 0.75 |
$ 1.34 |
(44) |
Per share – diluted |
$ 0.36 |
$ 0.52 |
(31) |
$ 0.74 |
$ 1.33 |
(44) |
Adjusted funds flow (1) |
255,199 |
177,834 |
44 |
569,723 |
530,315 |
7 |
Per share – basic (1) |
$ 0.46 |
$ 0.40 |
15 |
$ 1.02 |
$ 1.23 |
(17) |
Per share – diluted (1) |
$ 0.46 |
$ 0.40 |
15 |
$ 1.02 |
$ 1.22 |
(16) |
Net income |
8,634 |
124,793 |
(93) |
36,874 |
294,757 |
(87) |
Per share – basic |
$ 0.02 |
$ 0.28 |
(93) |
$ 0.07 |
$ 0.68 |
(90) |
Per share – diluted |
$ 0.02 |
$ 0.28 |
(93) |
$ 0.07 |
$ 0.68 |
(90) |
Net debt (1) |
(1,128,030) |
(286,762) |
293 |
(1,128,030) |
(286,762) |
293 |
Capital expenditures (1) |
122,759 |
98,451 |
25 |
388,752 |
333,301 |
17 |
Weighted average shares outstanding (thousands) |
||||||
Basic |
556,708 |
440,388 |
26 |
556,399 |
431,672 |
29 |
Diluted |
558,569 |
443,351 |
26 |
559,958 |
435,053 |
29 |
Share Trading |
||||||
High |
$ 4.12 |
$ 4.62 |
(11) |
$ 4.88 |
$ 6.48 |
(25) |
Low |
$ 3.19 |
$ 3.28 |
(3) |
$ 2.99 |
$ 3.28 |
(9) |
Average daily share trading volume (thousands) |
1,975 |
3,745 |
(47) |
2,457 |
3,890 |
(37) |
Average daily production |
||||||
Light oil (bbls/d) |
16,974 |
16,229 |
5 |
16,797 |
17,437 |
(4) |
Heavy oil (bbls/d) |
35,900 |
13,183 |
172 |
35,229 |
10,524 |
235 |
NGL (bbls/d) |
3,623 |
3,659 |
(1) |
3,795 |
3,769 |
1 |
Natural gas (mcf/d) |
72,597 |
62,428 |
16 |
71,633 |
66,839 |
7 |
Total (boe/d) |
68,597 |
43,476 |
58 |
67,760 |
42,870 |
58 |
Average sale prices |
||||||
Light oil ($/bbl) |
107.83 |
111.80 |
(4) |
98.30 |
119.53 |
(18) |
Heavy oil, net of blending expense(1) ($/bbl) |
92.85 |
89.30 |
4 |
76.15 |
99.48 |
(23) |
NGL ($/bbl) |
41.46 |
49.18 |
(16) |
41.51 |
56.23 |
(26) |
Natural gas ($/mcf) |
2.60 |
6.27 |
(59) |
2.84 |
6.59 |
(57) |
Total ($/boe) |
80.22 |
81.98 |
(2) |
69.29 |
88.28 |
(22) |
Operating netback ($/Boe) |
||||||
Average realized sales, net of blending expense (1) |
80.22 |
81.98 |
(2) |
69.29 |
88.28 |
(22) |
Royalty expenses |
(13.38) |
(14.06) |
(5) |
(12.70) |
(16.49) |
(23) |
Net production expenses (1) |
(8.47) |
(10.24) |
(17) |
(9.72) |
(10.25) |
(5) |
Transportation expenses |
(4.13) |
(2.88) |
43 |
(4.00) |
(2.49) |
61 |
Operating field netback ($/Boe) (1) |
54.24 |
54.80 |
(1) |
42.87 |
59.05 |
(27) |
Realized commodity hedging loss |
(2.52) |
(2.90) |
(13) |
(1.89) |
(5.46) |
(65) |
Operating netback ($/Boe) (1) |
51.72 |
51.90 |
– |
40.98 |
53.59 |
(24) |
Adjusted funds flow ($/Boe) (1) |
40.44 |
44.46 |
(9) |
30.80 |
45.31 |
(32) |
2023 Outlook & Guidance Update
The Company's exploration and development capital guidance range remains unchanged at $425 million to $475 million(3). Tamarack continues to focus on maximizing free funds flow(1) for debt repayment and enhancing shareholder returns as debt thresholds are met. Fourth quarter 2023 free funds flow(1) is expected to reflect increased oil weighting driving improved netback(1) realizations through our infrastructure initiatives.
Tamarack has updated its 2023 production guidance to reflect the west central non-core Cardium asset disposition previously announced on October 19, 2023 (the "Disposition). Updated full year 2023 production is expected to be in the range of 65,500 to 69,500 boe/d(4) with fourth quarter volumes of 65,000 to 66,000 boe/d(5). Production guidance reflects the strong performance of our Clearwater and Charlie Lake drilling programs and impact of the Disposition of ~4,500 boe/d(6) for the fourth quarter. Tamarack expects to provide the 2024 budget and guidance on December 6, 2023.
Prior Guidance 2023 |
Current Guidance 2023 |
||||
as presented May 10, 2023 |
|||||
Capital Budget ($MM)(3) |
$425 – $475 |
$425 – $475 |
|||
Annual Average Production (boe/d)(4) |
67,000 – 71,000 |
65,500 – 69,500 |
|||
Average Oil & NGL Weighting |
81% – 83% |
82% – 84% |
|||
Expenses: |
|||||
Royalty Rate (%) |
19% – 21% |
19% – 21% |
|||
Operating ($/boe) |
$9.00 – $9.50 |
$9.00 – $9.50 |
|||
Transportation ($/boe) |
$3.50 – $4.00 |
$3.50 – $4.00 |
|||
General and Administrative ($/boe)(7) |
$1.25 – $1.35 |
$1.25 – $1.35 |
|||
Interest ($/boe) |
$3.80 – $4.00 |
$3.80 – $4.00 |
|||
Taxes ($/boe)(8) |
$3.75 – $4.10 |
$3.75 – $4.50 |
|||
Leasing Expenditures ($MM) |
$3.5 – $4.5 |
$3.5 – $4.5 |
|||
Operations Update
Infrastructure
Tamarack's owned and operated Wembley gas plant continues to provide consistent and reliable processing capacity within the Company's operational control. Since commissioning in mid-June, approximately 40% of the Company's Charlie Lake production is processed through the facility and Tamarack has materially reduced its exposure to third party downtime at Wembley to approximately 1.2% (June 2023 to October 2023). This compares to average third-party downtime of approximately 12.0% from January 2022 to May 2023 resulting from infrastructure outages where Tamarack was delivering Wembley Charlie Lake volumes to non-operated facilities.
At West Marten Hills, Tamarack is expanding capacity at its Marten Creek plant to increase gas conservation and reduce emissions intensity as our Clearwater development moves forward. This facility offers the potential to become a regional conservation hub and is expected to initially conserve 6 MMcf/d of natural gas commencing in Q1/24. Expansion of this facility is underway and is expected to support long term regional Clearwater development.
Tamarack continues to advance strategic initiatives to enhance pricing and reduce costs, including the Nipisi terminal and pipeline project which has been commissioned, with linefill delivered in October. On the heels of this start up, Tamarack was able to secure the sale of initial batches of its Clearwater Heavy Oil barrels in October, for November delivery, which attracted premium pricing relative to the CHV (Conventional Heavy Oil) benchmark.
Clearwater
Clearwater production averaged 37,600 boe/d(9) in the third quarter, representing 55% of corporate production. During the quarter, the Company drilled and brought onstream 41 (40.3 net) Clearwater wells. Tamarack currently has five rigs running on its Clearwater assets (three at West Marten Hills, one at Nipisi and one at Marten Hills).
West Marten Hills continues to see strong well results as Tamarack recently brought 13 new B sand wells onstream, which included eight wells at the 02-22-76-5W5 pad (with average IP30 oil rates exceeding 250 bopd per well) and five wells at the 12-22-76-5W5 pad (with average IP30 oil rates of approximately 225 bopd per well). Demonstrating the stacked potential in this area, the Company has brought two new C sand wells onstream from the 2-22 and 12-22 pads with per well average IP30 of 245 bopd and 314 bopd respectively. Tamarack plans to waterflood the B and C sands from these pads, leveraging interconnected infrastructure to improve the economics for both zones.
Primary development at Marten Hills focused on multi-well pads with longer lateral lengths to drive improved capital efficiencies through reduced drilling and infrastructure costs. During the quarter, Tamarack drilled its first 11 leg, three bench wells, resulting in a 15% reduction in drilling cost per meter compared to its conventional drilling design. These wells are currently cleaning up and an update will be provided with the budget in December.
Expansion of the West Nipisi and Marten Hills waterflood program is ongoing with Tamarack currently injecting ~2,000 bbl/d of water at West Nipisi and observing early signs of response from multiple waterflood patterns implemented in 2023. The Company plans to drill four additional injectors by 2023 year-end to ramp water injection rates to 4,000 bbl/d.
At Marten Hills, Tamarack increased water injection at 15-02-075-25W4 beginning in April 2023 and observed a material subsequent oil response at this location of ~150 bopd higher than pre-ramp rates. This well has now produced over 420 mbbls of oil on a cumulative basis, representing the highest recovery of any Clearwater multi-lateral drilled in the history of the play. Building on these successful results, Tamarack plans to convert the offsetting wells to waterflood in Q4/23. In May 2023, Tamarack converted its first "W" waterflood pattern to injection at 01-11-074-24W5, observing recent water injectivity rates over 1,100 bbl/d. Given the strong positive correlation between injectivity and oil response across the Clearwater fairway, the Company sees this as a very promising result as the program continues to advance.
In the South Clearwater fairway, the Company has drilled four wells year-to-date utilizing the fan well design. Two of the four wells have been producing for over 30 days and the average IP30 is 244 bopd per well. The fan design drives efficiency through:
- Reduced surface locations and infrastructure requirements, minimizing the operational footprint and lowering lease construction costs;
- Improved drilling design with increased efficiency by reducing turns and required sliding, resulting in lower drilling costs on a $/metre basis; and
- Improved recovery efficiency with a 25% reduction in wells required to access the same reserves achieved by previous conventional design across a four-section land block of land.
Charlie Lake
With the new Wembley gas plant onstream, Tamarack's Charlie Lake assets achieved a new record production rate of 16,200 boe/d(10) during the third quarter. The Company was able to leverage wells drilled in the first half of 2023 to ramp up plant capacity exiting Q2/23, requiring the drilling of only one well in Q3/23 while still achieving record quarterly production. Reflecting continued field development success, the five wells drilled ahead of commissioning in the Wembley area achieved IP90 rates that averaged 900 boe/d(11) per well. The strongest of these was the 00/12-36-073-08W6/00 well which delivered an IP90 rate of 1,185 boe/d(12). With two rigs currently active, drilling for the fourth quarter includes a modest four (3.5 net) well program and is expected to sustain production in the 16,000 – 17,000 boe/d(13) range exiting the year.
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 $0.15/share annually which represents a 3.8% 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 on a quarterly basis. Tamarack expects to reach the first enhanced return threshold of the return of capital framework during the fourth quarter of 2023, reflecting the positive impact of recent dispositions, strong production and improved commodity prices. Given current valuations the Company views share buybacks as the preferred mechanism to enhance overall shareholder returns at this time.
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 risk management program. For the remainder of 2023, approximately 54% of net after royalty oil production is hedged against WTI with an average floor price of greater than US$67.50/bbl. For Q1/24, approximately 53% of net after royalty oil production is hedged against WTI with an average floor price of greater than US$68.40/bbl. Our strategy focuses on downside protection while maintaining upside opportunity. 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 MD&A for the three and nine months ended September 30, 2023, which will be available on SEDAR+ (www.sedarplus.ca).
Investor Call Information October 26, 2023 9:30 AM MDT (11:30 AM EDT)
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Tamarack will host a webcast at 9:30 AM MDT (11:30 AM EDT) on Thursday, October 26, 2023 to discuss the |
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 and Clearwater plays in Alberta while also pursuing EOR upside in these core areas. 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.
Abbreviations
AECO |
the natural gas storage facility located at Suffield, Alberta connected to TC |
ARO |
asset retirement obligation; may also be referred to as decommissioning |
bbls |
barrels |
bbl/d |
barrel per day |
boe |
barrel of oil equivalent |
boe/d |
barrel of oil equivalent per day |
bopd |
barrel 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 |
IP90 |
average production for the first 90 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 U.S. dollars at Cushing, |
Reader Advisories
Notes to Press Release |
|
1) |
See "Specified Financial Measures" |
2) |
Q3 2023 production of 68,597 boe/d comprised of 16,974 bbl/d light and medium oil, 35,900 bbl/d heavy oil, 3,623 bbl/d NGL and 72,597 mcf/d natural gas. |
3) |
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. |
4) |
Prior guidance Annual Average 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. Current guidance Annual Average Production 16,400-16,900 bbl/d light and medium oil, 34,700-36,500 bbl/d heavy oil, 3,230-4,260 bbl/d NGL and 67,000-71,000 mcf/d natural gas. |
5) |
Fourth quarter estimated volumes comprised of 14,000-14,300 bbl/d light and medium oil, 38,000-38,900 bbl/d heavy oil, 3,000-3,200 bbl/d NGL and 57,000-57,600 mcf/d natural gas. |
6) |
Production impacts of approximately 4,500 boe/d comprised of 1,098 bbl/d light and medium oil, 922 bbl/d NGL and 14,880 mcf/d natural gas. |
7) |
G&A noted excludes the effect of cash settled stock-based compensation. |
8) |
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. |
9) |
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. |
10) |
Q3 2023 Charlie Lake production of 16,200 boe/d is comprised of approximately 9,270 bbl/d light and medium oil, 1,970 bbl/d NGL and 30,000 mcf/d natural gas. |
11) |
Average of five recent Charlie Lake wells of 900 boe/d is comprised of approximately 713 bbl/d light and medium oil, 129 bbl/d NGL and 2,075 mcf/d natural gas. |
12) |
12-36-073-08W6 well IP90 rate of 1,185 boe/d comprised of 710 bbl/d light and medium oil, 130 bbl/d NGL and 2,075 mcf/d natural gas. |
13) |
Charlie Lake rates of 16,000 – 17,000 boe/d for the balance of 2023 comprised of approximately 9,735 bbl/d light and medium oil, 2,145 bbl/d NGL and 27,720 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; the completion of the Disposition; the anticipated benefits of the Disposition; future consolidation and disposition activity, organic growth and development and portfolio rationalization; future intentions with respect to debt repayment and reduction 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 the remainder of 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, including the Wembley gas plant and gas conservation investments; the Company's capital program, guidance and budget for 2023 and flexibility with respect thereto; the timing of 2024 guidance; 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 recently acquired assets; the ability of the Company to achieve drilling success consistent with management's expectations; risk management activities, including the Company's hedging management program; 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 satisfaction of all conditions to the completion of the Disposition; the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack's properties; the characteristics of recently acquired assets; the 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 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, 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,; 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; pandemics; Russia's military actions in Ukraine; and the Israel-Palestinian conflict. 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 September 30, 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.sedarplus.ca.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, material debt reduction (including achieving the first net debt threshold of its enhanced return of capital framework), total returns and components thereof, including pro forma the completion of the Disposition, 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, initial production 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 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.
SOURCE Tamarack Valley Energy Ltd.
Brian Schmidt, President & Chief Executive Officer, Tamarack Valley Energy Ltd., Phone: 403.263.4440, www.tamarackvalley.ca; Steve Buytels, Chief Financial Officer, Tamarack Valley Energy Ltd., Phone: 403.263.4440, www.tamarackvalley.ca
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