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 $1,128.0 million at September 30, 2023, reflecting the benefit of free funds flow(1), non-core dispositions and assets held for sale at the end of the quarter.
Brian Schmidt (Aakaikkitstaki), Tamarack’s President and CEO commented: “Tamarack’s third quarter results reflect the successful execution of ongoing drilling and field activity across our portfolio of core development prospects. We remain focused on disciplined capital deployment and strategic dispositions as net debt continues to be reduced and our asset base is high graded. Benefitting from infrastructure investment through the first half of 2023, the Company has increased our ownership and control of strategic facilities in our key plays resulting in enhanced market access and driving our cost structure lower. Tamarack provides investors with differentiated and focused exposure to two of North America’s most economic plays. Exiting 2023, we expect 88% of our production to be derived from our remaining core holdings in the Clearwater and Charlie Lake plays.”
Financial & Operating Results
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Three months ended |
Nine months ended |
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|
September 30, |
September 30, |
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|
2023 |
2022 |
% |
2023 |
2022 |
% |
|
|
($ 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 – $475 |
|||
|
Annual Average Production (boe/d)(4) |
67,000 – 71,000 |
65,500 – 69,500 |
|||
|
Average Oil & NGL Weighting |
81% – 83% |
82% – 84% |
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Expenses: |
|||||
|
Royalty Rate (%) |
19% – 21% |
19% – 21% |
|||
|
Operating ($/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).
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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. |
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