Message to Shareholders
The first quarter of 2023 marked Tamarack’s most active quarter in the Company’s history, peaking at nine active drilling rigs. Tamarack drilled 40 (39.8 net) horizontal wells in Q1 2023, including 32 (32.0 net) wells in the Clearwater and 8 (7.8 net) wells in the Charlie Lake. The Clearwater program was highlighted by the exploration success at Seal, West Marten Hills and West Nipisi. The Company’s first three wells at Seal delivered positive results with production from three stacked Clearwater sands. All three wells came on production from a single pad in March and achieved a combined IP30 rate of 380 bopd(2). Individual well performance IP30 rates include the ‘C’ sand (6 legs) at 206 bopd(2), ‘B’ sand (6 legs) at 130 bopd(2) and the ‘D’ sand (3 legs) at 43 bopd(2).
Total capital spending for the quarter of $148.2 million included approximately $30 million related to the construction of Tamarack’s Wembley gas plant and investment in the Clearwater Nipisi pipeline and terminal project. These two major infrastructure projects remain on-time and on budget, with the Wembley plant expected to be commissioned in June 2023. This sweet gas plant is a key component of Tamarack’s strategy to increase its egress capacity and concurrently reduce its operating cost structure related to ongoing development of the highly economic Charlie Lake oil play. The Clearwater Nipisi pipeline and terminal project is expected to be on-line at the end of third quarter and will drive operating cost savings along with netback enhancement from blending. When combining both projects, the Company expects to see both operating and transport costs driven lower throughout the year. These two initiatives have the potential to reduce the Company’s free funds flow breakeven by US$0.95 – US$1.10/bbl WTI and are key to enhancing free funds flow generation within the context of Tamarack’s five-year plan and return of capital framework.
Corporately, production for Q1 2023 averaged 67,938 boe/d(3), representing a 64% year-over-year increase and a 6% increase over the fourth quarter of 2022. Production through January and February averaged over 68,800 boe/d. the success of our drilling and exploration program, however, was somewhat muted by an unplanned TC Energy pipeline outage in March, which reduced total quarterly production by approximately 1,000 boe/d(4). Adjusting for this unplanned third-party event, production for Q1 was on track to exceed budget expectations.
The synergies from the combined Tamarack and Deltastream Energy Corp. (“Deltastream”) assets are delivering benefits through the scaled-up Clearwater development program. The combined multi-rig program across Nipisi and Marten Hills has enabled coordinated, shared services and the scale to enhance priority access to materials and equipment with our major service providers. The Deltastream assets continue to perform at or above the acquisition forecast, with additional upside and capital efficiency improvement opportunities underway.
Adjusted funds flow(1) of $157.3 million and free funds flow(1) of $9.1 million in the first quarter reflect the production impact of the unplanned third-party outages and a wider year-over-year WCS differential. Subsequent to the end of Q1 2023, the WCS differential has narrowed materially and current forward pricing indicates narrower WCS differentials through the balance of 2023. Looking ahead, management expects second quarter realized pricing to improve relative to the first quarter. As part of our ongoing risk management program, Tamarack has been proactive in responding to these differential improvements by locking in a portion of our heavy oil production with WCS differential swaps through to Q2 2024, which will reduce our exposure to potential heavy oil price volatility.
Subsequent to the end of the quarter, Tamarack extended and increased the existing 3-year covenant-based sustainability-linked lending (SLL) facility. The amended SLL has an increased capacity of $875 million (up from $700 million) and a new maturity date of May 10, 2026.
Financial & Operating Results
Three months ended |
|||
March 31, |
|||
2023 |
2022 |
% |
|
($ thousands, except per share) |
|||
Total oil, natural gas and processing revenue |
379,455 |
298,895 |
27 |
Cash flow from operating activities |
59,624 |
132,853 |
(55) |
Per share – basic |
$ 0.11 |
$ 0.32 |
(66) |
Per share – diluted |
$ 0.11 |
$ 0.31 |
(65) |
Adjusted funds flow(1) |
157,271 |
166,581 |
(6) |
Per share – basic |
$ 0.28 |
$ 0.40 |
(30) |
Per share – diluted |
$ 0.28 |
$ 0.39 |
(28) |
Net income (loss) |
2,505 |
26,457 |
(91) |
Per share – basic |
– |
$ 0.06 |
(100) |
Per share – diluted |
– |
$ 0.06 |
(100) |
Net debt(1) |
(1,374,068) |
(556,374) |
147 |
Capital expenditures(5) |
148,162 |
125,367 |
18 |
Weighted average shares outstanding (thousands) |
|||
Basic |
556,548 |
419,251 |
33 |
Diluted |
560,503 |
427,546 |
31 |
Share Trading |
|||
High |
$ 4.88 |
$ 6.09 |
(20) |
Low |
$ 3.48 |
$ 3.90 |
(11) |
Average daily share trading volume (thousands) |
3,056 |
3,769 |
(19) |
Average daily production |
|||
Light oil (bbls/d) |
17,035 |
17,868 |
(5) |
Heavy oil (bbls/d) |
34,399 |
7,522 |
357 |
NGL (bbls/d) |
4,122 |
4,113 |
– |
Natural gas (mcf/d) |
74,293 |
70,989 |
5 |
Total (boe/d) |
67,938 |
41,335 |
64 |
Average sale prices |
|||
Light oil ($/bbl) |
94.97 |
110.07 |
(14) |
Heavy oil, net of blending expense(1) ($/bbl) |
61.60 |
94.43 |
(35) |
NGL ($/bbl) |
45.91 |
56.21 |
(18) |
Natural gas ($/mcf) |
3.50 |
5.70 |
(39) |
Total ($/boe) |
61.61 |
80.17 |
(23) |
Operating netback ($/Boe) |
|||
Average realized sales, net of blending expense(1) |
61.61 |
80.17 |
(23) |
Royalty expenses |
(11.99) |
(15.72) |
(24) |
Net production and transportation expenses(1) |
(14.39) |
(12.07) |
19 |
Operating field netback ($/Boe)(1) |
35.23 |
52.38 |
(33) |
Realized commodity hedging loss |
(1.06) |
(4.00) |
(74) |
Operating netback ($/Boe)(1) |
34.17 |
48.38 |
(29) |
Adjusted funds flow ($/Boe)(1) |
25.72 |
44.78 |
(43) |
2023 Outlook & Guidance Update
The Company’s 2023 capital guidance range remains unchanged at $425 million to $475 million(5). Management continues to monitor commodity prices and will remain flexible with its second half capital program. Tamarack continues to target spending at the lower half of the range with a focus on maximizing free funds flow(1) for debt repayment and enhancing shareholder returns as debt thresholds are met. Our 2023 capital guidance maximizes free funds flow(1) generation over both the short and long term, with a significant amount capital in 2023 directed towards waterflood and infrastructure initiatives to set up lower sustaining capital and operating cost requirements throughout our five-year plan.
Subsequent to the first quarter, Tamarack disposed of certain non-core natural gas assets and decommissioning obligations for approximately $2.3 million in gross proceeds consisting of approximately 400 boe/d(6) of production. Our 2023 annual production guidance range has been updated to 67,000 to 71,000 boe/d(7) accounting for the disposition and the unplanned production downtime during the first quarter. Tamarack will provide further updates regarding the impact of the wildfires as additional information becomes available. Our operating cost, transportation expense, royalty, G&A and interest guidance range remain unchanged.
Original 2023 |
Updated 2023 |
|
Capital Budget ($mm)(5) |
$425 – $475 |
$425 – $475 |
Annual Average Production (boe/d)(7) |
68,000 – 72,000 |
67,000 – 71,000 |
Average Oil & NGL Weighting |
81% – 83% |
81% – 83% |
Expenses: |
||
Royalty Rate (%) |
19% – 21% |
19% – 21% |
Operating ($/boe) |
$9.00 – $9.50 |
$9.00 – $9.50 |
Transportation ($/boe)(8) |
$3.50 – $4.00 |
$3.50 – $4.00 |
General and Administrative ($/boe)(9) |
$1.25 – $1.35 |
$1.25 – $1.35 |
Interest ($/boe) |
$3.80 – $4.00 |
$3.80 – $4.00 |
Taxes (%)/($/boe)(10) |
10% – 12% |
$3.75 – $4.10 |
Leasing Expenditures ($mm) |
$3.5 – $4.5 |
$3.5 – $4.5 |
Operations Update
Production and Development
The safety of our people and the integrity of our assets is Tamarack’s primary focus. The Alberta wildfire situation is currently evolving and as such, we are monitoring this with respect to the potential direct and indirect impacts associated with third party infrastructure and facility disruptions which may impact production. In addition, we are monitoring the impact of these fires to Indigenous and local communities in the areas where we operate to determine ways to assist. Potential downtime estimates and overall impact to Q2 2023 volumes will be a function of overall duration of the events and impacts to regional operations.
Clearwater
Clearwater production averaged 36,800 boe/d(11) in the first quarter representing 54% of corporate production. The Company drilled and brought onstream 32 (32.0 net) wells and commenced injection to 6 (6.0 net) wells in the first quarter. West Marten Hills continues to exceed the Company’s expectations, where production has grown organically from approximately 400 boe/d(12) in Q4 2022 to over 3,400 boe/d(12). Initial rates from Tamarack’s 2022 drilling at Nipisi and West Marten Hills showed considerable improvement versus the prior year, with an increase of approximately 30% in the average IP30 of 200 bopd(13) relative to the Company’s 2021 wells which delivered IP30 rates of approximately 150 bopd(13). This trend has continued in 2023 with IP30 rates of 300 bopd(13) at West Marten Hills as the Company continues to delineate the pool and target areas with favourable viscosity. Building on results in this area Tamarack plans to drill an additional 22 (22.0 net) wells in the second half of 2023.
Tamarack has now drilled 14 (14.0 net) water injection wells at West Nipisi as part of the waterflood expansion. To drive further capital efficiency into the waterflood program Tamarack is utilizing multilateral injectors with two of the wells. The application of multilateral injection in this area is expected to lower overall project costs while achieving similar recoveries relative to single leg injection schemes. The original waterflood pilot producer at 102/13-19-076-07W5 has produced approximately 180,000 bbls to date and the water cut remains stable at approximately 20%. After more than 500 days of production this well is still producing approximately 400 bopd(13). In Marten Hills, Tamarack had two active drilling rigs throughout Q1 and plans to drill a total of 41 (41.0 net) wells in 2023. This activity includes further delineation of the Northwest area of the pool from the 12-26-75-25W4 pad, which will be on production in May 2023. Additionally, Tamarack has converted the first Marten Hills “W” pattern water injector and plans to commence injection in Q2 2023.
To support ongoing development, the Nipisi Battery expansion, complete with terminal connection, is in the final engineering stages and construction will commence in Q2 2023. Once the expansion is operational ~70% of Tamarack’s Nipisi oil production will be shipped to sales by pipeline. This project provides for long term value creation through enhanced netback opportunities and blending upside.
Charlie Lake
Leveraging off our large contiguous land base within the Charlie Lake fairway, Tamarack is successfully deploying pad development and utilizing longer laterals to drive enhanced cost efficiencies and realized free funds flow(1) generation. During the quarter, Charlie Lake production exceeded 16,000 boe/d(14), an almost 20% increase from the preceding quarter on the back of a successful Q4 and Q1 drilling program. The Company drilled 8 (7.8 net) wells during the quarter with 5 (4.8 net) wells commencing production. The Company plans to drill 11 (11.0 net) wells through the balance of 2023 and is driving down costs by increasing multi-well pad operations. The Company is currently completing Tamarack’s first three well Charlie Lake pad at 02-12-073-10W6 with an additional three well offsetting pad awaiting completion and drilling underway on a two well pad at 15-32-073-7W6. Continued cost improvement is expected with the second quarter program with an additional four well pad planned for Q4 2023.
Construction of the new Wembley gas plant is key to the multi-well pad strategy. This facility will provide Tamarack with operated, reliable processing capacity backstopped by a firm egress path for Tamarack’s ongoing regional development. With an initial capacity of 15 MMcf/d, this plant is expandable and offers visibility to tying-in production from an expanded field program.
Looking ahead, Tamarack is planning a waterflood pilot in Saddle Hills in Q4 2023. This project will capitalize on existing development well spacing that is conducive to successful multistage frac waterflood. Successful pilot results would have material impacts across our Charlie Lake fairway asset base with the long-term potential to tie production into our Wembley facility.
Exploration/Delineation Update
Tamarack continues to drive further inventory expansion through both our Seal Clearwater exploration results and our continued success on the West Nipisi Joint Venture. At Seal, the Company drilled and tested three separate Clearwater equivalent sands off one pad. Total production from the three wells on a peak IP30 basis is approximately 380 bopd(2). The lowermost sand was drilled with only three legs to test the commerciality of the sand, whereas the middle and upper sands were developed with 6-leg multilaterals and laterals approximately 1.25 miles in length. Owing to the strong results, Tamarack will advance to full development on these lands. Given the multiple zones, management expects development at Seal to drive strong capital efficiencies and economics with large-scale multi-well pads pushing lateral lengths to 1.5 miles. Anticipated development would result in pad costs of approximately $34 to $40 million and production rates of 2,200 – 3,000 bopd(2) per pad. At Seal, Tamarack owns 17 net sections with multizone potential and has a farm-in on 7 additional sections to accommodate future delineation.
At West Nipisi, the second well of the joint venture exploration program exhibited a peak IP30 rate of 175 bopd(13) with the first well showing low decline, delivering an IP90 rate of 160 bopd(13). Together, these results push the fairway of two Clearwater sands further to the west. Tamarack expects additional future drilling on these lands given the success of the program.
Return of Capital
The Company remains committed to balancing long-term sustainable free funds flow growth with returning capital to shareholders. The base dividend is currently $0.15/share annually which represents a 4.3% yield at the current share price. Debt repayment remains the immediate focus to achieve our enhanced return of capital thresholds whereby the Company will return from 25% up to 75% of excess funds flow(1) on a quarterly basis.
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 ~45% of net after royalty oil production is hedged against WTI with an average floor price of greater than US$65/bbl. Our strategy focuses on downside protection while maintaining upside exposure. Tamarack will continue to utilize financial instruments, including base commodity, associated differentials and foreign exchange. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca) or Tamarack’s consolidated financial statements and related management’s discussion and analysis for the three months ended March 31, 2023, which are available on SEDAR (www.sedar.com).
Investor Call Tomorrow |
9:30 AM MDT (11:30 AM EDT) |
Tamarack will host a webcast at 9:30 AM MDT (11:30 AM EDT) on Thursday, May 11, 2023, to discuss the first quarter financial results and an operational update. Participants can access the live webcast via this link or through links provided on the Company’s website. A recorded archive of the webcast will be available on the Company’s website following the live webcast. |
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake, Clearwater and EOR plays in Alberta. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. For more information, please visit the Company’s website at www.tamarackvalley.ca.
Abbreviations
AECO |
the natural gas storage facility located at Suffield, Alberta connected to TC Energy’s Alberta System |
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 |
GJ |
gigajoule |
IFRS |
International Financial Reporting Standards as issued by the International Accounting Standards Board |
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 crude oil in Western Canada |
NGL |
Natural gas liquids |
WCS |
Western Canadian select, the benchmark for conventional and oil sands heavy production at Hardisty in Western Canada |
WTI |
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade |
Reader Advisories
Notes to Press Release
(1) |
See “Specified Financial Measures” |
(2) |
All production and IP30 rates quoted for the Seal development program are comprised entirely of heavy oil. |
(3) |
Q1 2023 production of 67,938 boe/d was comprised of 17,035 bbl/d light and medium oil, 34,399 bbl/d heavy oil, 4,122 bbl/d NGL and 74,293 mcf/d natural gas. |
(4) |
Production impacts of approximately 1,000 boe/d comprised of approximately 200 bbl/d light and medium oil, 650 bbl/d heavy oil, 15 bbl/d NGL and 800 mcf/d natural gas. |
(5) |
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. |
(6) |
Production of 400 boe/d associated with the non-core asset disposition is comprised of 2,400 mcf/d natural gas. |
(7) |
Target production is comprised of 16,500-17,500 bbl/d light and medium oil, 34,750-36,500 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 71,000-75,000 mcf/d natural gas. |
(8) |
Transportation expense differs from the previously released 2023 guidance due to a change in the classification of pipeline tariffs in our corporate model. Some pipeline tariffs were originally included as a revenue deduction, are now included as transportation expense. |
(9) |
G&A noted excludes the effect of cash settled stock-based compensation. |
(10) |
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. |
(11) |
Q1 2023 Clearwater production of 36,800 boe/d is comprised of approximately 35,100 bbl/d heavy oil, 170 bbl/d NGL and 9,200 mcf/d natural gas. |
(12) |
Q4 2022 West Marten Hills production of approximately 400 boe/d is comprised of 400 bbl/d heavy oil while Q1 2023 West Marten Hills production of approximately 3,400 boe/d is comprised of 3,400 bbl/d heavy oil. |
(13) |
All production and IP30 rates quoted for the Nipisi and West Marten Hills development program are entirely comprised of heavy oil. |
(14) |
Q1 2023 Charlie Lake production of 16,000 boe/d is comprised of approximately 8,850 bbl/d light and medium oil, 2,150 bbl/d NGL and 30,000 mcf/d natural gas. |
Disclosure of Oil and Gas Information
Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with Canadian Securities Administrators’ National Instrument 51 101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Boe may be misleading, particularly if used in isolation.
References in this press release to “crude oil” or “oil” refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to “NGL” throughout this press release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51-101. References to “natural gas” throughout this press release refers to conventional natural gas as defined by NI 51-101.