Strathcona Resources Ltd. Reports Year End 2024 Reserves, Fourth Quarter and Full Year 2024 Financial and Operating Results, and Announces Quarterly Dividend
Readers are advised to review the "Presentation of Reserves and Other Oil and Gas Information" and "Non-GAAP Financial Measures and Ratios" at the conclusion of this news release for information regarding the presentation of the reserves information, as well as certain oil and gas metrics, and certain financial measures that do not have standardized meaning under generally accepted accounting principles, contained in this news release. All amounts in this news release are stated in Canadian dollars unless otherwise specified.
CALGARY, AB, March 4, 2025 /CNW/ - Strathcona Resources Ltd. ("Strathcona" or the "Company") (TSX: SCR) today reported its year end 2024 reserves and fourth quarter and full year 2024 financial and operational results. The Board of Directors also declared a quarterly dividend of $0.26 per common share to be paid on March 31, 2025 to all shareholders of record on March 21, 2025.
YE 2024 Reserves Highlights
- Proved Developed Producing ("PDP"), Proved ("1P"), and Proved Plus Probable ("2P") reserves of 367 MMboe, 1,534 MMboe, and 2,655 MMboe, reflecting growth of 8%, 3%, and 2% respectively (10%, 4%, and 2% respectively for oil and condensate)(1) versus December 31, 2023
- PDP finding and development ("F&D") costs(2), including changes in future development costs ("FDC"), of $13.49 per boe, equating to a 2024 PDP recycle ratio(2) of 2.4x
- 165% organic 2P reserve replacement(2); 39 Year 2P Reserve Life Index(2)
- Growth in PDP, 1P, and 2P before-tax PV-10 net of debt, including dividends(3) of 29%, 5% and 5% per share
FY 2024 Highlights
- Production of 183,080 boe/d (71% oil and condensate, 78% liquids)(1)
- Operating Earnings of $970.5 million ($4.53 / share)(2)
- Free Cash Flow of $606.1 million ($2.83 / share)(2)
Q4 2024 Highlights
- Production of 187,203 boe/d (70% oil and condensate, 77% liquids)(1)
- Operating Earnings of $190.0 million ($0.89 / share)(2)
- Free Cash Flow of $0.3 million(2)
(1) |
See "Presentation of Reserves and Other Oil and Gas Information" section of this press release. |
(2) |
A non-GAAP financial measure or ratio which does not have a standardized meaning under IFRS® Accounting Standards (the "Accounting Standards"); see "Non-GAAP Measures and Ratios" section of this press release. |
(3) |
See "Supplementary Financial Measures" section of this press release. |
Three Months Ended |
Year Ended |
||||
($ millions, unless otherwise indicated) |
December |
December |
September |
December |
December |
WTI (US$ / bbl) |
70.27 |
78.32 |
75.10 |
75.72 |
77.62 |
WCS Hardisty (C$ / bbl) |
80.75 |
76.85 |
83.96 |
83.53 |
79.51 |
AECO 5A (C$ / GJ) |
1.40 |
2.18 |
0.65 |
1.38 |
2.50 |
Bitumen (bbls/d) |
59,732 |
59,845 |
58,610 |
59,516 |
55,768 |
Heavy oil (bbls/d) |
50,997 |
52,736 |
50,494 |
51,107 |
53,707 |
Condensate and light oil (bbls/d) |
20,763 |
19,184 |
19,520 |
19,922 |
12,011 |
Total oil production (bbls/d) |
131,492 |
131,765 |
128,624 |
130,545 |
121,486 |
Other NGLs (bbls/d) |
12,980 |
11,906 |
11,680 |
11,958 |
9,021 |
Natural gas (mcf/d) |
256,386 |
254,361 |
227,581 |
243,456 |
149,715 |
Production (boe/d) |
187,203 |
186,064 |
178,235 |
183,080 |
155,459 |
Sales (boe/d) |
184,120 |
184,360 |
178,391 |
182,794 |
155,920 |
% Oil and condensate |
70 % |
71 % |
72 % |
71 % |
78 % |
% Liquids(1) |
77 % |
77 % |
79 % |
78 % |
84 % |
Oil and natural gas sales, net of blending costs and other income(2) |
1,024.6 |
1,003.7 |
1,041.3 |
4,255.0 |
3,690.8 |
Royalties |
208.5 |
134.9 |
134.0 |
662.7 |
556.9 |
Production and operating – Energy(2) |
58.7 |
72.5 |
45.7 |
248.1 |
322.3 |
Production and operating – Non-energy(2) |
138.5 |
133.3 |
140.2 |
563.6 |
474.0 |
Transportation and processing |
144.2 |
135.7 |
140.2 |
577.0 |
482.9 |
General and administrative |
28.4 |
24.5 |
25.5 |
101.1 |
91.9 |
Depletion, depreciation and amortization |
196.3 |
227.5 |
226.3 |
873.5 |
732.9 |
Interest and finance costs(3) |
60.0 |
73.2 |
64.0 |
258.5 |
281.5 |
Current income tax recovery |
— |
— |
— |
— |
(46.9) |
Operating Earnings(2) |
190.0 |
202.1 |
265.4 |
970.5 |
795.3 |
Other items(3) |
102.1 |
(61.6) |
77.4 |
366.8 |
208.1 |
Income and comprehensive income |
87.9 |
263.7 |
188.0 |
603.7 |
587.2 |
Operating Earnings(2) |
190.0 |
202.1 |
265.4 |
970.5 |
795.3 |
Non-cash items(3) |
217.3 |
249.1 |
360.6 |
1,074.4 |
807.9 |
(Loss) gain on risk management and foreign exchange contracts – realized |
(1.8) |
19.6 |
(97.3) |
(107.5) |
(41.0) |
Funds from Operations(2) |
405.5 |
470.8 |
528.7 |
1,937.4 |
1,562.2 |
Capital expenditures |
(392.5) |
(306.2) |
(319.6) |
(1,295.6) |
(1,026.8) |
Decommissioning costs |
(12.7) |
(13.8) |
(8.5) |
(35.7) |
(37.9) |
Free Cash Flow(2) |
0.3 |
150.8 |
200.6 |
606.1 |
497.5 |
Debt |
2,461.6 |
2,665.0 |
2,449.9 |
2,461.6 |
2,665.0 |
Common shares (millions) |
214.2 |
214.2 |
214.2 |
214.2 |
214.2 |
(1) |
See "Presentation of Reserves and Other Oil and Gas Information" section of this press release. |
(2) |
A non-GAAP financial measure or ratio which does not have a standardized meaning under the "Accounting Standards"; see "Non-GAAP Measures and Ratios" section of this press release. |
(3) |
See "Supplementary Financial Measures" section of this press release. |
Three Months Ended |
Year Ended |
||||
($/boe, unless otherwise indicated) |
December 31, 2024 |
December 31, 2023 |
September 30, 2024 |
December 31, 2024 |
December 31, 2023 |
Oil and natural gas sales, net of blending costs and other income(1) |
60.49 |
59.16 |
63.45 |
63.60 |
64.85 |
Royalties |
12.31 |
7.95 |
8.16 |
9.91 |
9.78 |
Production and operating – Energy(1) |
3.46 |
4.27 |
2.78 |
3.71 |
5.66 |
Production and operating – Non-energy(1) |
8.18 |
7.86 |
8.54 |
8.42 |
8.33 |
Transportation and processing |
8.51 |
8.00 |
8.54 |
8.62 |
8.49 |
General and administrative |
1.68 |
1.44 |
1.55 |
1.51 |
1.61 |
Depletion, depreciation and amortization |
11.59 |
13.41 |
13.79 |
13.06 |
12.88 |
Interest and finance costs(2) |
3.54 |
4.31 |
3.90 |
3.86 |
4.94 |
Current income tax recovery |
— |
— |
— |
— |
(0.82) |
Operating Earnings(1) |
11.22 |
11.92 |
16.19 |
14.51 |
13.98 |
Effective royalty rate (%)(1) |
20.3 % |
13.4 % |
12.9 % |
15.6 % |
15.1 % |
(1) |
A non-GAAP financial measure or ratio which does not have a standardized meaning under the Accounting Standards; see "Non-GAAP Measures and Ratios" section of this press release. |
(2) |
See "Supplementary Financial Measures" section of this press release. |
Annual Letters to Strathcona Shareholders
A letter to shareholders providing an in-depth review of Strathcona's year-end 2024 reserves and a full year review of 2024 financial and operating performance can be found on Strathcona's website at strathconaresources.com/investors/reports.
Quarter Review and Near-Term Priorities
Strathcona's fourth quarter production of 187 Mboe per day was up 5% quarter-over-quarter, with 2024 full year production of 183 Mboe per day in-line with guidance. Full year capital expenditures of $1,296 million were slightly below Strathcona's capital budget of $1,300 million. Fourth quarter free cash flow was negatively impacted by a build into inventory of 3 Mbbls per day of heavy oil and the deferral of crown royalty deductions associated with capital spending at Cold Lake and Lloydminster. Corresponding recoveries are expected in 2025, with excess heavy oil inventory being sold in January and the delayed capital expenditure deductions reducing 2025 royalties.
In Cold Lake, activity was focused on the tie-in of 8 new lower drainage wells (LDWs) on the D-East pad and 8 new well pairs on the C-South pad in Tucker. Early performance from both pads has exceeded expectations, with Tucker achieving average production of more than 28 Mbbls per day at a steam-oil-ratio (SOR) of 3.7x in February. This represents a production increase of approximately 50% and an SOR reduction of approximately 30% versus 2022-2024 average levels, and an all-time monthly production record for the project. The success of the lower drainage wells at D-East, which included Strathcona's first multi-lateral LDW, built upon learnings from Strathcona's piloting of LDWs at Orion between 2021-2024 and is expected to unlock further LDW development across the Tucker project. The step-change improvement at Tucker is another example of the operational improvements Strathcona has realized since it acquired its three Cold Lake assets between 2020 and 2022, with combined production now up approximately 30% since each was acquired, to 66 Mbbls per day in February.
In Lloydminster, production growth was driven by record production of over 6 Mbbls per day at Druid, up 35% quarter-over-quarter, partially offset by production downtime in Strathcona's Lloydminster thermal properties. Strathcona's 2024 Druid drilling program exceeded expectations, driven by strong performance from the Company's first multilateral well and first infill wells at 50 meter spacing. The validation of multilaterals and infills in turn translated into a greater than 36% increase in 2P reserves for year-end 2024 at Druid. Current activity in Lloydminster is focused on the tie-in of the Meota West 2 OTSG expansion exploiting the General Petroleum formation (targeting first oil in the second quarter of 2025), construction of the new Meota Central processing facility (targeting first oil in the fourth quarter of 2026), and the annual conventional drilling program.
In the Montney, the fourth quarter saw the return of previously shut-in volumes at Groundbirch following improved natural gas pricing, as well as record quarterly production of over 38 Mboe per day at Kakwa (approximately 57% liquids) driven by strong performance at the recently tied-in 3-24 pad. Strathcona also finished drilling the 5 well 5-21 pad at Kakwa, the Company's first with 2.5-mile laterals, which achieved approximately 9% per lateral meter savings versus the previous 2.0-mile design (DCE&T costs of approximately $3,965 / lateral meter vs. $4,350 / lateral meter). Current activity is focused on the 5-well 3-04 pad in Kakwa and 6-well 14-04 pad in Grand Prairie.
Subsequent to the quarter-end, Strathcona received approval for an expanded credit facility of approximately $2.75 billion (from $2.50 billion previously) through an amended and restated credit agreement which includes a new US$175 million term credit facility. The amended and restated credit agreement includes a $250 million accordion feature, allowing the credit facility to expand to $3.0 billion subject to certain conditions.
U.S. Tariffs
Strathcona is closely monitoring the implementation of U.S. tariffs and thus far expects the financial impact to be largely mitigated. Of the approximately 115 Mbbls per day of bitumen and heavy oil Strathcona produces, approximately 85 Mbbls per day ("Local Sales") is sold in Western Canada markets and approximately 30 Mbbls per day is sold in the United States Gulf Coast ("USGC Sales"). Tariffs will impact Strathcona's Local Sales to the extent they cause a widening in WTI-WCS Hardisty differentials, and in the fourth quarter of 2024 Strathcona hedged 45 Mbbls per day (approximately 53% of its Local Sales) at a US$12.94 / bbl differential for full-year 2025.
For Strathcona's USGC Sales, Strathcona will pay a tariff based on its landed price, net of transportation, in the USGC, estimated at approximately US$5 per barrel at current prices. However, Strathcona's USGC Sales are priced at a premium to the WCS Houston benchmark, and since potential tariffs were announced in November 2024 WTI-WCS Houston differentials have strengthened by approximately US$2.50 per barrel, implicitly reflecting the portion of the tariff born by the U.S. downstream buyer and negating approximately 50% of the tariff impact to Strathcona. In the first quarter of 2025, Strathcona hedged approximately 21 Mbbls per day (approximately 70% of USGC sales) at a WTI-WCS Houston differential of US$3.52 per barrel between April and September 2025.
Taken together, Strathcona's financial hedges, the strengthening of the WCS Houston benchmark, and the weaker Canadian dollar are expected to significantly insulate Strathcona from U.S. tariffs. Relative to Strathcona's November 2024 Investor Day (which included 2025 guidance based on US$70 per barrel WTI, US$13 per barrel WTI-WCS Hardisty differentials, US$5 per barrel WTI-WCS Houston differentials, and 1.38x CAD-USD), current pricing of approximately US$68 per barrel WTI, US$14.00 per barrel WTI-WCS Hardisty differentials, US$2.50 per barrel WTI-WCS Houston differentials, and 1.45x USD-CAD is estimated to translate to approximately the same all-in net realized price, after hedging and including tariff payments. To the extent WCS Hardisty differentials widened to US$15.50 per barrel (which in Strathcona's view would represent the maximum theoretical impact of tariffs), the net impact to Strathcona's realized price, after hedging and including tariff payments is expected to be approximately 1% (despite US$2 per barrel lower WTI).
Finally, Strathcona also produces approximately 20 Mbbls per day of condensate which is approximately 100% consumed internally for Strathcona's operations and therefore is not meaningfully exposed to the impact of tariffs on condensate prices. Any impact of tariffs on Strathcona's natural gas and natural gas liquids sales is expected to be minimal relative to Strathcona's total revenue.
Dividend Increase
Strathcona's board of directors has declared a quarterly dividend of $0.26 per common share to be paid on March 31, 2025 to shareholders of record on March 21, 2025. This reflects an increase of 4% versus the prior quarter, in-line with expected production growth. Future dividend increases will be considered based on further growth in production and/or reductions in full-cycle WTI breakeven prices. Payments to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that may be applicable. Dividends paid by Strathcona are considered "eligible dividends" for Canadian tax purposes.
Outlook
Year to date 2025 production has averaged approximately 195 Mboe per day, meaningfully above expectations, and Strathcona will re-evaluate 2025 guidance of 185-195 Mboe per day mid-year. Strathcona's 2025 capital budget of $1.35 billion is unchanged.
Conference Call Details
Strathcona will host a conference call on Wednesday March 5, 2025, starting at 9:00AM MT (11:00AM ET), to review the Company's year-end 2024 reserves and fourth quarter and year end 2024 financial and operating results.
Date: Wednesday, March 5, 2025
Time: 11:00AM ET (9:00AM MT)
URL Entry: To join without operator assistance, register at https://emportal.ink/3VHJaZC up to 15 minutes before the start time. Enter your name and phone number to receive an automated call-back.
Telephone Entry: Alternatively, you can join with operator assistance by dialing 1 (888) 510-2154 (North American Toll Free) and quote conference ID 73482
Webcast Link: https://app.webinar.net/y1JGnDLnaYD
For those unable to participate in the conference call at the scheduled time, a recording of the conference call will be available for seven days following the call and can be accessed by dialing 1 (888) 660-6345 and entering the conference number 73482.
2024 Reserves Information
The tables below summarize Strathcona's 2024 year-end reserves which were prepared by McDaniel & Associates Consultants Ltd. ("McDaniel"). A complete filing of our oil and gas reserves and other oil and gas information presented in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") are included in Strathcona's Annual Information Form for the year ended December 31, 2024, which can be found at www.sedarplus.ca and www.strathconaresources.com .
Summary of Oil and Gas Reserves (Forecast Prices and Costs) as of December 31, 2024
Reserves Category |
Light & Medium Crude Oil |
Heavy Crude Oil |
Bitumen |
Conventional Natural Gas (Associated & Non-Associated Gas) |
|||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||||||
Proved |
|||||||||||||||
Developed Producing |
877 |
688 |
99,884 |
89,768 |
136,222 |
95,481 |
460,110 |
420,259 |
|||||||
Developed Non-Producing |
19 |
17 |
1,260 |
1,093 |
— |
— |
7,384 |
6,801 |
|||||||
Undeveloped |
933 |
732 |
369,292 |
328,922 |
562,083 |
363,274 |
843,999 |
756,524 |
|||||||
Total Proved(1) |
1,829 |
1,437 |
470,436 |
419,782 |
698,305 |
458,755 |
1,311,492 |
1,183,584 |
|||||||
Total Probable |
4,549 |
3,284 |
167,287 |
144,871 |
684,534 |
426,945 |
1,011,153 |
882,395 |
|||||||
Total Proved Plus Probable(1) |
6,378 |
4,720 |
637,723 |
564,653 |
1,382,840 |
885,700 |
2,322,645 |
2,065,979 |
|||||||
Reserves Category |
Conventional Natural Gas |
Natural Gas Liquids |
Oil Equivalent |
||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
||||||||||
Proved |
|||||||||||||||
Developed Producing |
9,956 |
9,172 |
52,113 |
42,002 |
367,441 |
299,511 |
|||||||||
Developed Non-Producing |
287 |
258 |
1,242 |
1,003 |
3,800 |
3,288 |
|||||||||
Undeveloped |
8,684 |
7,922 |
88,321 |
73,205 |
1,162,742 |
893,540 |
|||||||||
Total Proved(1) |
18,927 |
17,352 |
141,676 |
116,210 |
1,533,983 |
1,196,340 |
|||||||||
Total Probable |
33,197 |
29,923 |
90,424 |
68,802 |
1,120,852 |
795,954 |
|||||||||
Total Proved Plus Probable(1) |
52,124 |
47,275 |
232,100 |
185,012 |
2,654,835 |
1,992,294 |
|||||||||
(1) Figures may not add due to rounding. |
(2) Conventional Natural Gas (Solution Gas) includes all gas produced in association with light and medium crude oil and heavy crude oil. |
Summary of Net Present Value of Future Net Revenue Attributable to Oil and Gas Reserves (Forecast Prices and Costs) as of December 31, 2024
Reserves Category |
Before Deducting Income Taxes |
After Deducting Income Taxes |
||||||||||
0 % |
5 % |
10 % |
15 % |
20 % |
Unit Value(2) |
0 % |
5 % |
10 % |
15 % |
20 % |
Unit Value(3) |
|
(in $ millions)(1) |
$/boe |
(in $ millions)(1) |
$/boe |
|||||||||
Proved |
||||||||||||
Developed Producing |
7,438 |
6,991 |
6,113 |
5,401 |
4,847 |
20.41 |
6,679 |
6,401 |
5,641 |
5,015 |
4,525 |
18.84 |
Developed Non‑Producing |
102 |
86 |
75 |
67 |
60 |
22.73 |
77 |
65 |
57 |
51 |
46 |
17.35 |
Undeveloped |
26,767 |
14,758 |
8,783 |
5,473 |
3,487 |
9.83 |
20,166 |
10,801 |
6,190 |
3,660 |
2,157 |
6.93 |
Total Proved(4) |
34,307 |
21,835 |
14,971 |
10,940 |
8,394 |
12.51 |
26,922 |
17,266 |
11,888 |
8,725 |
6,729 |
9.94 |
Total Probable |
31,710 |
13,267 |
7,026 |
4,325 |
2,938 |
8.83 |
24,148 |
9,929 |
5,181 |
3,148 |
2,115 |
6.51 |
Total Proved plus Probable(4) |
66,017 |
35,101 |
21,997 |
15,265 |
11,333 |
11.04 |
51,070 |
27,195 |
17,069 |
11,874 |
8,844 |
8.57 |
(1) |
Net present value of future net revenue includes all resource income, including the sale of oil, gas, by-product reserves, processing third party reserves and other income. |
(2) |
Calculated using net present value of future net revenue before deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes. |
(3) |
Calculated using net present value of future net revenue after deducting income taxes, discounted at 10% per year, and net reserves. The unit values are based on net reserves volumes. |
(4) |
Figures may not add due to rounding. |
Forecast Prices and Costs as of December 31, 2024
Year |
Inflation |
Exchange Rate |
Crude Oil |
Natural Gas |
Natural Gas Liquids |
|||||
WTI Cushing |
Canadian Light |
Western Canadian |
Alberta AECO-C |
Edmonton |
Edmonton |
Edmonton |
Ethane |
|||
2025 |
— % |
1.40 |
71.58 |
94.79 |
82.69 |
2.36 |
100.14 |
51.15 |
33.56 |
7.54 |
2026 |
2 % |
1.37 |
74.48 |
97.04 |
84.27 |
3.33 |
100.72 |
49.99 |
32.78 |
10.76 |
2027 |
2 % |
1.35 |
75.81 |
97.37 |
83.81 |
3.48 |
100.24 |
50.16 |
32.81 |
11.32 |
2028 |
2 % |
1.35 |
77.66 |
99.80 |
85.70 |
3.69 |
102.73 |
51.41 |
33.63 |
12.02 |
2029 |
2 % |
1.35 |
79.22 |
101.79 |
87.45 |
3.76 |
104.79 |
52.44 |
34.30 |
12.26 |
2030 |
2 % |
1.35 |
80.80 |
103.83 |
89.25 |
3.83 |
106.86 |
53.49 |
34.99 |
12.51 |
2031 |
2 % |
1.35 |
82.42 |
105.91 |
91.04 |
3.91 |
109.01 |
54.56 |
35.69 |
12.77 |
2032 |
2 % |
1.35 |
84.06 |
108.03 |
92.85 |
3.99 |
111.19 |
55.65 |
36.40 |
13.03 |
2033 |
2 % |
1.35 |
85.74 |
110.19 |
94.71 |
4.07 |
113.42 |
56.76 |
37.13 |
13.30 |
2034 |
2 % |
1.35 |
87.46 |
112.39 |
96.61 |
4.15 |
115.69 |
57.90 |
37.87 |
13.57 |
Escalation of 2% per year thereafter |
||||||||||
(1) Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale. |
(2) Inflation rates for forecasting costs only. Prices inflated at 2% after 2025 where applicable. |
(3) The exchange rate is used to generate the benchmark reference prices in this table. |
Reconciliation of Changes in Gross Reserves(1)
Conventional Natural Gas |
|||||||
Light & Medium |
Heavy Crude |
Bitumen |
Non-Associated |
Solution Gas |
Natural Gas Liquids |
Oil |
|
Proved |
|||||||
December 31, 2023 |
1,701 |
449,983 |
673,057 |
1,342,535 |
19,824 |
136,846 |
1,488,647 |
Extensions and improved recovery(2) |
219 |
11,413 |
11,599 |
119,799 |
1,381 |
9,729 |
53,157 |
Technical revisions(3) |
148 |
27,008 |
35,432 |
(53,368) |
(555) |
7,405 |
61,006 |
Discoveries(4) |
— |
— |
— |
— |
— |
— |
— |
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
Dispositions |
— |
(403) |
— |
— |
— |
— |
(403) |
Economic factors(5) |
(1) |
1,141 |
— |
(10,065) |
(26) |
(875) |
(1,416) |
Production |
(238) |
(18,705) |
(21,783) |
(87,409) |
(1,696) |
(11,430) |
(67,007) |
Infill drilling |
— |
— |
— |
— |
— |
— |
— |
December 31, 2024(6) |
1,829 |
470,436 |
698,305 |
1,311,492 |
18,927 |
141,676 |
1,533,983 |
Probable |
|||||||
December 31, 2023 |
3,359 |
168,324 |
680,169 |
1,073,714 |
25,497 |
88,447 |
1,123,501 |
Extensions and improved recovery(2) |
913 |
(974) |
2,471 |
(35,131) |
6,198 |
1,740 |
(673) |
Technical revisions(3) |
286 |
18 |
1,895 |
(21,609) |
1,550 |
949 |
(195) |
Discoveries(4) |
— |
— |
— |
— |
— |
— |
— |
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
Dispositions |
— |
(112) |
— |
— |
— |
— |
(112) |
Economic factors(5) |
(8) |
31 |
— |
(5,821) |
(48) |
(713) |
(1,669) |
Production |
— |
— |
— |
— |
— |
— |
— |
Infill drilling |
— |
— |
— |
— |
— |
— |
— |
December 31, 2024(6) |
4,549 |
167,287 |
684,534 |
1,011,153 |
33,197 |
90,424 |
1,120,852 |
Proved Plus Probable |
|||||||
December 31, 2023 |
5,059 |
618,307 |
1,353,226 |
2,416,249 |
45,321 |
225,294 |
2,612,148 |
Extensions and improved recovery(2) |
1,132 |
10,439 |
14,070 |
84,668 |
7,579 |
11,469 |
52,484 |
Technical revisions(3) |
434 |
27,026 |
37,327 |
(74,977) |
995 |
8,355 |
60,811 |
Discoveries(4) |
— |
— |
— |
— |
— |
— |
— |
Acquisitions |
— |
— |
— |
— |
— |
— |
— |
Dispositions |
— |
(515) |
— |
— |
— |
— |
(515) |
Economic factors(5) |
(9) |
1,172 |
— |
(15,886) |
(74) |
(1,588) |
(3,086) |
Production |
(238) |
(18,705) |
(21,783) |
(87,409) |
(1,696) |
(11,430) |
(67,007) |
Infill drilling |
— |
— |
— |
— |
— |
— |
— |
December 31, 2024(6) |
6,378 |
637,723 |
1,382,840 |
2,322,645 |
52,124 |
232,100 |
2,654,835 |
(1) |
Gross reserves means Strathcona's working interest reserves before calculation of royalties, and before consideration of Strathcona's royalty interests. |
(2) |
Additions due to new wells drilled and booked during the year, and any reserve changes due to enhanced oil recovery. |
(3) |
Technical revisions include changes in reserves associated with changes in operating costs, capital costs and commodity price offsets. |
(4) |
Additions where no reserves were previously booked. |
(5) |
Changes to reserves volumes due to changes in price forecasts and/or inflation rates. |
(6) |
Figures may not add due to rounding. |
Undiscounted Future Net Revenue by Reserves Category
Reserves Category |
Revenue |
Royalties |
Operating |
Development |
Abandonment |
Future Net |
Income |
Future Net |
Total Proved |
119,912 |
29,362 |
37,187 |
16,688 |
2,368 |
34,307 |
7,385 |
26,922 |
Total Probable |
111,365 |
35,467 |
29,065 |
14,539 |
583 |
31,710 |
7,562 |
24,148 |
Total Proved plus Probable (1) |
231,277 |
64,830 |
66,252 |
31,227 |
2,951 |
66,017 |
14,947 |
51,070 |
(1) Figures may not add due to rounding |
About Strathcona
Strathcona is one of North America's fastest growing oil and gas producers with operations focused on thermal oil, enhanced oil recovery and liquids-rich natural gas. Strathcona is built on an innovative approach to growth achieved through the consolidation and development of long-life oil and gas assets. Strathcona's common shares (symbol SCR) are listed on the Toronto Stock Exchange (TSX).
For more information about Strathcona, visit www.strathconaresources.com.
Non-GAAP Financial Measures and Ratios
Non-GAAP financial measures and ratios are used internally by management to assess the performance of the Company. They also provide investors with meaningful metrics to assess the Company's performance compared to other companies in the same industry. However, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to financial measures determined in accordance with GAAP and these measures should not be considered to be more meaningful than GAAP measures in evaluating the Company's performance.
"Oil and natural gas sales, net of blending and other income" is calculated by deducting purchased product and blending costs from oil and natural gas sales, sales of purchased product and other income. Management uses this metric to isolate the revenue associated with the Company's production after accounting for the unavoidable cost of blending. The following table contains a quantitative reconciliation of Oil and natural gas sales, net of blending and other income to the most directly comparable GAAP financial measure, oil and natural gas sales.
Three Months Ended |
Year Ended |
||||
($ millions, unless otherwise indicated) |
December |
December |
September |
December |
December |
Oil and natural gas sales |
1,292.8 |
1,287.6 |
1,272.5 |
5,336.4 |
4,748.3 |
Sales of purchased products |
15.6 |
11.3 |
44.4 |
75.0 |
46.3 |
Other income (loss) |
— |
(0.1) |
0.1 |
0.1 |
1.0 |
Purchased product |
(16.1) |
(10.3) |
(43.9) |
(75.0) |
(46.5) |
Blending costs |
(267.7) |
(284.8) |
(231.8) |
(1,081.5) |
(1,058.3) |
Oil and natural gas sales, net of blending and other income (loss) |
1,024.6 |
1,003.7 |
1,041.3 |
4,255.0 |
3,690.8 |
"Production and operating – Energy" is the portion of production and operating expenses reflecting the cost of gas and propane fuel, utilities and carbon tax incurred to operate facilities. This metric allows management to analyze the portion of production and operating expenses subject to non-controllable market prices.
The term "Production and operating – Non-energy" is the portion of production and operating expenses reflecting the cost of operating activities relating to the production of resources. This metric allows management to analyze the portion of production and operating expenses that is within the Company's control. A quantitative reconciliation of Production and operating – Energy and Production and operating – Non energy to the most directly comparable GAAP financial measure, Production and operating expenses, is set forth below.
Three Months Ended |
Year Ended |
||||
($ millions, unless otherwise indicated) |
December 31, 2024 |
December 31, 2023 |
September 30, 2024 |
December 31, 2024 |
December 31, 2023 |
Production and operating – Energy |
58.7 |
72.5 |
45.7 |
248.1 |
322.3 |
Production and operating – Non-energy |
138.5 |
133.3 |
140.2 |
563.6 |
474.0 |
Production and operating expenses |
197.2 |
205.8 |
185.9 |
811.7 |
796.3 |
"Operating Earnings" is considered a key financial metric for evaluating the profitability of Strathcona's principal business and is derived from income (loss) and comprehensive income (loss) adjusted for amounts which are considered non-recurring or not directly attributable to the Company's operations.
"Funds from Operations" is used by management to analyze operating performance and provides an indication of the funds generated by Strathcona's principal business to either fund operating activities, re-invest to either maintain or grow the business or make debt repayments. Funds from Operations is derived from income (loss) and comprehensive income (loss) adjusted for non-cash items and transaction costs.
"Free Cash Flow" indicates funds available for deleveraging, funding future growth, or shareholder returns. Free Cash Flow is derived from income (loss) and comprehensive income (loss) adjusted for non-cash items, transaction costs, capital expenditures and decommissioning costs.
A quantitative reconciliation of Operating Earnings, Funds from Operations and Free Cash Flow to the most directly comparable GAAP financial measure, income (loss) and comprehensive income (loss), is set forth below.
Three Months Ended |
Year Ended |
||||
($ millions, unless otherwise indicated) |
December 31, 2024 |
December 31, 2023 |
September 30, 2024 |
December 31, 2024 |
December 31, 2023 |
Income (loss) and comprehensive income (loss) |
87.9 |
263.7 |
188.0 |
603.7 |
587.2 |
Loss (gain) on risk management contracts |
(10.2) |
(129.1) |
16.6 |
44.0 |
(69.6) |
Foreign exchange (gain) loss |
47.7 |
(20.9) |
(6.8) |
68.2 |
(22.1) |
Transaction related costs |
0.3 |
(1.3) |
0.3 |
1.0 |
3.8 |
Unrealized (gain) loss on Sable remediation fund |
— |
(0.3) |
(0.2) |
(0.1) |
(0.2) |
Loss on settlement of other obligation |
— |
— |
4.4 |
4.4 |
— |
Deferred tax expense |
64.3 |
90.0 |
63.1 |
249.3 |
296.2 |
Operating Earnings |
190.0 |
202.1 |
265.4 |
970.5 |
795.3 |
Depletion, depreciation and amortization |
196.3 |
227.5 |
226.3 |
873.5 |
732.9 |
Finance costs |
21.0 |
21.6 |
21.9 |
88.3 |
75.3 |
Decommissioning government grant |
— |
— |
— |
0.2 |
(0.3) |
(Loss) gain on risk management contracts - realized |
(5.4) |
19.5 |
(94.7) |
(107.0) |
(42.4) |
Realized loss on deferred premium settlement |
— |
— |
112.4 |
112.4 |
— |
Foreign exchange (loss) gain - realized |
3.6 |
0.1 |
(2.6) |
(0.5) |
1.4 |
Funds from Operations |
405.5 |
470.8 |
528.7 |
1,937.4 |
1,562.2 |
Capital expenditures |
(392.5) |
(306.2) |
(319.6) |
(1,295.6) |
(1,026.8) |
Decommissioning costs |
(12.7) |
(13.8) |
(8.5) |
(35.7) |
(37.9) |
Free Cash Flow |
0.3 |
150.8 |
200.6 |
606.1 |
497.5 |
"Effective royalty rate" is calculated by dividing royalties by oil and natural gas sales and sales of purchased product, net of blending costs and purchased product. This metric allows management to analyze the movement of royalty expenses in relation to realized and benchmark commodity prices.
"PDP Recycle Ratio" is calculated by dividing the Organic Operating Netback by PDP Finding and Development Costs ("PDP F&D"). PDP Recycle Ratio is used to measure the profit per barrel of oil to the cost of finding and developing that barrel of oil.
"Organic Operating Netback" is used to assess the profitability and efficiency of Strathcona's field operations before the impact of acquisitions.
A quantitative reconciliation of "Organic Operating Netback" to the most comparable GAAP measure, "Oil and natural gas sales", is set forth below:
Year Ended |
|
($ millions, unless otherwise indicated) |
December 31, 2024 |
Oil and natural gas sales |
5,336.4 |
Sales of purchased products |
75.0 |
Purchased product |
(75.0) |
Blending costs |
(1,081.5) |
Oil and natural gas sales, net of blending |
4,254.9 |
Royalties |
662.7 |
Production and operating |
811.7 |
Transportation and processing |
577.0 |
Field Operating Income |
2,203.5 |
Operating income from properties acquired in the year |
- |
Organic Operating Income |
2,203.5 |
Sales volumes (boe/d) |
182,794 |
Less: sales volumes from properties acquired in the year (boe/d) |
- |
Organic Sales volumes (boe/d) |
182,794 |
Organic Operating Netback ($/boe) |
32.94 |
"PDP F&D Costs" are calculated as Organic Capex plus changes in PDP future development costs (2024 - $56.0 million), divided by PDP reserve additions for the year (2024 – 95.7 MMboe), excluding the impact of acquisitions and dispositions. Management uses PDP F&D costs as a measure of capital efficiency for organic reserves development.
"Organic Capex" is calculated as property, plant and equipment expenditures excluding capitalized overhead, expenditures on corporate assets and property, plant and equipment expenditures on acquired assets.
A quantitative reconciliation of "Organic Capex" to the most comparable GAAP measure, "Property, plant and equipment expenditures", is set for below:
Year Ended |
|
($ millions) |
December 31, 2024 |
Property, plant and equipment expenditures |
1,295.6 |
Less: capitalized overhead |
(52.1) |
Less: expenditures on corporate assets |
(9.0) |
Less: property, plant and equipment expenditures on assets acquired in the year |
— |
Organic Capex |
1,234.5 |
"Organic 2P Reserves Replacement" is calculated as 2P reserves additions, excluding acquisitions and dispositions, divided by annual production volumes.
"2P Reserve Life Index" calculated by dividing gross 2P reserves by annualized fourth quarter production.
Supplementary Financial Measures
"PDP, 1P and 2P before tax PV10 net of debt, including dividends, per share" is comprised of before tax present value for PDP, 1P and 2P reserves, discounted at 10 per cent, as determined in accordance with NI 51-101, adjusted for debt at the end of the period and dividends paid, divided by shares outstanding at the end of the period.
"Interest and finance costs" is an aggregation of interest and finance costs. Management uses this metric to obtain a fulsome understanding of all interest and accretion costs the Company is subject to.
"Other items" is an aggregation of risk management contracts, foreign exchange, transaction related costs, unrealized loss (gain) on Sable remediation fund, loss on settlement of other obligations, and deferred tax expense. They are presented in such a manner to yield prominence to key financial metrics such as income and comprehensive income, Funds from Operations and Free Cash Flow.
Three Months Ended |
Year Ended |
||||
($ millions, unless otherwise indicated) |
December 31, 2024 |
December 31, 2023 |
September 30, 2024 |
December 31, 2024 |
December 31, 2023 |
Loss (gain) on risk management contracts |
(10.2) |
(129.1) |
16.6 |
44.0 |
(69.6) |
Foreign exchange (gain) loss |
47.7 |
(20.9) |
(6.8) |
68.2 |
(22.1) |
Transaction related costs |
0.3 |
(1.3) |
0.3 |
1.0 |
3.8 |
Unrealized (gain) loss on Sable remediation fund |
— |
(0.3) |
(0.2) |
(0.1) |
(0.2) |
Loss on settlement of other obligation |
— |
— |
4.4 |
4.4 |
— |
Deferred tax expense |
64.3 |
90.0 |
63.1 |
249.3 |
296.2 |
Other items |
102.1 |
(61.6) |
77.4 |
366.8 |
208.1 |
"Non-cash items" is an aggregation of depletion, depreciation and amortization, finance costs, and other income – decommissioning government grant. They are presented in such a manner to yield prominence to key financial metrics such as income and comprehensive income, Funds from Operations and Free Cash Flow.
Three Months Ended |
Year Ended |
||||
($ millions, unless otherwise indicated) |
December 31, 2024 |
December 31, 2023 |
September 30, 2024 |
December 31, 2024 |
December 31, 2023 |
Depletion, depreciation and amortization |
196.3 |
227.5 |
226.3 |
873.5 |
732.9 |
Finance costs |
21.0 |
21.6 |
21.9 |
88.3 |
75.3 |
Other income – Decommissioning government grant |
— |
— |
— |
0.2 |
(0.3) |
Realized loss on deferred premium settlement |
— |
— |
112.4 |
112.4 |
— |
Non-cash items |
217.3 |
249.1 |
360.6 |
1,074.4 |
807.9 |
Presentation of Reserves and Other Oil and Gas Information
This press release contains various references to the abbreviation "boe" which means barrels of oil equivalent. All boe conversions in this press release are derived by converting gas to oil at the ratio of six thousand cubic feet ("mcf") of natural gas to one barrel ("bbl") of crude oil. Boe may be misleading, particularly if used in isolation. A boe conversion rate of 1 bbl : 6 mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 bbl : 6 mcf, utilizing a conversion ratio of 1 bbl : 6 mcf may be misleading as an indication of value.
In respect of 2023 year-end reserves information contained in this press release, Strathcona's reserves have been evaluated in accordance with Canadian reserve evaluation standards under NI 51-101. McDaniel and Sproule Associates Limited ("Sproule"), each an independent petroleum consulting firm based in Calgary, Alberta, have each evaluated the petroleum and natural gas reserves associated with Strathcona's interests in Alberta, British Columbia and Saskatchewan. For consistency in Strathcona's reserves reporting, McDaniel and Sproule used the forecast prices and costs of Sproule as at December 31, 2023 to prepare their reports. Such estimates constitute forward-looking information, which are based on values that Strathcona's management believes to be reasonable, and are subject to the same limitations discussed under "Forward-Looking Information" below.
References in this press release to initial production rates and other short-term production rates and test results 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 aggregate production for the Company or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the test results should be considered to be preliminary.
References to initial production rates 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 aggregate production for us or the assets for which such rates are provided. Accordingly, we caution that the initial production rates should be considered to be preliminary.
Product Type Production and Reserve Information
National Instruments 51-101 - Standards of Disclosure for Oil and Gas Activities includes condensate within the natural gas liquids product type. The Company has disclosed condensate as combined with light oil and separately from other natural gas liquids in this press release since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this presentation provides a more accurate description of its operations and results therefrom. References to "oil and condensate" in this press release refer to, collectively, light and medium crude oil, heavy crude oil, bitumen and natural gas liquids. References to "natural gas" in this press release refer to conventional natural gas. References to "liquids" in this press release refer to, collectively, bitumen, heavy oil, condensate and light oil (comprised of condensate and light oil) and other natural gas liquids (comprised of ethane, propane and butane only).
The Company's quarterly and year-to-date average daily production volumes, and the references to "natural gas", "crude oil" and "condensate", reported in this press release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:
Three Months Ended |
Year Ended |
||||
December 31, 2024 |
December 31, 2023 |
September 30, 2024 |
December 31, 2024 |
December 31, 2023 |
|
Heavy crude oil (bbl/d) |
50,997 |
52,736 |
50,494 |
51,107 |
53,707 |
Light and medium crude oil (bbl/d) |
617 |
580 |
645 |
651 |
642 |
Total crude oil (bbl/d) |
51,614 |
53,316 |
51,139 |
51,758 |
54,349 |
Bitumen (bbl/d) |
59,732 |
59,845 |
58,610 |
59,516 |
55,768 |
NGLs (bbl/d) |
33,126 |
30,509 |
30,555 |
31,229 |
20,389 |
Total liquids (bbl/d) |
144,472 |
143,670 |
140,304 |
142,503 |
130,506 |
Conventional natural gas (mcf/d) |
256,386 |
254,361 |
227,581 |
243,456 |
149,715 |
Total (boe/d) |
187,203 |
186,064 |
178,235 |
183,080 |
155,459 |
The following is a reconciliation of product types as defined by NI 51-101 to "Total Oil and Condensate" as referenced in this press release:
2024
NI 51-101 Light & |
NI 51-101 |
NI 51-101 |
Condensate |
Total Oil and |
|
Reserves Category |
(MMbbl) |
(MMbbl) |
(MMbbl) |
(MMbbl) |
(MMbbl) |
Proved |
|||||
Developed Producing(1) |
1 |
100 |
136 |
26 |
263 |
Developed Non-Producing(1) |
- |
1 |
- |
1 |
2 |
Undeveloped(1) |
1 |
369 |
562 |
50 |
982 |
Total Proved(1) |
2 |
470 |
698 |
76 |
1,247 |
Probable(1) |
5 |
167 |
685 |
48 |
905 |
Total Proved plus Probable(1) |
6 |
638 |
1,383 |
125 |
2,152 |
(1) Figures may not add due to rounding |
NI 51-101 Natural |
Less: |
Natural |
NI 51-101 |
Natural |
Total |
||
Reserves Category |
(MMbbl) |
(MMbbl) |
(MMbbl) |
(Bcf) |
(Bcf) |
(MMboe) |
|
Proved |
|||||||
Developed Producing(1) |
52 |
(26) |
26 |
470 |
470 |
367 |
|
Developed Non-Producing(1) |
1 |
(1) |
1 |
8 |
8 |
4 |
|
Undeveloped(1) |
88 |
(50) |
39 |
853 |
853 |
1,162 |
|
Total Proved(1) |
142 |
(76) |
65 |
1,330 |
1,330 |
1,534 |
|
Probable(1) |
90 |
(48) |
42 |
1,044 |
1,044 |
1,121 |
|
Total Proved plus Probable(1) |
232 |
(125) |
107 |
2,375 |
2,375 |
2,655 |
(1) Figures may not add due to rounding |
2023
NI 51-101 Light & |
NI 51-101 |
NI 51-101 |
Condensate |
Total Oil |
|
Reserves Category |
(MMbbl) |
(MMbbl) |
(MMbbl) |
(MMbbl) |
(MMbbl) |
Proved |
|||||
Developed Producing(1) |
1 |
93 |
120 |
26 |
239 |
Developed Non-Producing(1) |
- |
1 |
- |
- |
1 |
Undeveloped(1) |
1 |
356 |
553 |
53 |
964 |
Total Proved(1) |
2 |
450 |
673 |
80 |
1,205 |
Probable(1) |
3 |
168 |
680 |
53 |
905 |
Total Proved plus Probable(1) |
5 |
618 |
1,353 |
133 |
2,109 |
(1) Figures may not add due to rounding |
NI 51-101 Natural |
Less: |
Natural Gas |
NI 51-101 |
Natural |
Total |
||
Reserves Category |
(MMbbl) |
(MMbbl) |
(MMbbl) |
(Bcf) |
(Bcf) |
(MMboe) |
|
Proved |
|||||||
Developed Producing(1) |
48 |
(26) |
22 |
464 |
464 |
339 |
|
Developed Non-Producing(1) |
1 |
- |
- |
6 |
6 |
3 |
|
Undeveloped(1) |
88 |
(53) |
35 |
893 |
893 |
1,147 |
|
Total Proved(1) |
137 |
(80) |
57 |
1,362 |
1,362 |
1,489 |
|
Probable(1) |
88 |
(53) |
35 |
1,099 |
1,099 |
1,124 |
|
Total Proved plus Probable(1) |
225 |
(133) |
92 |
2,462 |
2,462 |
2,612 |
(1) Figures may not add due to rounding |
Forward-Looking Information
Certain statements contained in this press release constitute forward-looking information within the meaning of applicable securities laws. The forward-looking information in this press release is based on Strathcona's current internal expectations, estimates, projections, assumptions and beliefs. Such forward-looking information is not a guarantee of future performance and involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable as of the time of such information, but no assurance can be given that these factors, expectations and assumptions will prove to be correct, and such forward-looking information included in this press release should not be unduly relied upon.
The use of any of the words "expect", "target", "anticipate", "intend", "estimate", "objective", "ongoing", "may", "will", "project", "believe", "depends", "could" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the generality of the foregoing, this press release contains forward-looking information pertaining to the following: the Company's business strategy and future plans; expected impacts of tariffs on Strathcona's operations, including Local Sales, and the effectiveness of Strathcona's mitigation measures; expected operating strategy; expected production and capital expenditures in 2025; declaration, payment and any increases, in dividend payments; successful execution of the company's strategy and operational goals; expected recoveries in 2025 and delayed capital expenditures reducing our 2025 royalties; LDW development across the Tucker project; first oil at the new Meota Central processing facility; and the Company's future allocation of excess free cash flow.
All forward-looking information reflects Strathcona's beliefs and assumptions based on information available at the time the applicable forward-looking information is disclosed and in light of the Company's current expectations with respect to such things as: Strathcona's ability to generate sufficient cash flow to fund debt repayment and dividend payments; the success of Strathcona's operations and growth and expansion projects; expectations regarding production growth, future well production rates and reserve volumes; expectations regarding Strathcona's capital program; Strathcona's ability to declare and pay dividends; expectations regarding the impact of tariffs on Strathcona's operations and its ability to effectively mitigate the impact thereof; the outlook for general economic trends, industry trends, prevailing and future commodity prices, foreign exchange rates and interest rates; prevailing and future royalty regimes and tax laws; future well production rates and reserve volumes; fluctuations in energy prices based on worldwide demand and geopolitical events; the impact of inflation; the integrity and reliability of Strathcona's assets; decommissioning obligations; Strathcona's ability to comply with its financial covenants; and the governmental, regulatory and legal environment, including expectations regarding the current and future carbon tax regime and regulations and potential tariffs and other non-tariff trade barriers. Certain forward-looking information with respect to the Company's 2025 guidance assumes commodity prices and exchange rates of: US$70 / bbl WTI, US$13 / bbl WCS-WTI differential, 1.38 USD-CAD and C$3.00 / GJ AECO. Management believes that its assumptions and expectations reflected in the forward-looking information contained herein are reasonable based on the information available on the date such information is provided and the process used to prepare the information. However, it cannot assure readers that these expectations will prove to be correct.
The forward-looking information included in this press release is not a guarantee of future performance and involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information, including, without limitation: changes in commodity prices; changes in the demand for or supply of Strathcona's products; the continued impact, or further deterioration, in global economic and market conditions, including from inflation and/or certain geopolitical conflicts, such as the ongoing Russia/Ukraine conflict, the conflict in the Middle East, and other heightened geopolitical risks, including the imposition of tariffs or other trade barriers, and the ability of the Company to carry on operations as contemplated in light of the foregoing; determinations by the Organization of the Petroleum Exporting Countries and other countries as to production levels; unanticipated operating results or production declines; changes in tax or environmental laws, climate change, royalty rates or other regulatory matters; changes in Strathcona's development plans or by third party operators of Strathcona's properties; failure to achieve anticipated results of its operations; competition from other producers; inability to retain drilling rigs and other services; failure to realize the anticipated benefits of the Company's acquisitions; incorrect assessment of the value of acquisitions; delays resulting from or inability to obtain required regulatory approvals; increased debt levels or debt service requirements; inflation; changes in foreign exchange rates; inaccurate estimation of Strathcona's oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets or other sources of capital; increased costs; a lack of adequate insurance coverage; the impact of competitors; and the other factors discussed under the "Risk Factors" section in Strathcona's Management's Discussion & Analysis and Annual Information Form, each for the year ended December 31, 2024, and from time to time in Strathcona's public disclosure documents, which are available at www.sedarplus.ca.
Declaration of dividends is at the sole discretion of the board of directors of Strathcona and will continue to be evaluated on an ongoing basis. There are risks that may result in Strathcona changing, suspending or discontinuing its quarterly dividends, including changes to its free cash flow, operating results, capital requirements, financial position, debt levels, market conditions or corporate strategy and the need to comply with requirements under its credit agreement and applicable laws respecting the declaration and payment of dividends. There are no assurances as to the continuing declaration and payment of future dividends or the amount or timing of any such dividends.
Management approved the capital budget and production guidance contained herein as of the date of this press release. The purpose of the capital budget and production guidance is to assist readers in understanding Strathcona's expected and targeted financial position and performance, and this information may not be appropriate for other purposes. The foregoing risks should not be construed as exhaustive. The forward-looking information contained in this press release speaks only as of the date of this press release and Strathcona does not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws. Any forward-looking information contained herein is expressly qualified by this cautionary statement.
SOURCE Strathcona Resources Ltd.
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