TOURMALINE DELIVERS RECORD PRODUCTION, INCREASES 2P RESERVES TO 5.5 BILLION BOE, ANNOUNCES A 43% INCREASE TO THE BASE DIVIDEND AND DECLARES A SPECIAL DIVIDEND
CALGARY, AB, March 5, 2025 /CNW/ - Tourmaline Oil Corp. (TSX: TOU) ("Tourmaline" or the "Company") is pleased to release financial and operating results for the full-year and fourth quarter of 2024.
HIGHLIGHTS
- Full-year 2024 cash flow(1) ("CF") was $3.2 billion ($8.93 per diluted share(2)). Fourth quarter 2024 CF was $850.3 million ($2.27 per diluted share).
- 2025 forecast free cash flow(3) ("FCF") of $1.4 billion ($3.62 per diluted share(4)) based on current strip pricing(5), up from previous guidance of $1.1 billion(6). At current strip pricing, the Company forecasts it will generate 2025 CF of $4.3 billion ($11.53 per diluted share).
- Full-year 2024 net earnings were $1.3 billion ($3.51 per diluted share).
- The Company announces a quarterly base dividend increase of 43% to $0.50 per share effective Q1 2025 and a special dividend of $0.35/share. Tourmaline believes that with continued improvements in realized pricing, the Company is well positioned to increase returns to shareholders in 2025 relative to 2024, in addition to pursuing a growth capital budget.
- First quarter 2025 production range of 630,000-635,000 boepd is currently anticipated.
- Proved developed producing ("PDP") reserves(7) increased 29% in 2024 after accounting for production.
- Proved plus probable ("2P") reserves increased 14% to 5.5 billion boe in 2024 after accounting for production.
- Exit 2024 net debt(8) was $1.7 billion (0.4 times 2025 forecast cash flow). The Company intends to deleverage throughout 2025 and remains committed to a long-term net debt target of $1.5 billion (which is approximately 0.30 to 0.35 times 2025 forecast net debt to cash flow).
PRODUCTION UPDATE
- Fourth quarter 2024 average production was 605,413 boepd, up 9% from Q4 2023. Full-year 2024 average production of 579,173 boepd was up 11% over full-year 2023 average production of 520,366 boepd.
- 2024 average liquids production (oil, condensate, NGLs) of 138,584 bbls/d was up 17% over 2023 liquids production of 118,808 bbls/d.
- In addition to being Canada's largest and most active natural gas producer, Tourmaline is the largest NGL producer and the third largest condensate producer in Canada(9). Condensate and NGL production volumes are expected to increase significantly over the next 5 years with the Company's North Montney, West Doe-Groundbirch, South Montney, and North Deep Basin growth projects. These projects are not fully captured in the Company's current five-year EP plan but will be as the timelines are solidified.
- The 2025 forecast production range of 635,000 to 665,000 boepd remains unchanged; the Company expects to finalize the second half 2025 EP capital program during the second quarter.
- First quarter 2025 production of 630,000 to 635,000 boepd is currently anticipated. The Company has approximately 51 wells to bring on-production in March which is expected to result in a first quarter exit in excess of 640,000 boepd.
FINANCIAL HIGHLIGHTS
- Improving strip prices have increased full-year forecast 2025 CF to $4.3 billion from previous guidance of $4.1 billion and full-year forecast 2025 FCF to $1.4 billion, from previous guidance of $1.1 billion, as disclosed in November 2024.
- Full-year 2024 CF was $3.2 billion ($8.93 per diluted share) and full-year 2024 FCF was $1.0 billion ($2.75 per diluted share).
- Fourth quarter 2024 CF was $850.3 million ($2.27 per diluted share on Q4 2024 average production of 605,413 boepd). Q4 2024 FCF was $96.7 million ($0.26 per diluted share).
- Full-year 2024 earnings were $1.3 billion ($3.51 per diluted share).
- Given the strong growth in the base business over the past three years, through a combination of high margin, organic growth and accretive acquisitions, Tourmaline's Board of Directors has elected to increase the base quarterly dividend from $0.35 to $0.50 per share, a 43% increase, effective Q1 2025.
- Tourmaline's Board of Directors has also declared a special dividend of $0.35 per share to be paid on March 25, 2025 to shareholders of record on March 13, 2025. Tourmaline intends to pay special dividends in all four quarters of 2025, inclusive of this Q1 2025 special dividend. Tourmaline believes that with continued improvements in realized pricing, the Company is well positioned to increase returns to shareholders in 2025 relative to 2024, in addition to pursuing a growth capital budget.
- Tourmaline paid $3.32 per share in combined base and special dividends in 2024, a 5.3% trailing yield based on an average 2024 share price of $62.37.
- Full-year 2024 capital expenditures were $1.9 billion, including Q4 2024 capital expenditures of $460.2 million.
- Exit 2024 net debt was $1.7 billion, approaching the Company's long-term net debt target of $1.5 billion (which is approximately 0.30 to 0.35 times 2025 forecast net debt to cash flow). This does not include the value of the Company's Topaz shares, which was $911.5 million based on a December 31, 2024 closing Topaz share price of $27.85. Maintaining balance sheet strength puts the Company in a strong position to deal with any new macro challenges and to take advantage of opportunities that might arise.
2024 RESERVES
- Year-end 2024 PDP reserves of 1.35 billion boe were up 29% after accounting for 2024 annual production of 212 million boe. Total proved ("TP") reserves of 2.91 billion boe were up 19% after accounting for 2024 production. 2P reserves of 5.50 billion boe were up 14% after accounting for 2024 production.
- For the second consecutive year, the EP program had an increased emphasis on conversions to PDP rather than 2P reserve growth compared to previous years.
- After 16 years of operations, Tourmaline now has 24.84 TCF of economic 2P natural gas reserves and 1.36 billion barrels of 2P oil, condensate and NGL reserves, all of which are pipeline-connected to markets across North America. At year-end 2024, 84% of the current estimated drilling inventory was not booked in the 2024 year-end reserve report.
- Year-end 2024 oil, condensate, and NGL 2P reserves of 1.36 billion barrels represent the second largest conventional liquids reserve base in Canada, based on public disclosure.
- Tourmaline has only booked 3,972 gross locations of a total drilling inventory of 25,462 gross locations (16% of the overall inventory) to achieve year-end 2024 2P reserves of 5.50 billion boe.
- Tourmaline replaced 330% of its 2024 annual production of 212.0 million boe with 2P additions of 698.8 million boe, including 2024 production.
- Tourmaline's 2024 PDP finding and development ("F&D") costs were $8.45 per boe including changes in future development capital ("FDC"), yielding a PDP reserve recycle ratio(10)(11) of 1.8 times.
- TP FD&A costs in 2024 were $9.44 per boe, including changes in FDCs. 3-year TP FD&A costs are $10.23 per boe, including changes in FDC.
- 2P FD&A costs in 2024 were $7.28 per boe, including changes in FDC, yielding a 2P recycle ratio of 2.1 times. 3-year 2P FD&A costs were $9.03 per boe, including changes in FDC. The 2024 2P FD&A costs continue to reflect the increased focus on conversions to PDP. Approximately 81% of the 256.5 net wells rig released in 2024 were conversions from undeveloped reserves to developed reserves. Delays in acquiring new surface disturbance permits in HV1 areas in NEBC limited the ability to drill delineation pads and book 2P reserves. The Company expects this situation to improve in 2025.
- Tourmaline's 2P reserve value (before taxes) equates to $114.20 per diluted share (after tax reserve value of $87.61 per diluted share) using the January 1, 2025 engineering price deck at a 10% discount rate. TP reserve value (before tax) is $75.17 per diluted share and $59.18 per diluted share (after tax). PDP reserve value is $44.42 per diluted share (before tax) and $37.12 per diluted share (after tax).
2025 CAPITAL PROGRAM
- The full-year 2025 EP capital budget range remains unchanged at $2.60 to $2.85 billion. The Company expects steadily improving natural gas prices in 2025. Should the price recovery materialize later in the year, the capital program will be sequenced accordingly.
- Facility and pipeline expenditures of $300.0 million remain in the total 2025 EP capital budget, including the ongoing NEBC North Montney Phase 1 infrastructure buildout, electrification pre-builds for the 2026-2027 West Doe and Groundbirch gas plant projects, and certain long-lead time facility pre-orders.
- The Company expects to finalize the sequencing of the entire future NEBC infrastructure buildout during 2025 (expected to include up to four new gas processing facilities in aggregate). The Groundbirch development is now expected to consist of two separate 200 mmcfpd deep-cut plants, to be installed in the 2027 to 2029 time frame.
MARKETING UPDATE
- Tourmaline's average realized natural gas price in 2024 was CAD $3.38/mcf, CAD $1.90/mcf above the average 2024 AECO 5A index price of CAD $1.48/mcf. The Company's marketing diversification portfolio and strategic hedging program allow Tourmaline to consistently outperform local hub pricing on a sustained basis.
- Tourmaline expects to exit 2025 with 1.3 bcfpd in exports to targeted markets including 904 mmcfpd delivered to the US Gulf, JKM, TTF, Western US and Pacific Northwest premium markets. This is inclusive of an additional 95 mmcfpd of ANR service to the US Gulf, executed in Q1 2025.
- Tourmaline has an average of 1.06 bcfpd hedged in 2025 at a weighted average fixed price of $5.07/mcf. This includes 66 mmcfpd hedged at a weighted average price of CAD $20.82/mcf in international markets.
- Tourmaline remains encouraged by the very strong, demand driven outlook for North American natural gas prices which have improved in the majority of the sales hubs accessed by the Company over Q4 2024. Western Canadian gas prices have lagged this recovery despite winter (November-March) natural gas storage withdrawals averaging 1.43 bcfpd(12) vs 0.736 bcfpd last winter. Tourmaline will continue to monitor the multiple local natural gas demand catalysts anticipated in 2025, including the startup of LNG Canada. The Company will manage unhedged, non-export (local) volumes accordingly, and in the event of very weak spring/summer 2025 prices, the Company will optimize the pace of well stimulation and production startup activities to shape the production profile to the highest cash flow outcome.
EP UPDATE
- Tourmaline drilled 286 gross wells in 2024 and led the Canadian industry with a total of 1,425,407 metres drilled during the year.
- In 2024, Tourmaline delivered its best overall well performance in the past five years in the Alberta Deep Basin complex. This outperformance has been across the full suite of Deep Basin assets, from Kakwa-Smoky Wilrich/Falher in the north to Strachan-Garrington Glauconite in the south.
- The Company is currently planning to drill and complete a total of 365 net wells in 2025 including 170 wells in the Alberta Deep Basin, 160 wells in the NEBC gas condensate complex, and 35 wells in the Peace River High.
- As of January 1, 2025, the ongoing new zone/new pool exploration program has added 2.04 TCF of 2P reserves and 1,068 Tier1/Tier 2 drilling locations since inception of the program. There are several potential high impact exploration wells in the 2025 program.
- Tourmaline continues to make select midstream investments to reduce costs and improve realized margins. In the Gundy, BC complex, infrastructure investments have reduced midstream related costs(13) by approximately 20% since 2021, and since acquiring the Aitken, BC complex in 2021, midstream related costs have been reduced by approximately 45%. We expect similar reductions to be achieved on the Crew Energy Inc. assets acquired in 2024 through a combination of growth and the execution of a strategy similar to our Aiken/Gundy assets.
ENVIRONMENTAL PERFORMANCE IMPROVEMENT
- Tourmaline's cleantech engineering team continues to develop and implement new proprietary emission reduction technologies, execute expanded water management initiatives, explore industry-leading methane mitigation technologies, and manage related third-party environmental research.
- Since embarking on the diesel displacement initiative for drilling rigs and frac spreads in June 2017, the Company has displaced 189 million litres of diesel, providing an emissions reduction of 124,536 tonnes of carbon dioxide and saving approximately $185 million (including the cost of the replacement natural gas). Drilling and completions operations powered using natural gas result in lower emissions of carbon dioxide, nitrogen oxides, sulphur dioxide and particulate matter compared to traditional diesel-powered drilling and completions operations.
- The compressed natural gas in long-haul trucking joint development with Clean Energy Fuels Corp., announced in April 2023, continues to progress with stations operational in Calgary, Edmonton, and Grande Prairie. An additional four stations are planned in 2025. This initiative is expected to reduce costs and emissions in the long-haul trucking industry and build Canadian natural gas demand.
- Tourmaline completed construction of two new water recycling facilities in 2024 and is planning to build two additional storage and recycling facilities in 2025.
DIVIDEND
- The continued profitable growth in the Company's base business has allowed for a 43% increase in the quarterly base dividend to $0.50 per share. The Board of Directors has declared the quarterly base dividend of $0.50 per share, which is payable on March 31, 2025 to shareholders of record at the close of business on March 14, 2025.
- Given the significant increase in the quarterly base dividend, the Company will continue with a more modest quarterly special dividend program and intends to pay a special dividend in all four quarters of 2025. The Board of Directors of Tourmaline has declared a special dividend of $0.35 per share to be paid on March 25, 2025 to shareholders of record at the close of business on March 13, 2025. Both the special dividend and the quarterly base dividend are designated as eligible dividends for Canadian income tax purposes.
____________________ |
|
(1) |
This news release contains certain specified financial measures consisting of non-GAAP financial measures, non-GAAP ratios, capital management measures |
(2) |
"Cash flow per diluted share" is a non-GAAP financial ratio. Cash flow, a non-GAAP financial measure, is used as a component of the non-GAAP financial |
(3) |
"Free cash flow" is a non-GAAP financial measure defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is |
(4) |
Calculated as forecast 2025 FCF divided by diluted share count (based on 376 million diluted Common Shares). |
(5) |
Based on oil and gas commodity strip pricing at February 14, 2025. |
(6) |
As forecasted in the Company's November 6, 2024 news release. |
(7) |
Reserves are "Company gross reserves", which are defined as the working interest share of reserves prior to the deduction of interest owned by others |
(8) |
"Net debt" is a capital management measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(9) |
Based on public disclosure. |
(10) |
Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. The recycle ratio is calculated by |
(11) |
Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(12) |
As of February 20, 2025. |
(13) |
Midstream related costs include liquids transportation fees, gathering and processing fees, as well as fractionation and loading fees. |
CORPORATE SUMMARY – DECEMBER 31, 2024
Three Months Ended December 31, |
Year Ended December 31, |
||||||
2024 |
2023 |
Change |
2024 |
2023 |
Change |
||
OPERATIONS |
|||||||
Production |
|||||||
Natural gas (mcf/d) |
2,799,365 |
2,543,185 |
10 % |
2,643,532 |
2,409,349 |
10 % |
|
Crude oil, condensate and NGL (bbl/d) |
138,852 |
133,093 |
4 % |
138,584 |
118,808 |
17 % |
|
Oil equivalent (boe/d) |
605,413 |
556,957 |
9 % |
579,173 |
520,366 |
11 % |
|
Product prices(1) |
|||||||
Natural gas ($/mcf) |
$ 3.48 |
$ 4.25 |
(18) % |
$ 3.38 |
$ 4.83 |
(30) % |
|
Crude oil, condensate and NGL ($/bbl) |
$ 56.99 |
$ 54.29 |
5 % |
$ 54.78 |
$ 56.79 |
(4) % |
|
Operating expenses ($/boe) (2) |
$ 4.52 |
$ 4.22 |
7 % |
$ 4.75 |
$ 4.51 |
5 % |
|
Transportation costs ($/boe) (3) |
$ 4.97 |
$ 5.41 |
(8) % |
$ 5.11 |
$ 5.27 |
(3) % |
|
Operating netback ($/boe) (4) |
$ 17.40 |
$ 19.80 |
(12) % |
$ 16.26 |
$ 22.17 |
(27) % |
|
Cash general and |
$ 0.82 |
$ 0.58 |
41 % |
$ 0.77 |
$ 0.68 |
13 % |
|
FINANCIAL |
|||||||
Total revenue from commodity sales and realized gains |
1,623,819 |
1,658,883 |
(2) % |
6,044,773 |
6,706,997 |
(10) % |
|
Royalties |
125,699 |
150,466 |
(16) % |
509,252 |
638,419 |
(20) % |
|
Cash flow |
850,330 |
918,008 |
(7) % |
3,218,491 |
3,707,683 |
(13) % |
|
Cash flow per share (diluted) |
$ 2.27 |
$ 2.62 |
(13) % |
$ 8.93 |
$ 10.73 |
(17) % |
|
Net earnings |
407,445 |
700,202 |
(42) % |
1,264,109 |
1,735,880 |
(27) % |
|
Net earnings per share (diluted) |
$ 1.09 |
$ 2.00 |
(46) % |
$ 3.51 |
$ 5.03 |
(30) % |
|
Capital expenditures (net of dispositions)(6) |
460,193 |
635,987 |
(28) % |
1,901,461 |
2,073,249 |
(8) % |
|
Weighted average shares outstanding (diluted) |
360,249,193 |
345,383,038 |
4 % |
||||
Net debt |
(1,702,732) |
(1,779,732) |
(4) % |
||||
PROVED + |
|||||||
Natural gas (bcf) |
24,837.0 |
22,719.0 |
9 % |
||||
Crude oil (mbbls) |
119,331 |
130,423 |
(9) % |
||||
Natural gas liquids (mbbls) |
1,236,385 |
1,091,453 |
13 % |
||||
Mboe |
5,495,212 |
5,008,374 |
10 % |
||||
Notes: |
|
(1) |
Product prices include realized gains and losses on risk management activities and financial instrument contracts. |
(2) |
Supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(3) |
Supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(4) |
Excluding interest and financing charges. Non-GAAP financial measure and non-GAAP ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(5) |
Non-GAAP financial measure and non-GAAP ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(6) |
Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(7) |
Reserves are "Company gross reserves", which are defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. |
2024 RESERVE SUMMARY
The following tables summarize the Company's gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.
Reserves and Future Net Revenue Data (Forecast Prices and Costs)
Summary of Crude Oil, Natural Gas and Natural Gas Liquids Reserves and
Net Present Values of Future Net Revenue
as of December 31, 2024
Forecast Prices and Costs(1)
Light & Medium Crude |
Conventional Natural |
Shale Natural Gas(2) |
Natural Gas Liquids |
Total Oil Equivalent |
||||||
Reserves Category |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company Gross (Mboe) |
Company Net (Mboe) |
Proved Developed Producing..... |
19,424 |
15,523 |
2,947,051 |
2,635,837 |
3,183,306 |
2,701,494 |
304,203 |
241,859 |
1,345,354 |
1,146,938 |
Proved Developed Non- |
1,249 |
950 |
68,669 |
60,791 |
166,022 |
145,573 |
11,724 |
8,963 |
52,088 |
44,307 |
Proved Undeveloped................. |
45,302 |
34,380 |
2,780,509 |
2,471,795 |
4,111,107 |
3,560,197 |
320,826 |
250,881 |
1,514,731 |
1,290,593 |
Total |
65,976 |
50,853 |
5,796,229 |
5,168,424 |
7,460,434 |
6,407,264 |
636,753 |
501,704 |
2,912,173 |
2,481,838 |
Total Probable.......................... |
53,356 |
40,852 |
3,876,118 |
3,382,789 |
7,704,191 |
6,451,295 |
599,632 |
439,860 |
2,583,039 |
2,119,726 |
Total Proved Plus Probable........ |
119,331 |
91,704 |
9,672,347 |
8,551,213 |
15,164,625 |
12,858,558 |
1,236,385 |
941,565 |
5,495,212 |
4,601,564 |
Reserves Category |
Net Present Values of Future Net Revenue ($000s) |
|||||||||||||
Before Income Taxes Discounted at |
After Income Taxes Discounted at(3) |
Unit Value Before |
||||||||||||
0 |
5 |
8 |
10 |
15 |
20 |
0 |
5 |
8 |
10 |
15 |
20 |
($/Boe) |
($/Mcfe) |
|
Proved Developed |
23,847,083 |
19,192,472 |
17,133,713 |
16,001,951 |
13,787,544 |
12,179,465 |
19,525,133 |
15,917,317 |
14,279,103 |
13,372,323 |
11,587,969 |
10,284,504 |
13.95 |
2.33 |
Proved Developed Non- |
1,515,535 |
1,168,266 |
1,019,224 |
936,756 |
772,991 |
651,662 |
1,130,804 |
870,508 |
758,410 |
696,339 |
573,012 |
481,593 |
21.14 |
3.52 |
Proved Undeveloped |
24,460,933 |
15,310,637 |
11,890,699 |
10,142,896 |
6,997,510 |
4,961,818 |
18,250,512 |
11,230,701 |
8,597,068 |
7,251,456 |
4,834,661 |
3,278,260 |
7.86 |
1.31 |
Total Proved |
49,823,551 |
35,671,375 |
30,043,636 |
27,081,603 |
21,558,044 |
17,792,945 |
38,906,449 |
28,018,526 |
23,634,580 |
21,320,118 |
16,995,642 |
14,044,356 |
10.91 |
1.82 |
Total Probable |
48,555,806 |
24,196,600 |
17,211,705 |
14,059,054 |
9,061,175 |
6,269,667 |
36,153,792 |
17,863,534 |
12,609,150 |
10,240,810 |
6,498,053 |
4,421,126 |
6.63 |
1.11 |
Total Proved Plus |
98,379,358 |
59,867,975 |
47,255,341 |
41,140,657 |
30,619,219 |
24,062,611 |
75,060,241 |
45,882,060 |
36,243,731 |
31,560,928 |
23,493,696 |
18,465,482 |
8.94 |
1.49 |
Notes: |
|
(1) |
Numbers may not add due to rounding. |
(2) |
Shale Natural Gas is required to be presented separately from Conventional Natural Gas as its own product type pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). While the Tourmaline Montney reserves do not strictly fit the definition of "shale gas" as defined in NI 51-101 because the natural gas is not "primarily adsorbed" as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure. |
(3) |
The after-tax net present value of the Company's oil and gas reserves reflects Company-level tax pools. The Company's financial statements and management's discussion and analysis should be consulted for information at the Company level. |
Total Future Net Revenue ($000s)
(Undiscounted)
as of December 31, 2024
Forecast Prices and Costs(1)
Reserves Category |
Revenue |
Royalties |
Operating |
Capital |
Abandonment |
Future Net |
Income |
Future Net |
Proved Developed |
44,649,154 |
6,254,803 |
12,218,339 |
- |
2,328,929 |
23,847,083 |
4,321,950 |
19,525,133 |
Proved Developed Non- |
2,349,374 |
348,600 |
376,490 |
74,860 |
33,889 |
1,515,535 |
384,731 |
1,130,804 |
Proved |
54,264,254 |
8,851,271 |
10,473,280 |
9,914,196 |
564,574 |
24,460,933 |
6,210,421 |
18,250,512 |
Total |
101,262,782 |
15,454,674 |
23,068,109 |
9,989,055 |
2,927,392 |
49,823,551 |
10,917,102 |
38,906,449 |
Total |
98,665,451 |
19,632,960 |
21,198,138 |
8,432,653 |
845,892 |
48,555,806 |
12,402,014 |
36,153,792 |
Total Proved Plus |
199,928,233 |
35,087,635 |
44,266,247 |
18,421,708 |
3,773,285 |
98,379,358 |
23,319,116 |
75,060,241 |
Notes: |
|
(1) |
Numbers may not add due to rounding. |
(2) |
Abandonment and Reclamation Costs includes all active and inactive assets, with or without associated reserves, inclusive of all wells (existing and undrilled), facilities and pipelines. |
(3) |
The after-tax net present value of the Company's oil and gas reserves reflects Company-level tax pools. The Company's financial statements and management's discussion and analysis should be consulted for information at the Company level. |
Summary of Pricing and Inflation Rate Assumptions
Forecast Prices and Costs (1)
Year |
Inflation(2) % |
Crude Oil and Natural Gas Liquids Pricing |
||||||||
CAD/USD |
NYMEX WTI Near |
MSW, Light |
Alberta Natural Gas Liquids |
|||||||
Constant |
Then |
Spec |
Edmonton |
Edmonton |
Edmonton |
|||||
2025.............. |
0.0 |
0.712 |
71.58 |
71.58 |
94.79 |
7.54 |
33.56 |
51.15 |
100.14 |
|
2026.............. |
2.0 |
0.728 |
73.02 |
74.48 |
97.04 |
10.76 |
32.78 |
49.98 |
100.72 |
|
2027.............. |
2.0 |
0.743 |
72.87 |
75.81 |
97.37 |
11.32 |
32.81 |
50.16 |
100.24 |
|
2028.............. |
2.0 |
0.743 |
73.18 |
77.66 |
99.80 |
12.02 |
33.63 |
51.41 |
102.73 |
|
2029.............. |
2.0 |
0.743 |
73.18 |
79.22 |
101.79 |
12.26 |
34.30 |
52.44 |
104.79 |
|
2030.............. |
2.0 |
0.743 |
73.18 |
80.80 |
103.83 |
12.51 |
34.99 |
53.49 |
106.86 |
|
2031.............. |
2.0 |
0.743 |
73.18 |
82.42 |
105.91 |
12.77 |
35.69 |
54.56 |
109.00 |
|
2032.............. |
2.0 |
0.743 |
73.18 |
84.06 |
108.02 |
13.03 |
36.40 |
55.65 |
111.19 |
|
2033.............. |
2.0 |
0.743 |
73.18 |
85.75 |
110.19 |
13.30 |
37.13 |
56.76 |
113.41 |
|
2034.............. |
2.0 |
0.743 |
73.18 |
87.46 |
112.39 |
13.57 |
37.87 |
57.90 |
115.69 |
|
2035.............. |
2.0 |
0.743 |
73.18 |
89.21 |
114.64 |
13.84 |
38.63 |
59.05 |
118.01 |
|
2036.............. |
2.0 |
0.743 |
73.18 |
90.99 |
116.93 |
14.12 |
39.40 |
60.24 |
120.37 |
|
2037.............. |
2.0 |
0.743 |
73.18 |
92.82 |
119.27 |
14.40 |
40.19 |
61.44 |
122.77 |
|
2038.............. |
2.0 |
0.743 |
73.18 |
94.67 |
121.65 |
14.69 |
41.00 |
62.67 |
125.23 |
|
2039.............. |
2.0 |
0.743 |
73.18 |
96.57 |
124.09 |
14.98 |
41.82 |
63.92 |
127.73 |
|
2040+............ |
2.0 |
0.743 |
73.18 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
|
Year |
Natural Gas and Sulphur Pricing |
||||||||||||
NYMEX Henry Hub |
Midwest |
AECO/NIT Then Current |
Alberta Plant Gate |
Huntingdon/ |
British Columbia |
Dutch TTF |
JKM |
||||||
Spot |
ARP $Cdn/ |
Westcoast |
Spot Plant |
||||||||||
Constant |
Then Current |
Dawn Price @ Ontario Then Current |
Constant |
Then Current |
|||||||||
2025............... |
3.31 |
3.31 |
3.05 |
2.36 |
3.01 |
2.15 |
2.15 |
2.15 |
3.01 |
2.15 |
1.82 |
12.77 |
13.47 |
2026............... |
3.65 |
3.73 |
3.53 |
3.33 |
3.49 |
3.05 |
3.11 |
3.11 |
3.79 |
3.15 |
2.81 |
11.18 |
11.73 |
2027............... |
3.70 |
3.85 |
3.66 |
3.48 |
3.61 |
3.13 |
3.26 |
3.26 |
3.94 |
3.29 |
2.96 |
11.05 |
11.50 |
2028............... |
3.71 |
3.93 |
3.73 |
3.69 |
3.69 |
3.26 |
3.46 |
3.46 |
4.02 |
3.50 |
3.16 |
11.55 |
12.28 |
2029............... |
3.70 |
4.01 |
3.82 |
3.76 |
3.77 |
3.26 |
3.53 |
3.53 |
4.10 |
3.57 |
3.23 |
11.78 |
12.51 |
2030............... |
3.70 |
4.09 |
3.89 |
3.83 |
3.85 |
3.26 |
3.60 |
3.60 |
4.18 |
3.64 |
3.30 |
12.02 |
12.76 |
2031............... |
3.70 |
4.17 |
3.97 |
3.91 |
3.93 |
3.26 |
3.68 |
3.68 |
4.26 |
3.71 |
3.37 |
12.26 |
13.00 |
2032............... |
3.70 |
4.26 |
4.05 |
3.99 |
4.02 |
3.27 |
3.75 |
3.75 |
4.35 |
3.79 |
3.45 |
12.50 |
13.26 |
2033............... |
3.70 |
4.34 |
4.13 |
4.07 |
4.10 |
3.27 |
3.83 |
3.83 |
4.44 |
3.87 |
3.52 |
12.75 |
13.36 |
2034............... |
3.70 |
4.43 |
4.21 |
4.15 |
4.18 |
3.27 |
3.91 |
3.91 |
4.53 |
3.94 |
3.60 |
13.00 |
13.63 |
2035............... |
3.70 |
4.52 |
4.30 |
4.24 |
4.27 |
3.27 |
3.99 |
3.99 |
4.62 |
4.02 |
3.67 |
13.27 |
14.35 |
2036............... |
3.70 |
4.61 |
4.39 |
4.32 |
4.36 |
3.27 |
4.07 |
4.07 |
4.71 |
4.10 |
3.74 |
13.53 |
14.62 |
2037............... |
3.71 |
4.70 |
4.48 |
4.41 |
4.45 |
3.27 |
4.15 |
4.15 |
4.81 |
4.19 |
3.82 |
13.80 |
14.91 |
2038............... |
3.70 |
4.79 |
4.56 |
4.49 |
4.54 |
3.27 |
4.23 |
4.23 |
4.91 |
4.27 |
3.89 |
14.08 |
15.20 |
2039............... |
3.70 |
4.89 |
4.65 |
4.58 |
4.63 |
3.27 |
4.32 |
4.32 |
5.00 |
4.35 |
3.97 |
14.36 |
15.50 |
2040+............. |
3.70 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
3.27 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
Notes: |
|
(1) |
Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the GLJ Reserve Report and Deloitte LLP in the Deloitte Reserve Report, were an equal weighted average of the December 31, 2024 price forecasts published by GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2025 and Sproule Associates Ltd. as at December 31, 2024 (each of which is available on their respective websites at www.gljpc.com, www.mcdan.com and www.sproule.com). GLJ assigns a value to the Company's existing physical diversification contracts for natural gas at consuming market regions including US Gulf Coast, US Midwest, US West and Canadian East, and international markets based on forecasted differentials to NYMEX Henry Hub as per the aforementioned consultant average price forecast, contracted volumes and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2024. |
(2) |
Inflation rates used for forecasting prices and costs, with the exception of capital expenditures, which have been forecasted to have nil inflation until 2027, at which time the inflation profile is as published in these tables. |
RESERVES PERFORMANCE RATIOS
The following tables highlight Tourmaline's reserves, F&D and FD&A costs as well as the associated recycle ratios.
Reserves, Capital Expenditures and Cash Flow(1)
As at, and for the Year ended December 31, |
2024 |
2023 |
2022 |
Reserves (Mboe) |
|||
Proved Producing |
1,345,354 |
1,204,499 |
1,001,175 |
Total Proved |
2,912,173 |
2,614,619 |
2,321,959 |
Proved Plus Probable |
5,495,212 |
5,008,374 |
4,500,272 |
Capital Expenditures ($ millions) |
|||
Exploration and Development(2) |
2,226 |
2,023 |
1,677 |
Net Property Acquisitions (Dispositions)(3) |
(325) |
51 |
202 |
Net Corporate Acquisitions (Dispositions)(3) |
1,709 |
1,442 |
188 |
Total(4) |
3,610 |
3,516 |
2,067 |
Cash Flow ($/boe) |
|||
Cash Flow |
15.18 |
19.52 |
26.72 |
Cash Flow - Three Year Average |
20.20 |
21.58 |
19.67 |
Notes: |
|
(1) |
Cash flow is defined as cash provided by operations adjusted for the change in non-cash operating working capital (deficit) and current income taxes. See "Non-GAAP and Other Financial Measures" below and in the Annual MD&A for further discussion. |
(2) |
Includes capitalized G&A of $45 million, $43 million and $47 million for 2024, 2023 and 2022, respectively. |
(3) |
Includes purchase price (cash and/or common shares) plus net debt, if applicable. |
(4) |
Represents the capital expenditures used for purposes of F&D and FD&A calculations. |
Finding and Development Costs
Finding and Development Costs, Excluding FDC |
2024 |
2023 |
2022 |
3-Ye ar Avg. |
Total Proved |
||||
Reserve Additions (MMboe) |
232.8 |
209.3 |
284.6 |
|
F&D Costs ($/boe) |
9.56 |
9.66 |
5.89 |
8.15 |
F&D Recycle Ratio(1) |
1.6 |
2.0 |
4.5 |
2.5 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
167.1 |
230.7 |
387.0 |
|
F&D Costs ($/boe) |
13.32 |
8.77 |
4.33 |
7.55 |
F&D Recycle Ratio(1) |
1.1 |
2.2 |
6.2 |
2.7 |
Finding and Development Costs, Including FDC |
2024 |
2023 |
2022 |
3-Year Avg. |
Total Proved |
||||
Change in FDC ($ millions) |
(161.5) |
231.8 |
1,202 |
|
Reserve Additions (MMboe) |
232.8 |
209.3 |
284.6 |
|
F&D Costs ($/boe) |
8.87 |
10.77 |
10.12 |
9.91 |
F&D Recycle Ratio(1) |
1.7 |
1.8 |
2.6 |
2.0 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
(422.0) |
912.9 |
2,380.7 |
|
Reserve Additions (MMboe) |
167.1 |
230.7 |
387.0 |
|
F&D Costs ($/boe) |
10.79 |
12.72 |
10.49 |
11.21 |
F&D Recycle Ratio(1) |
1.4 |
1.5 |
2.5 |
1.8 |
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, Excluding FDC |
2024 |
2023 |
2022 |
3-Year Avg. |
Total Proved |
||||
Reserve Additions (MMboe) |
509.5 |
482.6 |
316.9 |
|
FD&A Costs ($/boe) |
7.09 |
7.28 |
6.52 |
7.02 |
FD&A Recycle Ratio(1) |
2.1 |
2.7 |
4.1 |
2.0 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
698.8 |
698.0 |
440.1 |
|
FD&A Costs ($/boe) |
5.17 |
5.04 |
4.70 |
5.00 |
FD&A Recycle Ratio(1) |
2.9 |
3.9 |
5.7 |
4.0 |
Finding, Development and Acquisition Costs, Including FDC |
2024 |
2023 |
2022 |
3-Year Avg. |
Total Proved |
||||
Change in FDC ($ millions) |
1,201.6 |
1,654.1 |
1,337.3 |
|
Reserve Additions (MMboe) |
509.5 |
482.6 |
316.9 |
|
FD&A Costs ($/boe) |
9.44 |
10.71 |
10.74 |
10.23 |
FD&A Recycle Ratio(1) |
1.6 |
1.8 |
2.5 |
2.0 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
1,473.8 |
3,326.1 |
2,593.0 |
|
Reserve Additions (MMboe) |
698.8 |
698.0 |
440.1 |
|
FD&A Costs ($/boe) |
7.28 |
9.80 |
10.59 |
9.03 |
FD&A Recycle Ratio(1) |
2.1 |
2.0 |
2.5 |
2.2 |
Note: |
|
(1) |
The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year. |
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m.) ET
Tourmaline will host a conference call tomorrow, March 6, 2025 starting at 9:00 a.m. MT (11:00 a.m. ET).
To participate without operator assistance, you may register and enter your phone number at https://emportal.ink/4hl79GK to receive an instant automated call back.
To participate using an operator, please dial 1-888-510-2154 (toll-free in North America), or 1-437-900-0527 (international dial-in), a few minutes prior to the conference call.
REPLAY DETAILS
If you are unable to dial into the live conference call on March 6, 2025, a replay will be available by dialing 1-888-660-6345 (international 1-289-819-1450), referencing Encore Replay Code 65397. The recording will expire on March 20, 2025.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
FORWARD-LOOKING INFORMATION
This news release contains forward-looking information and statements (collectively, "forward-looking information") within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "on track", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this news release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results, business opportunities and shareholder return plan, including the following: the future declaration and payment of base and special dividends and the timing and amount thereof which assumes, among other things, the availability of free cash flow to fund such dividends; anticipated 2025 cash flow and free cash flow; long-term net debt targets and the Company's expectation that it will deleverage throughout 2025; the Company's expectation that it will pay special dividends in all four quarters of 2025; anticipated liquids and natural gas production and production growth for various periods including estimated production levels for the exit and average production for the first quarter of 2025 and full-year 2025; condensate and NGL production growth anticipated from the Company's Conroy North Montney, West Doe-Groundbirch, South Montney and North Deep Basin growth projects; the Company's ability to increase returns to shareholders in 2025 relative to 2024; expected full-year 2025 EP capital budget and anticipated timing for finalizing the second half 2025 EP capital program; the number of wells that the Company anticipates bringing on-production in 2025; the Company's ability to adjust the capital program if natural gas pricing recovers later in 2025; the expectation that the Company will finalize the sequencing of the entire future NEBC infrastructure buildout during 2025, as well as the expectation that the Groundbirch development will consist of two separate 200 mmcfpd deep cut plants and the timing of installation thereof; anticipated natural gas prices; the expectation that the ability to acquire new surface disturbance permits in HV1 areas in NEBC will improve in 2025; the number of wells that the Company plans to drill and complete in 2025; the potential high impact exploration wells in the 2025 exploration program; the expected reduction in midstream related costs to be achieved on the assets acquired through the Crew Energy Inc. acquisition; sustainability and environmental improvement initiatives; anticipated natural gas volumes to targeted premium export markets at the end of 2025; the anticipated timing of additional compressed natural gas fueling stations; the reduction in costs an emissions in the long-haul trucking market and the demand for natural gas that will result from the Company's initiative to construct and own compressed natural gas fueling stations; the number of additional water storage and recycling facilities to be constructed in 2025; as well as Tourmaline's future drilling prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning the following: prevailing and future commodity prices and currency exchange rates; the degree to which Tourmaline's operations and production may be disrupted or by circumstances attributable to supply chain disruptions; applicable royalty rates and tax laws; interest rates; inflation rates; future well production rates and reserve volumes; operating costs, receipt of regulatory approvals and the timing thereof; the performance of existing and future wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the benefits to be derived from acquisitions; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; ability to maintain investment grade credit rating; and ability to market crude oil, natural gas and natural gas liquids successfully. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time is dependent upon, among other things, free cash flow, financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tourmaline to pay dividends is subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.
Statements relating to "reserves" are also deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that it will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; supply chain disruptions; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; changes in rates of inflation; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; stock market volatility; ability to access sufficient capital from internal and external sources; uncertainties associated with counterparty credit risk; failure to obtain required regulatory and other approvals including drilling permits and the impact of not receiving such approvals on the Company's long-term planning; climate change risks; severe weather (including wildfires and drought); risks of wars or other hostilities or geopolitical events, civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in legislation, including but not limited to tax laws, royalties and environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies) and including uncertainty with respect to the interpretation of omnibus Bill C-59 and the related amendments to the Competition Act (Canada)); trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade arrangements); general economic and business conditions and markets. Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein), Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities which may be accessed through the SEDAR+ website (www.sedarplus.ca) or Tourmaline's website (www.tourmaline.com).
The forward-looking information contained in this news release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.
The reserves data set forth above is based upon the reports of GLJ Ltd. ("GLJ") and Deloitte LLP, each dated effective December 31, 2024, which have been consolidated into one report by GLJ and adjusted to apply certain of GLJ's assumptions and methodologies and pricing and cost assumptions. The price forecast used in the reserve evaluations is an average of forecast prices published by Sproule Associates Ltd. as at December 31, 2024 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2025 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com, and www.mcdan.com), and will be contained in the Company's Annual Information Form for the year ended December 31, 2024, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before March 31, 2025.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company's oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company's tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company's financial statements and the management's discussion and analysis should be consulted for information at the level of the Company.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregations. The estimated values of future net revenue disclosed in this news release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2024, which will be filed on (SEDAR+ accessible at www.sedarplus.ca) on or before March 31, 2025.
BOE EQUIVALENCY
In this news release, production and reserves information may be presented on a "barrel of oil equivalent" or "BOE" basis. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
INDUSTRY METRICS
This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are "F&D" costs, "FD&A" costs, "recycle ratio", "F&D recycle ratio", and "FD&A recycle ratio". These metrics are considered "non-GAAP ratios" and do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. The non-GAAP financial measures used as a component of these non-GAAP ratios are capital expenditures and cash flow.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time, however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods.
"F&D" costs are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.
"FD&A" costs are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.
The "recycle ratio" is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.
The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
FINANCIAL OUTLOOKS
Also included in this news release are estimates of Tourmaline's 2025 cash flow and free cash flow and long-term net debt targets, which are based on, among other things, the various assumptions as to production levels, capital expenditures and other assumptions disclosed in this news release and including Tourmaline's estimated 2025 average production of 635,000 – 665,000 boepd, 2025 commodity price assumptions for natural gas ($3.96/mcf NYMEX US, $2.23/mcf AECO, $15.22/mcf JKM US), crude oil ($69.94/bbl WTI US) and an exchange rate assumption of $0.71 (US/CAD). These estimates are included to provide readers with an understanding of Tourmaline's anticipated cash flow, free cash flow and net debt levels based on the capital expenditure, production, pricing, exchange rate and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
NON-GAAP AND OTHER FINANCIAL MEASURES
This news release contains the terms "cash flow", "capital expenditures", "free cash flow", and "operating netback", which are considered "non-GAAP financial measures" and the terms "cash flow per diluted share", "free cash flow per diluted share", "operating netback per boe", "cash flow per-boe", "finding and development costs", "finding, development and acquisition costs" and "recycle ratio", which are considered "non-GAAP financial ratios". These terms do not have a standardized meaning prescribed by GAAP. In addition, this news release contains the terms "adjusted working capital" and "net debt", which are considered "capital management measures" and do not have standardized meanings prescribed by GAAP. Accordingly, 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 or more meaningful than the most directly comparable GAAP measures in evaluating the Company's performance. See "Non-GAAP and Other Financial Measures" in the most recent Management's Discussion and Analysis for more information on the definition and description of these terms.
Non-GAAP Financial Measures
Cash Flow
Management uses the term "cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash (net of current income taxes) necessary to fund its future growth expenditures, to repay debt or to pay dividends. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to cash flow, is set forth below:
Three Months Ended |
Years Ended |
|||
(000s) |
2024 |
2023 |
2023 |
2023 |
Cash flow from operating activities (per GAAP) |
$ 666,110 |
$ 1,012,819 |
$ 2,729,780 |
$ 4,406,092 |
Current income taxes (1) |
(36,665) |
(75,669) |
(65,173) |
(431,298) |
Current income taxes paid (recovered) |
(34) |
6,051 |
526,768 |
40,548 |
Change in non-cash working capital (deficit) |
220,919 |
(25,193) |
27,116 |
(307,659) |
Cash flow |
$ 850,330 |
$ 918,008 |
$ 3,218,491 |
$ 3,707,683 |
(1) |
For the purposes of this reconciliation, current income taxes exclude $19.0 million of income taxes related to the capital gain on the sale of Topaz shares during the three and twelve months ended December 31, 2024. Refer to Notes 11 and 14 of the Company's consolidated financial statements as at and for the year ended December 31, 2024 for further details. |
Capital Expenditures
Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and divestitures. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures, is set forth below:
Three Months Ended |
Years Ended |
|||
(000s) |
2024 |
2023 |
2024 |
2023 |
Cash flow used in investing activities (per GAAP) |
$ 123,552 |
$ 1,196,019 |
$ 1,638,627 |
$ 2,602,360 |
Corporate acquisitions |
(169,040) |
(650,986) |
(169,040) |
(650,986) |
Change in non-cash working capital |
174,216 |
90,954 |
100,409 |
121,875 |
Proceeds from sale of investments |
331,465 |
– |
331,465 |
– |
Capital expenditures |
$ 460,193 |
$ 635,987 |
$ 1,901,461 |
$ 2,073,249 |
EP Expenditures
Management uses the term "EP expenditures" or exploration and production expenditures as a measure of capital investment in exploration and production activity, and such spending is compared to the Company's annual budgeted exploration and production expenditures. The most directly comparable GAAP measure for exploration and production spending is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to exploration and development expenditures, is set forth below:
Three Months Ended |
Years Ended |
|||
(000s) |
2024 |
2023 |
2024 |
2023 |
Cash flow used in investing activities (per GAAP) |
$ 123,552 |
$1,196,019 |
$ 1,638,627 |
$ 2,602,360 |
Change in non-cash working capital |
174,216 |
90,954 |
100,409 |
121,875 |
Proceeds from sale of investments |
331,465 |
– |
331,465 |
– |
Corporate acquisitions |
(169,040) |
(650,986) |
(169,040) |
(650,986) |
Property acquisitions |
(7,379) |
– |
(33,083) |
(58,536) |
Proceeds from divestitures |
300,858 |
– |
357,692 |
7,789 |
Other |
(10,256) |
(12,737) |
(52,607) |
(51,292) |
Exploration and production expenditures |
$ 743,416 |
$ 623,250 |
$ 2,173,463 |
$ 1,971,210 |
Free Cash Flow
Management uses the term "free cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund its future growth expenditures, to repay debt and provide shareholder returns. Free cash flow is defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payment. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. See "Non-GAAP Financial Measures – Cash Flow" and " Non-GAAP Financial Measures – Capital Expenditures" above.
Three Months Ended |
Years Ended |
|||
(000s) |
2024 |
2023 |
2024 |
2023 |
Cash flow |
$ 850,330 |
$ 918,008 |
$ 3,218,491 |
$ 3,707,683 |
Capital expenditures |
(460,193) |
(635,987) |
(1,901,461) |
(2,073,249) |
Property acquisitions |
7,379 |
- |
33,083 |
58,536 |
Proceeds from divestitures |
(300,858) |
- |
(357,692) |
(7,789) |
Free Cash Flow |
$ 96,658 |
$ 282,021 |
$ 992,421 |
$ 1,685,181 |
Operating Netback
Management uses the term "operating netback" as a key performance indicator and one that is commonly presented by other oil and natural gas producers. Operating netback is defined as the sum of commodity sales from production, premium on risk management activities and realized (loss) on financial instruments less the sum of royalties, transportation costs and operating expenses. A summary of the reconciliation of operating netback from commodity sales from production, which is a GAAP measure, is set forth below:
Three Months Ended |
Years Ended |
|||
(000s) |
2024 |
2023 |
2024 |
2023 |
Commodity sales from production |
$ 1,215,050 |
$ 1,366,040 |
$ 4,729,771 |
$ 5,351,253 |
Premium on risk management activities |
280,791 |
191,236 |
828,468 |
811,263 |
Realized gain on financial instruments |
127,978 |
101,607 |
486,534 |
544,481 |
Royalties |
(125,699) |
(150,466) |
(509,252) |
(638,419) |
Transportation costs |
(276,602) |
(276,991) |
(1,082,592) |
(1,000,570) |
Operating expenses |
(251,594) |
(216,462) |
(1,006,541) |
(857,173) |
Operating netback |
$ 969,924 |
$ 1,014,964 |
$ 3,446,388 |
$ 4,210,835 |
Non-GAAP Financial Ratios
Operating Netback per-boe
Management calculates "operating netback per-boe" as operating netback divided by total production for the period. Operating netback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas producers. A summary of the calculation of operating netback per boe, is set forth below:
Three Months Ended |
Years Ended |
|||
($/boe) |
2024 |
2023 |
2024 |
2023 |
Revenue, excluding processing income |
$ 29.15 |
$ 32.37 |
$ 28.52 |
$ 35.31 |
Royalties |
(2.26) |
(2.94) |
(2.40) |
(3.36) |
Transportation costs |
(4.97) |
(5.41) |
(5.11) |
(5.27) |
Operating expenses |
(4.52) |
(4.22) |
(4.75) |
(4.51) |
Operating netback |
$ 17.40 |
$ 19.80 |
$ 16.26 |
$ 22.17 |
Cash Flow per-boe
Management uses cash flow per boe to highlight how much cash flow is generated by each boe produced. The ratio is calculated by dividing cash flow by total production for the period. See "Non-GAAP Financial Measures – Cash Flow". See "Reserves Performance Ratios" section for information on annual cash flow per boe and comparative period data used.
Finding and Development Costs, Finding, Development and Acquisition Costs and Recycle Ratio
See "Reserves Performance Ratios" and "Industry Metrics" for information on the composition of the non-GAAP financial measures used as a component of and comparative period data for finding and development costs, finding, development and acquisition costs and recycle ratio.
Capital Management Measures
Adjusted Working Capital
Management uses the term "adjusted working capital" for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's liquidity. A summary of the reconciliation of working capital (deficit) to adjusted working capital (deficit), is set forth below:
As at December 31, |
||
(000s) |
2024 |
2023 |
Working capital (deficit) |
$ (167,623) |
$ (298,280) |
Fair value of financial instruments – short-term (asset) |
(315,365) |
(437,535) |
Lease liabilities – short-term |
8,385 |
5,796 |
Decommissioning obligations – short-term |
60,000 |
45,000 |
Unrealized foreign exchange in working capital – (asset) liability |
(15,354) |
5,524 |
Adjusted working capital (deficit) |
$ (429,957) |
$ (679,495) |
Net Debt
Management uses the term "net debt", as a key measure for evaluating its capital structure and to provide shareholders and potential investors with a measurement of the Company's total indebtedness. A summary of the composition of net debt, is set forth below:
As at December 31, |
||
(000s) |
2024 |
2023 |
Bank debt |
$ (574,339) |
$ (651,594) |
Senior unsecured notes |
(698,436) |
(448,643) |
Adjusted working capital (deficit) |
(429,957) |
(679,495) |
Net debt |
$ (1,702,732) |
$ (1,779,732) |
Supplementary Financial Measures
The following measures are supplementary financial measures: cash flow per diluted share, reserve value per diluted share, operating expenses ($/boe), cash general and administrative expenses ($/boe) and transportation costs ($/boe). These measures are calculated by dividing the numerator by a diluted share count or by total production for the period, depending on the financial measure discussed.
ESTIMATED DRILLING INVENTORY
This news release discloses drilling locations. Drilling locations are categorized as follows: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 23,724 (gross) locations disclosed in this news release, 2,132 are proved undeveloped locations, 36 are proved non-producing locations, 1,735 are probable undeveloped locations, and 19,821 are unbooked. Proved producing wells, proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by GLJ and Deloitte LLP as of December 31, 2023, and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
SUPPLEMENTAL INFORMATION REGARDING PRODUCT TYPES
This news release includes references to full-year 2024 production, Q4 2024 production and Q1 2025 and full-year 2025 expected average daily production. The following table is intended to provide supplemental information about the product type composition for each of the production figures that are provided in this news release:
Light and Medium |
Conventional |
Shale Natural Gas |
Natural Gas |
Oil Equivalent |
|
Company Gross |
Company Gross |
Company Gross |
Company Gross |
Company Gross |
|
2024 Average Daily |
12,173 |
1,476,442 |
1,167,090 |
126,411 |
579,173 |
Q4 2024 Average Daily |
11,572 |
1,522,030 |
1,277,335 |
127,280 |
605,413 |
Q1 2025 Expected |
11,880 |
1,529,630 |
1,333,000 |
143,515 |
632,500 |
2025 Expected Average |
58,100 |
1,582,500 |
1,347,500 |
103,550 |
650,000 |
(1) |
For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGLs in this disclosure exclude condensate. |
GENERAL
See also "Forward-Looking Statements" and "Non-GAAP and Other Financial Measures" in the most recently filed Management's Discussion and Analysis.
CERTAIN DEFINITIONS:
1H |
first half |
2H |
second half |
bbl |
barrel |
bbls/day |
barrels per day |
bbl/mmcf |
barrels per million cubic feet |
bcf |
billion cubic feet |
bcfe |
billion cubic feet equivalent |
bpd or bbl/d |
barrels per day |
boe |
barrel of oil equivalent |
boepd or boe/d |
barrel of oil equivalent per day |
bopd or bbl/d |
barrel of oil, condensate or liquids per day |
DUC |
drilled but uncompleted wells |
EP |
exploration and production |
gj |
gigajoule |
gjs/d |
gigajoules per day |
JKM |
Japan Korea Marker |
mbbls |
thousand barrels |
mmbbls |
million barrels |
mboe |
thousand barrels of oil equivalent |
mboepd |
thousand barrels of oil equivalent per day |
mcf |
thousand cubic feet |
mcfpd or mcf/d |
thousand cubic feet per day |
mcfe |
thousand cubic feet equivalent |
mmboe |
million barrels of oil equivalent |
mmbtu |
million British thermal units |
mmbtu/d |
million British thermal units per day |
mmcf |
million cubic feet |
mmcfpd or mmcf/d |
million cubic feet per day |
MPa |
megapascal |
mstb |
thousand stock tank barrels |
natural gas |
conventional natural gas and shale gas |
NCIB |
normal course issuer bid |
NGL or NGLs |
natural gas liquids |
TCF |
trillion cubic feet |
MANAGEMENT'S DISCUSSION AND ANALYSIS AND CONSOLIDATED FINANCIAL STATEMENTS
To view Tourmaline's Management's Discussion and Analysis and Consolidated Financial Statements for the years ended December 31, 2024 and 2023, please refer to SEDAR+ (www.sedarplus.ca) or Tourmaline's website at www.tourmaline.com.
About Tourmaline Oil Corp.
Tourmaline is Canada's largest and most active natural gas producer dedicated to producing the lowest-development-cost natural gas in North America. We are an investment grade exploration and production company providing strong and predictable operating and financial performance through the development of our three core areas in the Western Canadian Sedimentary Basin. With our existing large reserve base, decades-long drilling inventory, relentless focus on execution, cost management, and environmental performance improvement, we are excited to provide shareholders an excellent return on capital and an attractive source of income through our base dividend and surplus free cash flow distribution strategies.
Website: www.tourmaline.com
SOURCE Tourmaline Oil Corp.
For further information, please contact: Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer, (403) 266-5992 OR Tourmaline Oil Corp., Brian Robinson, Chief Financial Officer, (403) 767-3587; [email protected] OR Tourmaline Oil Corp., Scott Kirker, Chief Legal Officer and External Affairs, (403) 767-3593; [email protected] OR Tourmaline Oil Corp., Jamie Heard, Vice President, Capital Markets, (403) 767-5942; [email protected] OR Tourmaline Oil Corp., Suite 2900, 250 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, Phone: (403) 266-5992; Facsimile: (403) 266-5952, E-mail: [email protected]
Share this article