CALGARY, AB, March 4, 2026 /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 2025.
HIGHLIGHTS
-- Record Q4 2025 average production of 659,204 boepd and January 2026
average production of over 685,000 boepd.
-- 829 million boe proved plus probable ("2P") reserve addition in 2025,
including a corporate record single year organic 2P reserve addition of
457 million boe, both after accounting for 2025 production.
-- Continued corporate operating costs reduction in Q4 2025, down over 9%
from the first half of 2025 to $4.66/boe.
-- Peace River High ("PRH") asset sale completed in February 2026 for
proceeds of $765 million, prior to customary closing adjustments.
-- 2026 forecasted EP capital expenditures reduced by $350 million as the
Company remains focused on optimizing free cash flow(1)(2) ("FCF").
-- Quarterly base dividend of $0.50/share to be paid on March 31, 2026 to
shareholders of record at the close of business on March 16, 2026.
-- Net debt(3) at year-end 2025 of $1.5 billion, inclusive of the impact of
the PRH asset sale, or 0.45x forecasted 2026 cash flow(4) ("CF"), down
from Q3 2025 net debt of $2.3 billion.
PRODUCTION UPDATE
-- Record Q4 2025 average production of 659,204 boepd, within the previous
Q4 guidance range of 655,000 - 665,000 boepd.
-- Q4 2025 average liquids production (oil, condensate, NGLs) was also a
record at 152,673 bbls/d.
-- January 2026 production averaged over 685,000 boepd prior to the impact
of the PRH asset sale, a new record and ahead of expectations.
-- First quarter 2026 average production of 660,000 - 670,000 boepd is
anticipated, after taking into account the sale of the PRH assets which
closed on February 2, 2026.
-- In order to improve operating netbacks(5), Tourmaline has elected to
terminate its discretionary deep cut gas plant deliveries in the Alberta
Deep Basin in 2026 as contracts expire. This will reduce corporate
average ethane production volumes by approximately 20,000 bpd on a full
year basis but is expected to increase forecasted 2026 operating netback
by approximately $65 million and forecasted 2027 operating netback by
approximately $110 million through the elimination of deep cut processing
fees as well as C2+ transportation and fractionation fees.
FINANCIAL RESULTS
-- Q4 2025 CF was $890 million ($2.29 per fully diluted share(6)). Full year
2025 CF was $3.4 billion ($8.84 per fully diluted share).
-- Tourmaline sold its PRH complex to a Canadian senior producer for cash
proceeds of $765 million, prior to customary closing adjustments. Through
this transaction, Tourmaline has sold its most mature, highest-cost
production and will replace it with new low-cost production streams
flowing through newly constructed Tourmaline facilities. Although
Tourmaline pioneered the Charlie Lake horizontal play in 2009-2010, this
disposition will allow the Company to enhance its focus on the Company's
two massive gas complexes. Tourmaline intends to utilize approximately
$500 million of the proceeds of this disposition for permanent long-term
debt reduction and approximately $265 million for the NEBC infrastructure
buildout over the next two years.
-- Net debt at year end 2025 was $1.5 billion, inclusive of the impact of
the PRH asset sale, and down from Q3 2025 net debt of $2.3 billion. The
Company is setting a long-term net debt target of $1.75 billion
(approximately 0.5x net debt to cash flow).
CAPITAL BUDGET/EP PLAN
-- The multi-year EP Plan has been updated for full year 2025 results, asset
sales, strong well performance, new commodity hedges, and cost reduction
initiatives realized to date.
-- The Company believes that during these unusually volatile times, the
optimal business approach is to steadily reduce debt and continuously
improve the overall cost structure. The Company is already executing on
this plan.
-- Q4 2025 EP capital spending was $812.7 million, within the original
quarterly guidance range. Full year 2025 EP capital spending was $2.93
billion.
-- The PRH asset sale and the redirection of discretionary Deep Basin deep
cut volumes will reduce total corporate production by a total of
approximately 50,000 boepd on a full year basis. Q1 2026 average
production of 660,000 - 670,000 boepd is now expected (which includes
Deep Basin deep cut production volumes for the entire quarter and PRH
production volumes until February 2, 2026). The full year 2026
anticipated average production range is now 620,000 - 640,000 boepd.
-- The 2026 full year EP capital program will be reduced by $350 million to
$2.55 billion along with a $50 million cut in non-EP capital for a total
capital expenditure reduction of $400 million. This reduction includes
$175 million of the originally planned 2026 EP capex in the PRH complex
and $175 million of expenditures in the gas complexes. The Company
believes it is prudent to defer certain gas-focused expenditures until a
sustained, stronger local price environment materializes. The gas complex
expenditure reduction will have a negligible impact on production
guidance (1.0%) given stronger than anticipated 2026 well performance to
date. The Company has identified an additional $200 million of drilling
and completion capital that could be deferred from the 2026 EP capital
program if commodity prices deteriorate further.
-- At strip pricing(7), Tourmaline's revised EP Plan anticipates 2026 CF of
$3.4 billion and FCF of $0.7 billion. All else equal for every US
$0.10/mcf that AECO pricing improves, Tourmaline's 2026 CF and FCF
increase by approximately $45 million. Similarly, for every US $1.00/mcf
that both JKM and TTF pricing improve, Tourmaline's 2026 CF and FCF
increase by approximately $50 million and Tourmaline's 2027 CF and FCF
increase by approximately $70 million.
2025 RESERVES
-- Year-end 2025 proved developed producing ("PDP") reserves(8) of 1.47
billion boe were up 27% after accounting for 2025 annual production of
233 million boe. Total proved ("TP") reserves of 3.26 billion boe were up
20% after accounting for 2025 production. 2P reserves of 6.09 billion boe
were up 15% after accounting for 2025 production.
-- The 2025 2P organic reserve addition of 457 million boe was the largest
single year organic 2P addition in corporate history.
-- After 17 years of operations, Tourmaline now has 27.7 TCF of economic 2P
natural gas reserves and 1.48 billion barrels of 2P oil, condensate and
NGL reserves, all of which are pipeline-connected to markets across North
America. At year-end 2025, 15.4% of the current internally estimated
drilling inventory of 26,512 gross locations was booked in the 2025
year-end reserve report.
-- Year-end 2025 oil, condensate and NGL 2P reserves of 1.48 billion barrels
represent the second largest conventional liquids reserve base in Canada,
based on public disclosure.
-- Tourmaline has only booked 4,073 gross locations of a total drilling
inventory of 26,512 gross locations (15.4% of the overall inventory) to
achieve year-end 2025 2P reserves of 6.1 billion boe.
-- Tourmaline replaced 356% of its 2025 annual production of 233 million boe
with 2P additions of 829 million boe, including 2025 production.
-- Tourmaline's 2025 PDP finding and development ("F&D") costs were $9.81
per boe including changes in future development capital ("FDC"), yielding
a PDP reserve recycle ratio of 1.5 times. TP finding, development and
acquisition ("FD&A") costs in 2025 were $10.95 per boe, including changes
in FDC. 2P FD&A costs in 2025 were $9.09 per boe, including changes in
FDC.
-- The Company elected to increase drill and complete costs across the
entire booked inventory (4,073 gross locations) to reflect the steady
migration to longer horizontals and an increasing percentage of plug and
perf style completions. Future facility capital was also increased to
reflect the Company's planned NEBC infrastructure buildout. These 2025
additions to the Company's total FDC amount incorporated in the year-end
2025 reserve report resulted in a $3.21/boe increase to the Company's
2025 2P FD&A including FDC and an increase of $4.61/boe to the Company's
2P F&D costs including FDC. These additions to the Company's total FDC
amounts are not expected to reoccur in future reserve reports. 2025 2P
FD&A costs including the increased FDC were $9.09/boe, compared to 5-year
2P FD&A costs of $7.74/boe, including changes in FDC.
-- Tourmaline's 2P reserve value (before taxes) equates to $98.86 per
diluted share (after tax reserve value of $75.66 per diluted share) using
the January 1, 2026 engineering price deck and a 10% discount rate. TP
reserve value (before tax) is $64.06 per diluted share and $50.43 per
diluted share (after tax). PDP reserve value is $38.94 per diluted share
(before tax) and $32.89 per diluted share (after tax). The decrease in
the 2P reserve value in the current reserve report (compared to the
December 31, 2024 reserve report) is a result of a significant increase
in reserve volumes being more than offset by significant backwardation in
the JKM gas price as well as weaker AECO prices in the engineering price
deck after 2027.
MARKETING UPDATE
-- Tourmaline's average realized natural gas price in Q4 2025 was CAD
$3.77/mcf, significantly (CAD $1.51/mcf) above the AECO 5A benchmark
price of CAD $2.26/mcf over the same period, as the Company continues to
benefit from its diversified marketing portfolio and strategic hedging
program.
-- Tourmaline has an average of 879 mmcfpd of natural gas hedged for 2026 at
a weighted average fixed price of CAD $4.54/mcf. This includes 55 mmcfpd
hedged at a weighted average price of CAD $14.69/mcf in international
markets and 130 mmcfpd at a weighted average price of CAD $6.70/mcf in
Western U.S. markets.
-- In Q1 2026, Tourmaline has over 370 mmcfpd of physical gas exposed to the
premium price Eastern markets (Dawn, Ventura, Chicago, Iroquois, Emerson
and ANR SE), providing a strong uplift to Q1 cash flow. These markets
traded at an average of CAD $24.00/mcf for the last ten days of January.
-- The Company entered into a long-term natural gas storage agreement with
AltaGas at its Dimsdale Storage Facility in Alberta in 2025, and AltaGas
has announced a positive final investment decision ("FID") for the Phase
2 expansion of the facility. Tourmaline will have access to 6 bcf of
storage capacity starting April 2026, increasing to 10 bcf in mid-2027
for a 10-year term. The Company views the acquisition of an additional
large storage position as a strategic opportunity to improve financial
performance and enhance operational flexibility in periods of natural gas
volatility. This is another aspect of the Company's ongoing efforts to
fully vertically integrate the overall gas business.
-- Tourmaline will have an average of 213,000 mmbtu/d exposed to
international pricing (TTF/JKM) in 2026. This will grow to 253,000
mmbtu/d by exit 2027 and 333,000 mmbtu/d by exit 2028. Both JKM and TTF
prices have improved since year end 2025.
COST REDUCTION/MARGIN IMPROVEMENT UPDATE
-- Tourmaline embarked upon a comprehensive cost reduction initiative in
mid-2025 with the focus on reducing all aspects of the cost equation.
These realized cost reductions are expected to be sustainable on a
long-term basis.
-- Q4 2025 operating costs were $4.66/boe, down 3% from third quarter 2025
operating costs of $4.80/boe and down 9% from first half of 2025
operating costs of $5.14/boe.
-- The sale of the PRH complex will reduce go-forward corporate operating
costs by a further 7%, resulting in a 2026 operating cost guidance of
$4.50/boe, a 9% year-over-year reduction.
-- With the success of cost reduction initiatives to date, Tourmaline is
revising its aggregate operating and transport cost reduction target by
2031 from $1.00/boe to $1.50/boe, with approximately $0.70/boe already
achieved since the first half of 2025 when the target was initiated.
-- Lower aggregate debt levels combined with the Company's recently
initiated commercial paper program are expected to yield approximately
$20-25 million in interest cost reductions in 2026 based on prevailing
interest rates.
-- Tourmaline has entered into agreements to control frac sand capacity in a
transload facility in the NEBC Montney complex. The facility is expected
to commence operations in Q2 2026. This vertical integration of the
Company's sand business is estimated to save over $40M per year in
capital costs.
-- The NEBC infrastructure buildout will systematically reduce costs as
various components of the buildout are completed. The first major
component to be completed is the liquids hub and associated pipelines
located in proximity to the Aitken gas processing complex. The project
was commissioned in February 2026 with an initial capacity of 20,000
bbl/d and will handle all condensate from North Montney Phase 1 and
future North Montney development phases with resulting expected overall
corporate savings of $0.05/boe over the EP Plan period.
-- By 2031, through expected total cost reductions of $1.50/boe, and
sand-related capital savings of over $40 million per year, Tourmaline
anticipates up to $500 million per year of aggregate structural cost
reductions, compared to the Company's first half of 2025 total cost
structure, which will flow through to lower corporate break evens and FCF
margin improvement.
EP UPDATE
-- Tourmaline drilled 331 gross wells in 2025 and led the Canadian
industry(9) with a total of 1.7 million metres drilled during the year.
-- In 2025, Tourmaline delivered its best overall well performance in the
past five years in the NEBC Montney gas condensate complex (21% higher
than the previous 5-year average based on the IP90 of 102 wells). This
outperformance has been across the full suite of the BC Montney assets,
from Aitken-Birch-Gundy in the north to Groundbirch-Doe-Monias in the
south.
-- The Company is currently planning to drill and complete a total of
approximately 280 net wells in 2026 including approximately 140 net wells
in both the Alberta Deep Basin and the NEBC gas condensate complexes.
Tourmaline continues to increase its lateral length with the 2025 Deep
Basin and NEBC program averaging 8,400 completed lateral feet, up over
1,100 feet from 2024. Drilling and completion costs per foot in the Deep
Basin and NEBC are now in decline, dropping from $805 per lateral foot in
2024 to $780 per lateral foot in 2025 despite steadily higher tonnage in
NEBC completions.
-- The 2026 EP capital budget reduction will not impact the original
start-up timing of the Aitken and Groundbirch/Monias gas plant projects
in NEBC. Aitken is on schedule for a Q4 2026 completion, with
Groundbirch/Monias completion expected in Q4 2027.
-- The Company's ongoing new zone/new pool exploration program has resulted
in 2.55 TCFe of 2P reserves (as at December 31, 2025) and 1,356
Tier1/Tier 2 drilling locations, with the vast majority of these
additions occurring in the last five years. There are several potential
high impact exploration and delineation wells planned in the 2026
program.
ENVIRONMENTAL PERFORMANCE IMPROVEMENT
-- Tourmaline has achieved Grade 'A' certification for methane performance
across its NEBC assets under MiQ's global methane certification standard.
Tourmaline is the first Canadian company to be certified under MiQ and
the first company in MiQ's history to have certified integrated gas
production and processing facilities.
-- 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 240 million
litres of diesel, providing an emissions reduction of 160,000 tonnes of
carbon dioxide and saving approximately $235 million (including the cost
of the replacement natural gas). Drilling and completions operations
powered by 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 5 stations operational across Alberta and British Columbia. An
additional four new stations are planned in 2026. 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 a new water recycling facility in
2025 and is planning to build three additional storage and recycling
facilities in 2026. These facilities reduce freshwater usage and reduce
well stimulation costs.
-- The Company is a leader in methane emission mitigation and operates the
West Wolf Emissions Testing Centre, the largest in the world, where new
technologies to accurately measure and ultimately reduce methane
emissions are developed.
DIVIDEND
-- Tourmaline's Board of Directors has declared a quarterly base dividend of
$0.50 per share, payable on March 31, 2026 to shareholders of record at
the close of business on March 16, 2026. The quarterly base dividend is
designated as an eligible dividend for Canadian income tax purposes.
-- Weak WCSB local gas pricing and unusually low pricing at the PG&E and
Malin sales hubs this winter will limit FCF and constrain the Company's
ability to fund a special dividend in Q1. Sustained stronger pricing and
the Company's ongoing margin improvement activities are expected to lead
to further base dividend increases in the future. Special dividends are
anticipated to be used in those periods of particularly strong pricing to
return the majority of the incremental FCF to shareholders.
_______________________________________________________
(1) This news release contains certain specified financial
measures consisting of non-GAAP financial measures,
non-GAAP financial ratios, capital management measures
and supplementary financial measures. See "Non-GAAP
and Other Financial Measures" in this news release
for information regarding the following specified
financial measures: "cash flow", "capital expenditures",
"EP expenditures", "free cash flow", "operating netback",
"operating netback per boe", "cash flow per diluted
share", "free cash flow per diluted share", "adjusted
working capital", "net debt", "reserve value per diluted
share", "operating expenses per boe", "cash general
and administrative expenses per boe" and "transportation
costs per boe". Since these specified financial measures
do not have standardized meanings under International
Financial Reporting Standards ("GAAP"), securities
regulations require that, among other things, they
be identified, defined, qualified and, where required,
reconciled with their nearest GAAP measure and compared
to the prior period. See "Non-GAAP and Other Financial
Measures" in this news release and in the Company's
Management's Discussion and Analysis as at and for
the year ended December 31, 2025 (the "Annual MD&A"),
which information is incorporated by reference into
this news release, for further information on the
composition of and, where required, reconciliation
of these measures.
(2) "Free cash flow" is a non-GAAP financial measure defined
as cash flow less capital expenditures, excluding
acquisitions and dispositions. Free cash flow is prior
to dividend payments. See "Non-GAAP and Other Financial
Measures" in this news release.
(3) "Net debt" is a capital management measure. See "Non-GAAP
and Other Financial Measures" in this news release
and in the Annual MD&A.
(4) "Cash flow" is a non-GAAP financial measure defined
as cash flow from operating activities adjusted for
the change in non-cash working capital (deficit) and
current taxes. See "Non-GAAP and Other Financial Measures"
in this news release and in the Annual MD&A.
(5) "Operating netback" is a non-GAAP financial measure.
See "Non-GAAP and Other Financial Measures" in this
news release and in the Annual MD&A.
(6) "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 ratio.
See "Non-GAAP and Other Financial Measures" in this
news release and in the Annual MD&A.
(7) Strip Pricing as of March 2, 2026.
(8) 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.
(9) As reported by Daily Oil Bulletin Energy on February
25, 2026.
CORPORATE SUMMARY -- DECEMBER 31, 2025
Three Months EndedDecember 31, Twelve Months EndedDecember 31,
2025 2024 Change 2025 2024 Change
OPERATIONS
Production
Natural gas (mcf/d) 3,039,185 2,779,365 9 % 2,946,447 2,643,532 11 %
Crude oil, condensate and
NGL (bbl/d) 152,673 138,852 10 % 147,121 138,584 6 %
Oil equivalent (boe/d) 659,204 605,413 9 % 638,196 579,173 10 %
Product prices(1)
Natural gas ($/mcf) $ 3.77 $ 3.48 8 % $ 3.62 $ 3.38 7 %
Crude oil, condensate and
NGL ($/bbl) $ 47.08 $ 56.99 (17) % $ 50.27 $ 54.78 (8) %
Operating expenses
($/boe) $ 4.66 $ 4.52 3 % $ 4.93 $ 4.75 4 %
Transportation costs
($/boe) $ 5.06 $ 4.97 2 % $ 5.14 $ 5.11 1 %
Operating netback
($/boe)(2) $ 16.32 $ 17.40 (6) % $ 16.02 $ 16.26 (1) %
Cash general and
administrative expenses
($/boe)(3) $ 0.69 $ 0.82 (16) % $ 0.78 $ 0.77 1 %
FINANCIAL
($000, except share and
per share)
Commodity sales from
production
Total revenue from
commodity sales and
realized gains 1,714,660 1,623,819 6 % 6,591,299 6,044,773 9 %
Royalties 135,121 125,699 7 % 513,879 509,252 1 %
Cash flow 890,117 850,330 5 % 3,395,570 3,218,491 6 %
Cash flow per share
(diluted) $ 2.29 $ 2.27 1 % $ 8.84 $ 8.93 (1) %
Net earnings (655,002) 407,445 (261) % 262,672 1,264,109 (79) %
Net earnings per share
(diluted) $ (1.69) $ 1.09 (255) % $ 0.68 $ 3.51 (81) %
Capital expenditures (net
of dispositions)(2) 827,986 460,193 80 % 2,932,280 1,901,461 54 %
Weighted average shares
outstanding (diluted) 383,938,857 360,249,193 7 %
Net debt (1,523,871) (1,702,732) (11) %
PROVED +
PROBABLE RESERVES(4)
Natural gas (bcf) 27,671.4 24,837.0 11 %
Crude oil (mbbls) 124,518 119,331 4 %
Natural gas liquids
(mbbls) 1,355,332 1,236,385 10 %
Mboe 6,091,751 5,495,212 11 %
Notes:
(1) Product prices include realized gains and losses on
risk management activities and financial instrument
contracts.
(2) See "Non-GAAP and Other Financial Measures" in this
news release and in the Annual MD&A.
(3) Excluding interest and financing charges.
(4) 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.
2025 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, 2025
Forecast Prices and Costs(1)
Light & Medium Conventional Natural Shale Natural Gas(2) Natural Gas Liquids Total Oil Equivalent
Crude Oil Gas
Reserves Company Company Company Company Net Company Company Company Company CompanyGross(Mboe) CompanyNet(Mboe)
Category Gross Net Gross (MMcf) Gross Net Gross Net
(Mbbls) (Mbbls) (MMcf) (MMcf) (MMcf) (Mbbls) (Mbbls)
Proved
Developed
Producing 21,160 17,174 3,055,049 2,735,539 3,718,591 3,177,927 320,480 259,711 1,470,580 1,262,462
Proved
Developed
Non-Producing 913 719 77,273 69,212 235,875 207,971 14,957 12,073 68,061 58,989
Proved
Undeveloped 46,004 35,868 2,707,566 2,420,305 5,028,848 4,397,996 381,895 306,033 1,717,302 1,478,285
Total Proved 68,077 53,760 5,839,887 5,225,056 8,983,313 7,783,894 717,332 577,817 3,255,943 2,799,735
Total Probable 56,441 44,105 3,887,703 3,405,262 8,960,502 7,602,413 638,000 483,364 2,835,808 2,362,082
Total Proved
Plus Probable 124,518 97,865 9,727,590 8,630,317 17,943,815 15,386,307 1,355,332 1,061,181 6,091,751 5,161,817
Reserves Net Present Values of Future Net Revenue ($000s)
Category
Before Income Taxes Discounted at After Income Taxes Discounted at(3) Unit Value Before
(%/year) (%/year) Income Tax
Discounted
at 10%/year
0 5 8 10 15 20 0 5 8 10 15 20 ($/Boe) ($/Mcfe)
Proved
Developed
Producing 22,301,966 17,992,059 16,036,155 14,951,707 12,814,736 11,253,708 18,441,419 15,077,840 13,505,660 12,627,256 10,885,272 9,604,416 11.84 1.97
Proved
Developed
Non-Producing 1,676,830 1,274,026 1,096,787 998,260 803,042 660,138 1,243,603 944,800 812,099 738,132 591,280 483,594 16.92 2.82
Proved
Undeveloped 22,289,928 13,562,876 10,305,918 8,646,213 5,674,702 3,770,473 16,576,660 9,821,393 7,287,783 5,997,234 3,693,228 2,227,362 5.85 0.97
Total Proved 46,268,724 32,828,961 27,438,860 24,596,180 19,292,480 15,684,319 36,261,681 25,844,033 21,605,541 19,362,623 15,169,781 12,315,371 8.79 1.46
Total Probable 47,073,880 23,307,656 16,451,121 13,361,389 8,489,541 5,799,002 34,976,107 17,159,157 12,006,018 9,687,734 6,046,297 4,051,063 5.66 0.94
Total Proved
Plus Probable 93,342,604 56,136,618 43,889,981 37,957,569 27,782,020 21,483,321 71,237,789 43,003,190 33,611,559 29,050,357 21,216,078 16,366,435 7.35 1.23
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, 2025
Forecast Prices and Costs(1)
Reserves Revenue Royalties Operating Capital Abandonment Future Net Income Future Net
Category Costs Development and Revenue Tax Revenue
Reclamation Before After
Costs Income Income
Costs(2) Tax Tax(3)
Proved
Developed
Producing 44,048,706 6,307,932 12,849,844 81,045 2,507,918 22,301,966 3,860,547 18,441,419
Proved
Developed
Non-Producing 2,767,252 371,004 548,968 113,251 57,200 1,676,830 433,228 1,243,603
Proved
Undeveloped 55,161,594 8,535,555 11,285,023 12,392,477 658,610 22,289,928 5,713,268 16,576,660
Total Proved 101,977,552 15,214,491 24,683,836 12,586,772 3,223,728 46,268,724 10,007,043 36,261,681
Total Probable 98,478,991 18,257,702 22,549,878 9,655,820 941,711 47,073,880 12,097,772 34,976,107
Total Proved
Plus Probable 200,456,543 33,472,193 47,233,714 22,242,592 4,165,439 93,342,604 22,104,815 71,237,789
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% Crude Oil and Natural Gas Liquids Pricing
CAD/USD NYMEXWTI Near MSW, Alberta Natural Gas Liquids
Exchange Month Futures Light (Then Current Dollars)
Rate Contract Crude
$US/$Cdn Crude Oil atCushing, Oil
Oklahoma (40 API,
0.3%S)
at
Edmonton
Then
Current
$Cdn/Bbl
Constant Then Spec Edmonton Edmonton Edmonton
2026 Current Ethane Propane Butane C5+
$US/Bbl $US/ $Cdn/Bbl $Cdn/Bbl $Cdn/Bbl Stream
Bbl Quality
$Cdn/Bbl
2026 0.0 0.728 59.92 59.92 77.54 9.59 25.10 36.95 80.01
2027 2.0 0.737 63.82 65.10 83.60 10.64 27.28 39.79 86.19
2028 2.0 0.740 67.55 70.28 90.18 11.34 29.67 42.87 92.83
2029 2.0 0.740 67.78 71.93 92.32 11.66 30.37 43.89 95.05
2030 2.0 0.740 67.79 73.37 94.17 11.89 30.98 44.77 96.94
2031 2.0 0.740 67.79 74.84 96.06 12.14 31.60 45.67 98.89
2032 2.0 0.740 67.79 76.34 97.98 12.39 32.23 46.58 100.87
2033 2.0 0.740 67.79 77.87 99.93 12.64 32.87 47.51 102.88
2034 2.0 0.740 67.79 79.42 101.93 12.90 33.53 48.46 104.94
2035 2.0 0.740 67.79 81.01 103.97 13.17 34.20 49.43 107.04
2036 2.0 0.740 67.79 82.63 106.05 13.43 34.89 50.42 109.18
2037 2.0 0.740 67.79 84.29 108.17 13.70 35.58 51.43 111.36
2038 2.0 0.740 67.79 85.97 110.34 13.97 36.30 52.46 113.59
2039 2.0 0.740 67.79 87.69 112.54 14.25 37.02 53.51 115.86
2040 2.0 0.740 67.79 89.45 114.79 14.54 37.76 54.58 118.18
2041+ 2.0 0.740 67.79 +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 Alberta Plant Gate Huntingdon/ British Columbia Dutch JKM
Near Month Contract Price @ SpotThen Sumas TTF $US/
Chicago Spot $US/ MMbtu
Then Current $US/ Mmbtu
Current $Cdn/ MMbtu
$US/ MMbtu
MMbtu
Spot ARP $Cdn/ Westcoast Spot Plant Gate
MMbtu Station 2 $Cdn/
$Cdn/ MMbtu
MMbtu
Constant Then Current Dawn Price@ OntarioThen Constant Then
2026 $US/MMbtu Current 2026 Current
$US/ $US/MMbtu $Cdn/ $Cdn/
MMbtu MMbtu MMbtu
2026 3.74 3.74 3.47 3.00 3.51 2.78 2.78 2.78 2.41 2.66 2.25 10.19 9.20
2027 3.70 3.78 3.55 3.30 3.54 3.02 3.08 3.08 3.56 3.07 2.65 9.94 9.70
2028 3.70 3.85 3.63 3.49 3.61 3.13 3.26 3.26 3.64 3.25 2.83 10.19 10.40
2029 3.71 3.93 3.70 3.58 3.69 3.16 3.35 3.35 3.72 3.34 2.92 10.50 11.08
2030 3.70 4.01 3.78 3.65 3.77 3.16 3.42 3.42 3.80 3.41 2.98 10.71 11.30
2031 3.70 4.09 3.85 3.72 3.85 3.16 3.49 3.49 3.89 3.47 3.04 10.92 11.53
2032 3.70 4.17 3.94 3.80 3.93 3.17 3.57 3.57 3.97 3.54 3.11 11.14 11.76
2033 3.70 4.26 4.01 3.88 4.02 3.17 3.64 3.64 4.06 3.62 3.18 11.36 11.99
2034 3.70 4.34 4.10 3.95 4.10 3.17 3.72 3.72 4.14 3.69 3.25 11.59 12.23
2035 3.70 4.43 4.17 4.03 4.18 3.17 3.79 3.79 4.23 3.77 3.32 11.82 12.49
2036 3.70 4.52 4.26 4.11 4.27 3.17 3.87 3.87 4.32 3.84 3.39 12.06 12.74
2037 3.70 4.61 4.34 4.20 4.35 3.17 3.95 3.95 4.40 3.92 3.46 12.30 12.99
2038 3.70 4.70 4.43 4.28 4.44 3.17 4.02 4.02 4.49 4.00 3.52 12.55 13.25
2039 3.70 4.79 4.52 4.36 4.53 3.17 4.11 4.11 4.58 4.08 3.60 12.80 13.52
2040 3.70 4.89 4.61 4.45 4.62 3.17 4.19 4.19 4.67 4.16 3.67 13.05 13.79
2041+ 3.70 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 3.17 +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, 2025 price forecasts published by
GLJ and McDaniel & Associates Consultants Ltd. as
at January 1, 2026 and Sproule Associates Ltd. as
at December 31, 2025 (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 U.S. Gulf
Coast, U.S. Midwest, U.S. 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, 2025.
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, 2025 2024 2023
Reserves (Mboe)
Proved Producing 1,470,580 1,345,354 1,204,499
Total Proved 3,255,943 2,912,173 2,614,619
Proved Plus Probable 6,091,751 5,495,212 5,008,374
Capital Expenditures ($ millions)
Exploration and Development(2) 2,989 2,226 2,023
Net Property Acquisitions (Dispositions)(3) 229 (325) 51
Corporate Acquisitions(3) 502 1,709 1,442
Total(4) 3,720 3,610 3,516
Cash Flow ($/boe)
Cash Flow 14.58 15.18 19.52
Cash Flow - Three Year Average 16.26 20.20 21.58
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 $51 million, $45 million
and $43 million for 2025, 2024 and 2023, respectively.
(3) Includes purchase price (cash and/or common shares)
plus net debt, if applicable.
(4) Represents the capital expenditures used for purposes
of F&D and FD&A calculations.
Finding and Development Costs
Finding and Development Costs, Excluding 2025 2024 2023 3-Year Avg. FDC Total Proved Reserve Additions (MMboe) 387.8 232.8 209.3 F&D Costs ($/boe) 7.71 9.56 9.66 8.72 F&D Recycle Ratio(1) 1.9 1.6 2.0 1.9 Total Proved Plus Probable Reserve Additions (MMboe) 457.5 167.1 230.7 F&D Costs ($/boe) 6.53 13.32 8.77 8.46 F&D Recycle Ratio(1) 2.2 1.1 2.2 1.9 Finding and Development Costs, Including 2025 2024 2023 3-Year Avg. FDC Total Proved Change in FDC ($ millions) 1,669.4 (161.5) 231.8 Reserve Additions (MMboe) 387.8 232.8 209.3 F&D Costs ($/boe) 12.01 8.87 10.77 10.82 F&D Recycle Ratio(1) 1.2 1.7 1.8 1.5 Total Proved Plus Probable Change in FDC ($ millions) 2,316.9 (422.0) 912.9 Reserve Additions (MMboe) 457.5 167.1 230.7 F&D Costs ($/boe) 11.60 10.79 12.72 11.74 F&D Recycle Ratio(1) 1.3 1.4 1.5 1.4
Finding, Development and Acquisition Costs
Finding, Development and Acquisition 2025 2024 2023 3-Year Avg.
Costs, Excluding
FDC
Total Proved
Reserve Additions (MMboe) 576.7 509.5 482.6
FD&A Costs ($/boe) 6.45 7.09 7.28 6.91
FD&A Recycle Ratio(1) 2.3 2.1 2.7 2.4
Total Proved Plus Probable
Reserve Additions (MMboe) 829.5 698.8 698.0
FD&A Costs ($/boe) 4.48 5.17 5.04 4.87
FD&A Recycle Ratio(1) 3.3 2.9 3.9 3.3
Finding, Development and Acquisition 2025 2024 2023 3-Year Avg.
Costs, Including
FDC
Total Proved
Change in FDC ($ millions) 2,597.7 1,201.6 1,654.1
Reserve Additions (MMboe) 576.7 509.5 482.6
FD&A Costs ($/boe) 10.95 9.44 10.71 10.39
FD&A Recycle Ratio(1) 1.3 1.6 1.8 1.6
Total Proved Plus Probable
Change in FDC ($ millions) 3,820.9 1,473.8 3,326.1
Reserve Additions (MMboe) 829.5 698.8 698.0
FD&A Costs ($/boe) 9.09 7.28 9.80 8.74
FD&A Recycle Ratio(1) 1.6 2.1 2.0 1.9
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 5, 2026 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/4c60ro6 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 5, 2026, a replay will be available by dialing 1-888-660-6345 (international 1-289-819-1450), referencing Replay Code 13689. The recording will expire on March 19, 2026.
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 and business opportunities, including the following: anticipated petroleum and natural gas production and production growth for various periods including estimated average production levels for Q1 2026 and full-year 2026; the reduction in estimated average ethane production levels and estimated increased 2026 and 2027 operating netbacks following the termination of the Company's use of discretionary deep cut gas processing; the use of proceeds from the sale of the Company's PRH Complex and the reduction in operating costs resulting from such sale; the Company's long-term net debt target; the anticipated 2026 full year EP capital program and the reduction thereto, including the impact on production guidance resulting from such reduction; anticipated commodity price improvement; the 2026 EP capital program; 2026 CF and FCF; the expected CF and FCF increases resulting from a U.S. $0.10/mcf tightening of the AECO basis; the expected CF and FCF increases resulting from a U.S. $1.00/mcf increase in both TTF and JKM pricing; production levels, CF, FCF and other information included in the Company's EP Plan; average production volumes exposed to international pricing in 2026 (JKM/TTF); expected interest cost reductions resulting from lower debt levels and the Company's commercial paper program; anticipated capital cost reductions resulting from the vertical integration of the Company's sand business; the anticipated growth, margin expansion and improvement in all operating metrics associated with the NEBC Montney infrastructure and development project; expected total cost reductions that the Company expects to realize by 2031 as a result of operating cost reductions and sand-related capital savings, and the flow through to lower corporate break evens and FCF margin improvement; the number of wells that the Company plans to drill and complete in 2026; the expectation that the EP capital budget reduction will not impact the original start up timing of the Aitken and Groundbirch/Monias gas plant projects in NEBC; the future declaration and payment of base and special dividends and the timing, cadence and
amount thereof; the expansion of Tourmaline's market diversification portfolio; the timing and scale of future growth and developments projects, including the NEBC infrastructure build out; projected operating and drilling costs and drilling times; anticipated future commodity prices; the number of new compressed natural gas fueling stations that are planned for 2026; the expectation that sustained stronger pricing and the Company's ongoing margin improvement activities will lead to further base dividend increases in the future and that special dividends will be used in those periods of extremely strong pricing to return the majority of the incremental FCF to shareholders; as well as Tourmaline's future drilling locations, 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 and interest rates; applicable royalty rates and tax laws; future well production rates and reserve volumes; operating costs, the timing of receipt of regulatory approvals; 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 successful completion of acquisitions and dispositions and the benefits to be derived therefrom; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; ability to maintain its investment grade credit rating; and ability to market crude oil, natural gas and NGL 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, FCF, 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; hazards such as fire, explosion, blowouts, cratering, and spills, any of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; 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, floods 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 and impact 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); and 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 and may be accessed through the SEDAR+ website (www.sedarplus.ca) or Tourmaline's website (www.tourmalineoil.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.
RESERVES DATA
The reserves data set forth above is based upon the reports of GLJ Ltd. ("GLJ") and Deloitte LLP, each dated effective December 31, 2025, 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, 2025 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2026 (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, 2025, which will be filed on SEDAR+ (accessible at www.sedarplus.ca) on or before March 31, 2026.
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, 2025, which will be filed on (SEDAR+ accessible at www.sedarplus.ca) on or before March 31, 2026.
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 2026 CF and FCF and long-term net debt, which are based on, among other things, the various assumptions as to production levels, receipt of drilling permits, capital expenditures and other assumptions disclosed in this news release and, with respect to 2026 CF and FCF and long-term net debt, Tourmaline's estimated average production of 620,000 -- 640,000 boepd, commodity price assumptions for natural gas ($3.85/mmbtu US, $1.88/mcf AECO, $2.49/mmbtu PG&E Citygate U.S., $13.00/mcf JKM U.S.), crude oil ($66.77/bbl WTI U.S.) and an exchange rate assumption (USD/CAD) of $0.74. In addition, such estimates are provided for illustration only and are based on budgets and forecasts as of the date hereof that are subject to change and a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they are included to provide readers with an understanding of Tourmaline's anticipated CF and FCF and long-term net 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", "EP 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", and "cash flow per-boe", 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
December 31, December 31,
(000s) 2025 2024 2025 2024
Cash flow from operating
activities (per GAAP) $700,112 $666,110 $3,387,019 $2,729,780
Current income taxes(1) (11,039) (36,665) (33,228) (65,173)
Current income taxes paid
(recovered) 3,246 (34) 31,382 526,768
Change in non-cash working
capital (deficit) 197,798 220,919 10,397 27,116
Cash flow $ 890,117 $850,330 $ 3,395,570 $ 3,218,491
(1) For the purposes of this reconciliation, current income
taxes exclude $11.3 million of income taxes related
to the capital gain on the sale of Topaz shares during
the three and twelve months ended December 31, 2025
(three and twelve months ended December 31, 2024 -
$19.0M). Refer to Notes 11 and 14 of the Company's
consolidated financial statements as at and for the
year ended December 31, 2025 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
December 31, December 31,
(000s) 2025 2024 2025 2024
Cash flow used in investing
activities (per GAAP) $ 523,856 $ 123,552 $2,733,529 $ 1,638,627
Corporate acquisitions -- (169,040) -- (169,040)
Change in non-cash working
capital 82,904 174,216 (10,675) 100,409
Investment in long-term asset -- -- (11,800) --
Proceeds from sale of
investments 221,226 331,465 221,226 331,465
Capital expenditures $ 827,986 $ 460,193 $2,932,280 $ 1,901,461
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 production expenditures is set forth below:
Three Months Ended Years Ended
December 31, December 31,
(000s) 2025 2024 2025 2024
Cash flow used in investing
activities (per GAAP) $ 523,856 $123,552 $2,733,529 $ 1,638,627
Change in non-cash working
capital 82,904 174,216 (10,675) 100,409
Proceeds from sale of
investments 221,226 331,465 221,226 331,465
Corporate acquisitions -- (169,040) -- (169,040) Investment in long-term asset -- -- (11,800) -- Property acquisitions (2,024) (7,379) (19,307) (33,083) Proceeds from divestitures 801 300,858 75,622 357,692 Other (14,028) (10,256) (62,883) (52,607) Exploration and production expenditures $ 812,735 $ 743,416 $2,925,712 $ 2,173,463
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
December 31, December 31,
(000s) 2025 2024 2025 2024
Cash flow $ 890,117 $850,330 $3,395,570 $ 3,218,491
Capital expenditures (827,986) (460,193) (2,932,280) (1,901,461)
Property acquisitions 2,024 7,379 19,307 33,083
Proceeds from divestitures (801) (300,858) (75,622) (357,692)
Free Cash Flow $63,354 $ 96,658 $ 406,975 $992,421
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 gain 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
December 31, December 31,
(000s) 2025 2024 2025 2024
Commodity sales from
production $ 1,423,017 $1,215,050 $4,940,024 $4,729,771
Premium on risk management
activities 202,830 280,791 1,230,294 828,468
Realized gain on financial
instruments 88,813 127,978 420,981 486,534
Royalties (135,121) (125,699) (513,879) (509,252)
Transportation costs (306,801) (276,602) (1,198,061) (1,082,592)
Operating expenses (282,530) (251,594) (1,148,182) (1,006,541)
Operating netback $ 990,208 $969,924 $3,731,177 $3,446,388
Non-GAAP Financial Ratios
Operating Netback per-boe
Management calculates "operating netback per-boe" as operating netback divided by total production for the period. Operating netback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas producers. A summary of the calculation of operating netback per boe is set forth below:
Three Months Ended Years Ended
December 31, December 31,
($/boe) 2025 2024 2025 2024
Revenue, excluding processing income $ 28.27 $ 29.15 $ 28.30 $ 28.52
Royalties (2.23) (2.26) (2.21) (2.40)
Transportation costs (5.06) (4.97) (5.14) (5.11)
Operating expenses (4.66) (4.52) (4.93) (4.75)
Operating netback $ 16.32 $ 17.40 $ 16.02 $ 16.26
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) 2025 2024
Working capital (deficit) $ (419,306) $ (167,623)
Fair value of financial instruments -- short-term
(asset) (135,676) (315,365)
Lease liabilities -- short-term 8,034 8,385
Decommissioning obligations -- short-term 75,000 60,000
Unrealized foreign exchange in working capital --
(asset) liability 991 (15,354)
Adjusted working capital (deficit) $ (470,957) $(429,957)
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) 2025 2024
Long-term debt $ (1,052,914) $ (1,272,775)
Adjusted working capital (deficit) (470,957) (429,957)
Net debt $ (1,523,871) $ (1,702,732)
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 26,512 (gross) locations disclosed in this news release, 2,316 are proved undeveloped locations (including drilled-uncompleted locations ("DUCs")), 1,757 are probable undeveloped locations, and 22,439 are unbooked. Proved producing wells, proved undeveloped locations, including DUCs, and probable undeveloped 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, 2025, 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
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