REG-Gran Tierra Energy Inc. Announces 2025 Fourth Quarter & Year-End Results
04/03/2026 24:00
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* Achieved Average Working Interest Fourth Quarter Production of 46,344 BOEPD
* Realized 2025 Adjusted EBITDA(1) of $284 Million
* Delivered Net Cash Provided by Operating Activities of $313 Million, up 31%
from 2024
* Generated 2025 Funds Flow from Operations(1 )of $178 Million
* Seventh Consecutive Year of South American Reserves Growth With Over 100%
Reserve Replacement PDP & 2P
* Achieved Company’s Best Safety Performance on Record in 2025
* Subsequent to Year-End Completed a Bond Exchange, Sold Non-Core Assets and
Signed an Agreement in Azerbaijan
CALGARY, Alberta, March 03, 2026 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc.
(“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE)
(LSE:GTE) today announced the Company’s financial and operating results for
the fourth quarter (“the Quarter”) and year ended December 31, 2025. Gran
Tierra’s 2025 year-end reserves were evaluated by the Company's independent
qualified reserves evaluator McDaniel & Associates Consultants Ltd.
(“McDaniel”) in a report with an effective date of December 31, 2025 (the
“GTE McDaniel Reserves Report”). All reserves values, future net revenue
and ancillary information contained in this press release have been prepared
by McDaniel and calculated in compliance with Canadian National Instrument
51-101 – Standards of Disclosure for Oil and Gas Activities (“NI
51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and
derived from the GTE McDaniel Reserves Report, unless otherwise expressly
stated. The following reserves categories are discussed in this press release:
Proved Developed Producing (“PDP”), Proved (“1P”), 1P plus Probable
(“2P”) and 2P plus Possible (“3P”). All dollar amounts are in United
States (“U.S.”) dollars and all production volumes are on an average
working interest before royalties (“WI”) basis unless otherwise indicated.
Production is expressed in barrels (“bbl”) of oil equivalent (“boe”)
per day (“boepd” or “boe/d”) and are based on WI sales before
royalties. Reserves are expressed in boe or million boe (“MMBOE”), unless
otherwise indicated. For per boe amounts based on net after royalty
(“NAR”) production, see Gran Tierra’s Annual Report on Form 10-K filed
March 4, 2026.
Message to Shareholders
Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented:
“We exited 2025 in a position of operational strength and enhanced financial
flexibility. The successful exchange of our 9.500% Senior Secured Amortizing
Notes due 2029, with approximately 88% participation, demonstrates strong
bondholder confidence in Gran Tierra and our strategy. The exchange extended
our maturity profile and reduced total bond debt outstanding while
strengthening our capital structure. Together with the prepayment facility and
non-core asset sales, this significantly enhances our liquidity and provides
greater flexibility to allocate capital and accelerate deleveraging as we
enter 2026.
These actions provide a clear path toward deleveraging while we execute on a
clear development plan across the portfolio. Over the past several years, our
team has assembled a diversified, high-quality asset base across South America
and Canada. That portfolio build-out required disciplined investment and the
strategic use of leverage to secure long-life, high-quality assets with a
focus on portfolio longevity. With the portfolio now established, our focus
shifts to optimizing and developing those assets while steadily reducing debt
and maximizing free cash flow. As we close out 2025, we look toward a 2026
program centered on disciplined development and capital allocation, leveraging
our technical capabilities across the portfolio to deliver stable production
growth and free cash flow.”
Operational:
* Production: * Gran Tierra achieved 2025 average WI production of 45,709
BOEPD, representing a 32% increase from 2024, as a result of positive
exploration well results in Ecuador, full year production from the Canadian
operations, partially offset by lower production in Southern Colombia and
Ecuador as a result of two major export pipeline disruptions, and trunk line
repairs at the Moqueta field which resulted in the field being shut-in during
the third quarter of 2025.
* The Quarter: Gran Tierra produced an average WI production of 46,344 BOEPD,
a 13% increase from the fourth quarter 2024 and a 9% increase from the third
quarter 2025 (“the Prior Quarter”).
* Commitments: Gran Tierra significantly reduced its capital commitments in
both Ecuador and Colombia during the year. In Ecuador, the Company completed
all Phase 1 commitments and submitted the required Field Development Plans,
fully securing its country entry. In Colombia, commitments were streamlined
through targeted portfolio and work program revisions. Together with ongoing
debt reduction, these actions reduced letters of credit and obligations,
materially improving liquidity and enhancing capital allocation flexibility
going forward.
* 2026 Suroriente Drilling Campaign: The Company recently drilled the Raju-2
well on the Suroriente Block, targeting the northern extent of the Cohembi
field. The well is currently producing at a rate of approximately 790 barrels
of oil per day, 6 barrels of water per day and 0.6 thousand cubic feet of gas
per day and is on track to exceed management’s initial 30-day production
expectations. Raju-2 further delineates the productive limits of the field
while reinforcing the development potential of the broader Cohembi structure.
The well is part of is part ofthe capital carry commitment associated with
Suroriente and with three wells remaining, the Company expects to complete the
remaining capital carry by the middle of 2026.
* Azerbaijan Entry: Gran Tierra entered into an exploration, development and
production sharing agreement (“EDPSA”) with the State Oil Company of the
Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest
to Gran Tierra and 35% to SOCAR. The EDPSA includes a five-year exploration
phase and upon a commercial discovery, a 25-year development phase. Minimum
exploration commitments to be completed within 36 months include the
acquisition of 250 square kilometres of 3D seismic, the drilling of two
exploration wells, and geological and environment impact studies.
2025 Year-End Reserves and Values(2):
Before Tax (as of December 31, 2025) Units 1P 2P 3P
Reserves MMBOE 142 258 329
Net Present Value at 10% Discount (“NPV10”) $ million 1,456 2,461 3,317
Net Debt* $ million (658) (658) (658)
Net Asset Value (NPV10 less Net Debt) (“NAV”) (3) $ million 798 1,803 2,659
Outstanding Shares (4) million 35.30 35.30 35.30
NAV per Share (3) $/share 22.61 51.08 75.33
After Tax (as of December 31, 2025) Units 1P 2P 3P
Reserves MMBOE 142 258 329
NPV10 $ million 1,138 1,758 2,283
Net Debt* $ million (658) (658) (658)
NAV (3) $ million 480 1,100 1,625
Outstanding Shares (4) million 35.30 35.30 35.30
NAV per Share (3) $/share 13.61 31.17 46.05
* As of December 31, 2025, Gran Tierra achieved(2,3): * Before Tax NAV of $0.8
billion (1P), $1.8 billion (2P), and $2.7 billion (3P)
* After Tax NAV of $0.5 billion (1P), $1.1 billion (2P), and $1.6 billion (3P)
* Reserve Life Index**: * 1P: 8 years
* 2P: 15 years
* 3P: 19 years
* South American reserves replacement*** of: * 101% PDP, with PDP reserves
additions of 11 MMBOE.
* 61% 1P, with 1P reserves additions of 6 MMBOE.
* 105% 2P, with 2P reserves additions of 11 MMBOE.
* Canadian reserves replacement was negative as a result of the
reclassification of certain reserves to contingent resources due to lower
forecasted gas prices.
* Canada now represents 39% of 1P and 44% of 2P reserves compared to Gran
Tierra’s total reserves.
* Future development costs (“FDC”) are forecasted by McDaniel to be $888
million for 1P reserves and $1,682 million for 2P reserves. Decreases in FDC
relative to 2024 year-end reflect that the GTE McDaniel Reserves Report now
assigns Gran Tierra 168 Proved Undeveloped future drilling locations (down
from 227 at 2024 year-end with 62 Glauconitic locations moved to contingent
resources) and 362 Proved plus Probable Undeveloped future drilling locations
(down from 441 at 2024 year-end with 74 Glauconitic locations moved to
contingent).
(*Comprised of Senior Notes of $741 million (gross) less cash and cash
equivalents of $83 million, prepared in accordance with GAAP. See “Non-GAAP
Measures”.**The reserve life indexes were calculated based on a Q4 2025
total average production rate of 46,344 BOEPD.)
(***Reserves replacement were calculated based on an annual basis using South
America average production rate of 29,023 BOEPD.)
Financial:
* 2025 Net Income: Gran Tierra realized a net loss of $193.1 million or $5.45
per share (basic and diluted), which included non-cash ceiling test impairment
losses of $136.3 million, compared to net income of $3.2 million, or $0.10 per
share (basic and diluted) in 2024.
* 2025 Adjusted EBITDA(1): The Company realized Adjusted EBITDA(1) of $283.7
million, a decrease of 23% from $366.8 million in 2024, commensurate with the
decrease in the Brent oil price.
* 2025 Net Cash Provided by Operating Activities: The Company generated net
cash provided by operating activities of $313.2 million, an increase of 31%
from $239.3 million in 2024.
* 2025 Funds Flow from Operations(1): Gran Tierra realized funds flow from
operations(1) of $177.8 million, compared to $224.9 million in 2024.
* 2025 Capital Expenditures: Capital expenditures increased by $8.2 million or
3% to $256.3 million compared to 2024 due to a higher number of wells drilled
in 2025 in Colombia, Ecuador, and Canada, which was predominately funded by
the Company’s 2025 net cash provided by operating activities of $313.2
million.
* Key Metrics During the Quarter: The Company realized a net loss of $141.1
million, Adjusted EBITDA(1 )of $52.5 million, and funds flow from
operations(1) of $26.8 million in the Quarter, compared with a net loss of
$20.0 million, Adjusted EBITDA(1 )of $69.0 million, and funds flow from
operations(1) of $41.7 million in the Prior Quarter. The Company recognized
quarterly production of 46,344 BOEPD.
* Cash Balance: The Company had $82.9 million in cash and cash equivalents as
at December 31, 2025, a decrease compared to a cash balance of $103.4 million
as at December 31, 2024.
* Bonds Buybacks: During 2025, Gran Tierra bought back approximately $21.3
million in face value of the Company’s 9.50% senior notes due October 15,
2029. This represents a discount of about 20% to the face value of the
repurchased bonds.
* Share Buybacks: Since January 1, 2022, through its NCIB programs, the
Company has re-purchased approximately 7.5 million shares of Common Stock,
representing about 21% of shares outstanding as of December 31, 2025.
* 2025 Operating Costs: Total operating expenses were $248.7 million, compared
to $202.3 million in 2024, representing a 23% increase while operating
expenses per boe were $15.17, 6% lower when compared to 2024. The increase in
total operating expenses in 2025 was a result of higher operating costs in
Ecuador driven by a production ramp-up in 2025, and the full year of Canadian
operations.
* 2025 Cash General and Administrative Costs: The Company’s gross cash
general and administrative (“G&A”) costs increased to $3.47 per boe from
$3.30 per boe in 2024. Total cash G&A costs were $56.9 million, an increase of
37% from $41.4 million in 2024, driven by a full year of G&A expenses from
Canadian operations, higher business development costs, and consulting costs
attributed to optimization projects.
* Oil, Natural Gas and Natural Gas Liquids (“NGL”) Sales: * 2025: Gran
Tierra’s oil, natural gas and NGL sales decreased 4% to $596.7 million,
compared to $621.8 million in 2024. This decrease was primarily driven by a
15% decrease in Brent price and a 19% decrease in sales volumes in Colombia,
offset by higher sales volumes in Ecuador, lower differentials, and a full
year of sales from Canadian operations.
* The Quarter: Gran Tierra generated oil, natural gas and NGL sales of $129.9
million, a decrease of 13% or $19.3 million from the Prior Quarter, primarily
driven by a 7% decrease in the Brent oil price, offsetting a 13% increase in
production. Oil, natural gas and NGL sales were $32.95 per boe, a 10% decrease
from the Prior Quarter primarily as a result of lower oil prices and lower
natural gas prices in Canada. Sales in the Quarter were impacted by the timing
of a lifting in Ecuador that deferred approximately $15 million of revenue,
which was recognized in early January 2026.
* Operating Netback(1): * 2025: Gran Tierra’s operating netback(1) of $20.18
per boe was down 37% from $31.99 in 2024.
* The Quarter: The Company’s operating netback(1) of $17.53 per boe was
lower by 21% from the fourth quarter 2024 and a decrease of 7% from the Prior
Quarter due to increased weighting to natural gas in Canada and lower oil
prices.
Closing of Bond Exchange and Upsized Prepayment Facility:
* Subsequent to December 31, 2025, Gran Tierra successfully closed its
previously announced bond exchange, achieving approximately 88% participation,
reflecting strong bondholder confidence in the Company’s asset base,
strategy and long-term credit profile. The Company exchanged $629 million of
its 9.500% Senior Secured Amortizing Notes due 2029 for $504 million of new
9.750% Senior Secured Amortizing Notes maturing April 15, 2031, with a
structured amortization profile beginning in 2029. In connection with the
exchange, the Company paid $125.0 million in cash consideration and cancelled
the tendered and treasury-held notes. On a pro forma basis, reflecting the
exchange, Gran Tierra’s net debt is approximately $533(8) million. The
Company also amended and expanded its oil offtake and prepayment agreement
with Trafigura to a facility of up to $350.0 million, enhancing liquidity and
extending maturities while further strengthening the balance sheet.
Gran Tierra’s Commitment to Go “Beyond Compliance” with Safe and
Sustainable Operations
* 2025 was the Company’s safest year on record. Gran Tierra has accumulated
a total of 37.2 million person-hours without a Lost Time Injury (LTI), and in
2025, the Company’s Total Recordable Incident Frequency (TRIF) was 0.02,
placing Gran Tierra in the top quartile for safety performance across its
operating regions.
* Gran Tierra opened the Acordionero Forestry Centre in El Cairo, Cesar,
Colombia — the Company’s second forestry centre dedicated to biodiversity,
conservation, sustainable agricultural management and environmental
innovation. Nearly 11,000 native trees have already been planted at the site,
and the nursery produces approximately 9,000 plants per month, reinforcing its
contribution to regional ecosystem recovery. The Centre also features a
solar-powered aquaponics system that operates as a closed loop: tilapia waste
fertilizes soil-free crops while water is continuously recycled, reducing
water use by more than 90% compared with traditional farming.
* Launched in 2017 in Colombia, Gran Tierra’s flagship program
NaturAmazonas, has evolved into much more than a traditional conservation
project. While Gran Tierra has consistently expanded our reforestation efforts
to exceed initial targets, the program now also integrates the local economy
into it. Gran Tierra has grown to support over 800 local families in
deforestation-free cacao farming, connected them with international buyers and
has trained over 420 local beekeepers to produce sustainable honey from native
bee species.
* Throughout all of Gran Tierra’s environmental initiatives, Gran Tierra has
planted over 1.9 million trees and restored or protected over 5,600 hectares
of land so far.
* More than 400,000 people have benefited from Gran Tierra’s social
investment programs in South America to date.
* As part of the Works for Taxes program, Gran Tierra is building four major
infrastructure projects in Putumayo, including a new aqueduct that will
deliver potable water to 1,300 residents in the municipalities of Mocoa, Valle
del Guamuez and Puerto Asís. Other initiatives include rural road upgrades
benefiting 24,000 local residents and improvements to local school facilities.
* Gran Tierra has been accepted by the Voluntary Principles Initiative as an
official member of the Voluntary Principles for Security and Human Rights
world-wide initiative. This membership is a recognition of Gran Tierra’s
efforts at respecting and promoting human dignity and provides support to
improve the Company’s security and Human Rights performance.
Corporate Presentation:
* Gran Tierra’s Corporate Presentation has been updated and is available at
www.grantierra.com.
Financial and Operational Highlights(5) (all amounts in $000s, except per
share and boe amounts)
Consolidated Information Year Ended Three Months Ended
December 31, December 31, December 31, December 31, September 30,
2025 2024 2025 2024 2025
Net (Loss) Income $ (193,119 ) $ 3,216 $ (141,148 ) $ (34,210 ) $ (19,950 )
Net (Loss) Income Per Share - Basic $ (5.45 ) $ 0.10 $ (4.00 ) $ (1.04 ) $ (0.57 )
Net (Loss) Income Per Share - Diluted $ (5.45 ) $ 0.10 $ (4.00 ) $ (1.04 ) $ (0.57 )
Operating Netback (1)
Gross Profit (6) $ 66,419 $ 182,637 $ 851 $ 22,180 $ 14,670
Depletion and Accretion (7) 264,522 218,417 68,236 60,061 61,908
Operating Netback (1) $ 330,941 $ 401,054 $ 69,087 $ 82,241 $ 76,578
Oil, Natural Gas and NGL Sales $ 596,713 $ 621,849 $ 129,929 $ 147,290 $ 149,254
Operating Expenses (248,748 ) (202,331 ) (57,160 ) (60,770 ) (68,379 )
Transportation Expenses (17,024 ) (18,464 ) (3,682 ) (4,279 ) (4,297 )
Operating Netback (1) $ 330,941 $ 401,054 $ 69,087 $ 82,241 $ 76,578
G&A Expenses Before Stock-based Compensation $ 56,873 $ 41,431 $ 16,817 $ 8,672 $ 13,453
G&A Expenses Stock-Based Compensation 3,214 9,707 3,042 3,331 143
G&A Expenses, Including Stock-Based Compensation $ 60,087 $ 51,138 $ 19,859 $ 12,003 $ 13,596
EBITDA (1) $ 146,790 $ 355,690 $ (77,030 ) $ 65,247 $ 59,202
Adjusted EBITDA (1) $ 283,656 $ 366,758 $ 52,473 $ 76,168 $ 69,034
Net Cash Provided by Operating Activities $ 313,249 $ 239,321 $ 157,193 $ 26,607 $ 48,149
Funds Flow from Operations (1) $ 177,762 $ 224,941 $ 26,827 $ 44,129 $ 41,685
Capital Expenditures (Before Changes in Working Capital) $ 256,277 $ 248,103 $ 53,040 $ 78,579 $ 57,340
Free Cash Flow (1) $ (78,515 ) $ (23,162 ) $ (26,213 ) $ (34,450 ) $ (15,655 )
Average Daily Volumes (BOEPD)
Working Interest Production Before Royalties 45,709 34,710 46,344 41,009 42,685
Royalties (7,266 ) (6,820 ) (6,880 ) (7,327 ) (6,723 )
Production NAR 38,443 27,890 39,464 33,682 35,962
(Decrease) Increase in Inventory (779 ) (454 ) (3,480 ) (712 ) 1,391
Sales 37,664 27,436 35,984 32,970 37,353
Royalties, % of WI Production Before Royalties 16 % 20 % 15 % 18 % 16 %
Per boe (5)
Gross Profit (6) $ 4.05 $ 14.57 $ 0.22 $ 5.98 $ 3.62
Depletion and Accretion (7) 16.13 17.42 17.30 16.20 15.27
Operating Netback ((1)(5)) $ 20.18 $ 31.99 $ 17.53 $ 22.19 $ 18.89
Brent $ 68.19 $ 79.86 $ 63.08 $ 74.01 $ 68.17
Quality and Transportation Discount (24.78 ) (17.93 ) (23.83 ) (25.45 ) (24.73 )
Royalties (7.02 ) (12.33 ) (6.30 ) (8.83 ) (6.63 )
Average Realized Price $ 36.39 $ 49.60 $ 32.95 $ 39.73 $ 36.81
Transportation Expenses (1.04 ) (1.47 ) (0.93 ) (1.15 ) (1.06 )
Average Realized Price Net of Transportation Expenses $ 35.35 $ 48.13 $ 32.02 $ 38.58 $ 35.75
Operating Expenses (15.17 ) (16.14 ) (14.49 ) (16.39 ) (16.86 )
Operating Netback (1) $ 20.18 $ 31.99 $ 17.53 $ 22.19 $ 18.89
Cash G&A Expenses (3.47 ) (3.30 ) (4.26 ) (2.75 ) (3.32 )
Transaction Costs — (0.47 ) — (1.20 ) —
Export Tax (0.20 ) — (0.17 ) — (0.65 )
Realized Foreign Exchange (Loss) Gain (0.47 ) 0.07 (0.71 ) 0.07 (0.53 )
Cash Settlement on Derivative Instruments 0.63 0.09 0.19 0.30 1.84
Interest Expense, Excluding Amortization of Debt Issuance Costs (5.02 ) (5.38 ) (5.45 ) (5.40 ) (5.22 )
Interest Income 0.07 0.29 0.06 0.34 0.05
Other Cash Gain 0.10 0.12 — 0.40 0.31
Net Lease Payments (0.01 ) 0.07 (0.03 ) 0.07 (0.10 )
Current Income Tax (Expense) Recovery (0.97 ) (5.53 ) (0.35 ) (2.12 ) (0.99 )
Cash Netback (1) $ 10.84 $ 17.95 $ 6.81 $ 11.90 $ 10.28
Share Information (000s)
Common Stock Outstanding, End of Period 35,299 35,972 35,299 35,972 35,296
Weighted Average Number of Common - Basic 35,436 32,043 35,294 34,333 35,291
Weighted Average Number of Common - Diluted 35,436 32,043 35,294 34,333 35,291
Colombia Information Year Ended, Three Months Ended,
December 31, December 31, December 31, December 31, September 30,
2025 2024 2025 2024 2025
Operating Netback ((1)(5))
Gross Profit (6) $ 53,685 $180,605 $ (2,865 ) $21,728 $10,237
Depletion and Accretion (7) 186,319 199,323 49,383 47,858 44,041
Operating Netback ((1)(5)) $ 240,004 $379,928 $ 46,518 $69,586 $54,278
Oil Sales $ 418,411 $575,482 $ 89,072 $119,310 $101,999
Operating Expenses (165,902 ) (179,257) (39,897 ) (46,614) (44,819)
Transportation Expenses (12,505 ) (16,297) (2,657 ) (3,110) (2,902)
Operating Netback ((1)(5)) $ 240,004 $379,928 $ 46,518 $69,586 $54,278
Capital Expenditures (Before Changes in Working Capital) $ 149,138 $126,867 $ 32,858 $28,855 $32,573
Average Daily Production (BOEPD)
WI Production Before Royalties 24,169 29,389 23,258 25,990 22,701
Royalties (3,685 ) (5,545) (3,013 ) (4,548) (3,481)
Production NAR 20,484 23,844 20,245 21,442 19,220
Increase (Decrease) in Inventory (210 ) 53 (908 ) 245 337
Sales 20,274 23,897 19,337 21,687 19,557
Royalties, % of WI Production Before Royalties 15 % 19% 13 % 17% 15%
Operating Netback ($/boe) ((1)(5))
Gross Profit (6) $ 6.14 $16.76 $ (1.39 ) $9.00 $4.83
Depletion and Accretion (7) 21.31 18.50 24.02 19.83 20.78
Operating Netback ((1)(5)) $ 27.44 $35.26 $ 22.63 $28.83 $25.60
Brent $ 68.19 $79.86 $ 63.08 $74.01 $68.17
Quality and Transportation Discount (11.65 ) (14.06) (13.01 ) (14.21) (11.48)
Royalties (8.70 ) (12.39) (6.75 ) (10.37) (8.57)
Average Realized Price 47.84 53.41 43.32 49.43 48.12
Transportation Expenses (1.43 ) (1.51) (1.29 ) (1.29) (1.37)
Average Realized Price Net of Transportation Expenses 46.41 51.90 42.03 48.14 46.75
Operating Expenses (18.97 ) (16.64) (19.40 ) (19.31) (21.15)
Operating Netback ((1)(5)) $ 27.44 $35.26 $ 22.63 $28.83 $25.60
Ecuador Information Year Ended, Three Months Ended,
December 31, December 31, December 31, December 31, September 30,
2025 2024 2025 2024 2025
Operating Netback ((1)(5))
Gross Profit (6) $ 5,479 $2,336 $ 3,678 $756 $859
Depletion and Accretion (7) 29,624 10,156 5,258 3,265 9,519
Operating Netback ((1)(5)) $ 35,103 $12,492 $ 8,936 $4,021 $10,378
Oil Sales $ 62,609 $27,412 $ 12,486 $9,025 $20,605
Operating Expenses (24,270 ) (13,425) (2,918 ) (4,507) (9,157)
Transportation Expenses (3,236 ) (1,495) (632 ) (497) (1,070)
Operating Netback ((1)(5)) $ 35,103 $12,492 $ 8,936 $4,021 $10,378
Capital Expenditures (Before Changes in Working Capital) $ 62,275 $102,377 $ 16,197 $31,416 $15,474
Average Daily Production (BOEPD)
WI Production Before Royalties 4,854 2,477 6,898 3,705 3,872
Royalties (1,497 ) (881) (1,925 ) (1,213) (1,273)
Production NAR 3,357 1,596 4,973 2,492 2,599
Increase (Decrease) in Inventory (569 ) (507) (2,572 ) (957) 1,054
Sales 2,788 1,089 2,401 1,535 3,653
Royalties, % of WI Production Before Royalties 31 % 36% 28 % 33% 33%
Operating Netback ($/boe) ((1)(5))
Gross Profit (6) $ 3.50 $3.24 $ 9.24 $2.99 $1.90
Depletion and Accretion (7) 18.94 14.08 13.21 12.91 21.00
Operating Netback ((1)(5)) $ 22.44 $17.33 $ 22.45 $15.90 $22.90
Brent $ 68.19 $79.86 $ 63.08 $74.01 $68.17
Quality and Transportation Discount (6.66 ) (11.06) (6.56 ) (10.09) (6.88)
Royalties (21.50 ) (30.78) (25.15 ) (28.22) (15.83)
Average Realized Price 40.03 38.02 31.37 35.70 45.46
Transportation Expenses (2.07 ) (2.07) (1.59 ) (1.97) (2.36)
Average Realized Price Net of Transportation Expenses 37.96 35.95 29.78 33.73 43.10
Operating Expenses (15.52 ) (18.62) (7.33 ) (17.83) (20.20)
Operating Netback ((1)(5)) $ 22.44 $17.33 $ 22.45 $15.90 $22.90
Canadian Information Year Ended, Three Months Ended,
December 31, December 31, December 31, December 31, September 30,
2025 2024 2025 2024 2025
Operating Netback ((1)(5))
Gross Profit (6) $ 7,255 $(304) $ 38 $(304) $3,574
Depletion and Accretion (7) 48,579 8,938 13,595 8,938 8,348
Operating Netback ((1)(5)) $ 55,834 $8,634 $ 13,633 $8,634 $11,922
Oil Sales $ 84,769 $14,832 $ 19,785 $14,832 $21,884
Natural Gas Sales 23,940 3,546 4,026 4,193 4,314
NGL Sales 20,275 4,193 7,477 3,546 3,702
Royalties (13,291 ) (3,616) (2,917 ) (3,616) (3,250)
Oil, Natural Gas and NGL Sales After Royalties $ 115,693 $18,955 $ 28,371 $18,955 $26,650
Operating Expenses (58,576 ) (9,649) (14,345 ) (9,649) (14,403)
Transportation Expenses (1,283 ) (672) (393 ) (672) (325)
Operating Netback ((1)(5)) $ 55,834 $8,634 $ 13,633 $8,634 $11,922
Capital Expenditures (Before Changes in Working Capital) $ 44,096 $18,114 $ 3,712 $18,114 $9,228
Average Daily Production
Crude Oil (bbl/d) 4,049 627 4,220 2,486 4,013
Natural Gas (mcf/d) 48,840 8,274 46,158 32,814 49,260
NGLs (bbl/d) 4,496 847 4,274 3,358 3,889
WI Production Before Royalties (BOEPD) 16,685 2,853 16,187 11,313 16,112
Royalties (BOEPD) (2,083 ) (394) (1,942 ) (1,566) (1,969)
Production NAR (BOEPD) 14,602 2,459 14,245 9,747 14,143
Sales (BOEPD) 14,602 2,459 14,245 9,747 14,143
Royalties, % of WI Production Before Royalties 12 % 14% 12 % 14% 12%
Benchmark Prices
West Texas Intermediate ($/bbl) $ 64.87 $69.62 $ 59.24 $69.62 $65.07
AECO Natural Gas Price (C$/GJ) $ 1.59 $1.56 $ 2.11 $1.56 $0.60
Average Realized Price
Crude Oil ($/bbl) $ 57.35 $64.86 $ 50.96 $64.86 $59.28
Natural Gas ($/mcf) $ 1.34 $1.17 $ 1.76 $1.17 $0.82
NGLs ($/bbl) $ 12.36 $13.57 $ 10.24 $13.57 $12.06
Operating Netback ($/boe) ((1)(5))
Gross Profit (6) $ 1.19 $(0.29) $ 0.03 $(0.29) $2.41
Depletion and Accretion (7) 7.98 8.59 9.13 8.59 5.63
Operating Netback ((1)(5)) $ 9.17 $8.30 $ 9.16 $8.30 $8.04
Average Realized Price $ 21.18 $21.69 $ 21.01 $21.69 $20.17
Royalties (2.18 ) (3.47) (1.96 ) (3.47) (2.19)
Transportation Expenses (0.21 ) (0.65) (0.26 ) (0.65) (0.22)
Operating Expenses (9.62 ) (9.27) (9.63 ) (9.27) (9.72)
Operating Netback ((1)(5)) $ 9.17 $8.30 $ 9.16 $8.30 $8.04
As at December 31
($000s) 2025 2024 % Change
Cash and cash equivalents $ 82,931 $ 103,379 (20 )
Credit facility $ — $ — —
Senior Notes $ 740,541 $ 786,619 (6 )
Additional information on 2025 expenses:
* Quality and Transportation Discount: increased in 2025 to $24.78 per boe
compared to $17.93 per boe in 2024 as a result of a change in production mix,
driven by the full integration of Canadian operations acquired in October
2024.
* Transportation Expenses: decreased by 29% to $1.04 per boe in 2025 from
$1.47 per boe in 2024 as a result of higher sales volumes transported in
Ecuador, two months of transportation of sales volumes in Canada through
pipelines, and an increase in trucking tariffs for Acordionero volumes in
2025.
* Royalties: decreased to $7.02 per boe in 2025, from $12.33 per boe in 2024.
This decrease was driven by the 15% decrease in the Brent oil price in 2025
relative to 2024 and the price sensitive royalty regime in Colombia and
Ecuador.
(1 Operating netback, EBITDA, Adjusted EBITDA, funds flow from operations, net
debt, free cash flow, and cash netback, are non-GAAP measures and do not have
a standardized meaning under GAAP. Cash flow refers to the GAAP line item
“net cash provided by operating activities”. Refer to “Non-GAAP
Measures” in this press release for descriptions of these non-GAAP measures
and reconciliations to the most directly comparable measures calculated and
presented in accordance with GAAP. )
(2 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. It does not
consider the corporate tax situation, or tax planning. It does not provide an
estimate of the value at the Company level which may be significantly
different. The Company’s financial statements should be consulted for
information at the Company level. )
(3 NAV per share is calculated as NPV10 (before or after tax, as applicable)
of the applicable reserves category minus net debt, divided by the number of
shares of Gran Tierra’s common stock issued and outstanding. )
(4 Outstanding shares of common stock based on December 31, 2025 balance of
35,298,774 shares of common stock. )
(5 Per boe amounts are based on WI sales before royalties. For per boe amounts
based on NAR production, see Gran Tierra’s Annual Report on Form 10-K filed
on March 4, 2026. )
(6 Gross profit is calculated as oil, gas and NGL sales, less operating and
transportation expenses, and depletion and accretion related to producing
assets. )
(7 Depletion and Accretion is calculated as DD&A expenses less depreciation of
administrative assets. )
(8 Proforma Net Debt is based on $616 million outstanding of Senior Notes less
$83 million of cash and cash equivalents as at December 31, 2025.)
Conference Call Information
Gran Tierra will host its fourth quarter and full year 2025 results conference
call on Wednesday March 4, 2026, at 9:00 a.m. Mountain Time, 11:00 a.m.
Eastern Time, and 4:00 p.m. Greenwich Mean Time. Interested parties may
register for the conference call at the following link:
https://register-conf.media-server.com/register/BIea135c3b51d44c9cb4d060ac04b977dd.
Please note that there is no longer a general dial-in number to participate
and each individual party must register through the provided link. Once
parties have registered, they will be provided a unique PIN and call-in
details. There is also a feature that allows parties to elect to be called
back through the “Call Me” function on the platform. Interested parties
can also continue to access the live webcast from their mobile or desktop
devices at the following link: https://edge.media-server.com/mmc/p/ruvvrgwq,
which is also available on Gran Tierra’s website at
https://www.grantierra.com/investor-relations/presentations-events/.
About Gran Tierra Energy Inc.
Gran Tierra Energy Inc., together with its subsidiaries, is an independent
international energy company currently focused on oil and natural gas
exploration and production in Canada, Colombia and Ecuador. The Company is
currently developing its existing portfolio of assets in Canada, Colombia and
Ecuador; however, we have recently entered into an exploration, development
and production sharing agreement with SOCAR and may eventually expand our
operations into Azerbaijan and will continue to pursue additional new growth
opportunities that would further strengthen the Company’s portfolio. The
Company’s common stock trades on the NYSE American, the Toronto Stock
Exchange and the London Stock Exchange under the ticker symbol GTE. Additional
information concerning Gran Tierra is available at www.grantierra.com. Except
to the extent expressly stated otherwise, information on the Company’s
website or accessible from our website or any other website is not
incorporated by reference into and should not be considered part of this press
release. Investor inquiries may be directed to info@grantierra.com or (403)
265-3221.
Gran Tierra’s Securities and Exchange Commission (the “SEC”) filings are
available on the SEC website at http://www.sec.gov. The Company’s Canadian
securities regulatory filings are available on SEDAR+ at
http://www.sedarplus.ca and UK regulatory filings are available on the
National Storage Mechanism website at
https://data.fca.org.uk/#/nsm/nationalstoragemechanism.
Contact Information
For investor and media inquiries please contact:
Gary Guidry, President & Chief Executive Officer
Ryan Ellson, Executive Vice President & Chief Financial Officer
Tel: +1.403.265.3221
For more information on Gran Tierra please go to: www.grantierra.com.
Forward Looking Statements and Legal Advisories:
This press release contains opinions, forecasts, projections, and other
statements about future events or results that constitute forward-looking
statements within the meaning of the United States Private Securities
Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended,
and financial outlook and forward looking information within the meaning of
applicable Canadian securities laws (collectively, “forward- looking
statements”), which can be identified by such terms as “believe,”
“expect,” “anticipate,” “forecast,” “budget,” “will,”
“estimate,” “target,” “project,” “plan,” “should,”
“guidance,” “outlook,” “strives” or similar expressions are
forward-looking statements. Such forward-looking statements include, but are
not limited to, the Company’s strategies and expectations, capital program,
drilling plans, cost saving initiatives, future sources of funding for capital
expenditures and other activities, future planned operations and production
estimates, forecast prices, and the Company’s plans to benefit the
environment or communities in which it operates. Statements relating to
“reserves” are also deemed to be forward-looking statements, as they
involve the implied assessment, based on certain estimates and assumptions,
including that the reserves described can be profitably produced in the
future.
The forward-looking statements contained in this press release reflect several
material factors and expectations and assumptions of Gran Tierra including,
without limitation, that Gran Tierra will continue to conduct its operations
in a manner consistent with its current expectations, the ability of Gran
Tierra to realize the anticipated benefits and operating synergies expected
from the acquisition of i3 Energy, the accuracy of testing and production
results and seismic data, pricing and cost estimates (including with respect
to commodity pricing and exchange rates), rig availability, the risk profile
of planned exploration activities, the effects of drilling down-dip, the
5-year weighted-average Brent forecast, the effects of waterflood and
multi-stage fracture stimulation operations, the extent and effect of delivery
disruptions, and the general continuance of current or, where applicable,
assumed operational, regulatory and industry conditions in Canada, Colombia,
Ecuador, and Azerbaijan and areas of potential expansion, and the ability of
Gran Tierra to execute its business and operational plans in the manner
currently planned, such as the expected effectiveness of the EDPSA in
Azerbaijan and the timing and execution of the related exploration program.
Gran Tierra believes the material factors, expectations and assumptions
reflected in the forward-looking statements are reasonable at this time but no
assurance can be given that these factors, expectations and assumptions will
prove to be correct.
Among the important factors that could cause actual results to differ
materially from those indicated by the forward-looking statements in this
press release are: our operations are located in South America and unexpected
problems can arise due to guerilla activity, strikes, local blockades or
protests; technical difficulties and operational difficulties may arise which
impact the production, transport or sale of our products; other disruptions to
local operations; global health events; global and regional changes in the
demand, supply, prices, differentials or other market conditions affecting oil
and gas, including inflation and changes resulting from a global health
crisis, geopolitical events, including the ongoing conflicts in Ukraine, the
Middle East and Venezuela, or from the imposition or lifting of crude oil
production quotas or other actions that might be imposed by OPEC and other
producing countries and resulting company or third-party actions in response
to such changes; changes in commodity prices, including volatility or a
prolonged decline in these prices relative to historical or future expected
levels; the risk that current global economic and credit conditions may impact
oil and natural gas prices and oil and natural gas consumption more than we
currently predict, which could cause further modification of our strategy and
capital spending program; prices and markets for oil and natural gas are
unpredictable and volatile; the effect of hedges; the accuracy of productive
capacity of any particular field; geographic, political and weather conditions
can impact the production, transport or sale of our products; our ability to
execute our business plan, which may include acquisitions, and realize
expected benefits from current or future initiatives; the risk that unexpected
delays and difficulties in developing currently owned properties may occur;
the ability to replace reserves and production and develop and manage reserves
on an economically viable basis; the accuracy of testing and production
results and seismic data, pricing and cost estimates (including with respect
to commodity pricing and exchange rates); the risk profile of planned
exploration activities; the effects of drilling down-dip; the effects of
waterflood and multi-stage fracture stimulation operations; the extent and
effect of delivery disruptions, equipment performance and costs; actions by
third parties; the timely receipt of regulatory or other required approvals
for our operating activities; the failure of exploratory drilling to result in
commercial wells; unexpected delays due to the limited availability of
drilling equipment and personnel; volatility or declines in the trading price
of our common stock or bonds; the risk that we do not receive the anticipated
benefits of government programs, including government tax refunds; our ability
to comply with financial covenants in its credit agreement and indentures and
make borrowings under any credit agreement; and the risk factors detailed from
time to time in Gran Tierra’s periodic reports filed with the Securities and
Exchange Commission, including, without limitation, under the caption “Risk
Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended
December 31, 2025 filed March 4, 2026 and its other filings with the SEC.
These filings are available on the SEC website at http://www.sec.gov and on
SEDAR+ at www.sedarplus.ca. Although the current guidance, capital spending
program and long term strategy of Gran Tierra are based upon the current
expectations of the management of Gran Tierra, should any one of a number of
issues arise, Gran Tierra may find it necessary to alter its business strategy
and/or capital spending program and there can be no assurance as at the date
of this press release as to how those funds may be reallocated or strategy
changed and how that would impact Gran Tierra’s results of operations and
financial position. Forecasts and expectations that cover multi-year time
horizons or are associated with 2P reserves inherently involve increased risks
and actual results may differ materially.
All forward-looking statements are made as of the date of this press release
and the fact that this press release remains available does not constitute a
representation by Gran Tierra that Gran Tierra believes these forward-looking
statements continue to be true as of any subsequent date. Actual results may
vary materially from the expected results expressed in forward-looking
statements. Gran Tierra disclaims any intention or obligation to update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise, except as expressly required by applicable law. In
addition, historical, current and forward-looking sustainability-related
statements may be based on standards for measuring progress that are still
developing, internal controls and processes that continue to evolve, and
assumptions that are subject to change in the future.
Non-GAAP Measures
This press release includes non-GAAP financial measures as further described
herein. These non-GAAP measures do not have a standardized meaning under GAAP.
Investors are cautioned that these measures should not be construed as
alternatives to net income or loss, cash flow from operating activities or
other measures of financial performance as determined in accordance with GAAP.
Gran Tierra’s method of calculating these measures may differ from other
companies and, accordingly, they may not be comparable to similar measures
used by other companies. Each non-GAAP financial measure is presented along
with the corresponding GAAP measure so as not to imply that more emphasis
should be placed on the non-GAAP measure.
Net Debt, as presented as at December 31, 2025 is comprised of $741 million
(gross) of senior notes outstanding less cash and cash equivalents of $83
million, prepared in accordance with GAAP. Management believes that net debt
is a useful supplemental measure for management and investors in order to
evaluate the financial sustainability of the Company’s business and
leverage. The most directly comparable GAAP measure is total debt.
Operating netback, as presented, is defined as gross profit less depletion and
accretion related to producing assets. Operating netback per boe, as
presented, is defined as operating netback over WI sales volume. Cash netback,
as presented, is most directly comparable to gross profit and is calculated as
gross profit adjusted for depletion and accretion related to producing assets,
cash G&A expenses, transaction costs, export tax, realized foreign exchange
gains or losses, cash settlement on derivative instruments, interest expense
excluding amortization of debt issuance costs, interest income, other cash
gains or losses, net lease payments, and current income tax expense or
recovery. Cash netback per boe, as presented, is defined as cash netback over
WI sales volumes. Management believes that operating netback and cash netback
are useful supplemental measures for investors to analyze financial
performance and provide an indication of the results generated by Gran
Tierra’s principal business activities prior to the consideration of other
income and expenses. See the table entitled Financial and Operational
Highlights above for the components of operating netback and operating netback
per boe. A reconciliation from net income or loss to cash netback is as
follows:
Year Ended Three Months Ended
December 31, December 31, September 30,
Operating and Cash Netback - Non-GAAP Measure ($000s) 2025 2024 2025 2024 2025
Gross profit $ 66,419 $ 182,637 $ 851 $ 22,180 $ 14,670
Adjustments to reconcile net (loss) income to operating netback
Depletion and accretion 264,522 218,417 68,236 60,061 61,908
Operating netback (non-GAAP) 330,941 401,054 69,087 82,241 76,578
Cash G&A expenses (56,873 ) (41,431 ) (16,817 ) (10,191 ) (13,453 )
Transaction costs — (5,907 ) — (4,448 ) —
Export tax (3,287 ) — (657 ) — (2,630 )
Realized foreign exchange (loss) gain (7,694 ) 915 (2,792 ) 273 (2,149 )
Cash settlement on derivative instruments 10,292 1,103 757 1,103 7,461
Interest expense, excluding amortization of debt issuance costs (82,341 ) (67,548 ) (21,477 ) (20,009 ) (21,178 )
Interest income 1,090 3,666 217 1,273 197
Other cash gain 1,645 1,478 — 1,478 1,268
Net lease payments (152 ) 888 (114 ) 264 (387 )
Current income tax (expense) recovery (15,859 ) (69,277 ) (1,377 ) (7,855 ) (4,022 )
Cash netback (non-GAAP) $ 177,762 $ 224,941 $ 26,827 $ 44,129 $ 41,685
EBITDA, as presented, is defined as net income (loss) adjusted for DD&A
expenses, interest expense, and income tax expense or recovery. Adjusted
EBITDA, as presented, is defined as EBITDA adjusted for asset impairment,
non-cash lease expense, lease payments, foreign exchange gains or losses,
unrealized derivative instruments gains or losses, transaction costs, other
non-cash gains or losses, and stock-based compensation expense. Management
uses this supplemental measure to analyze performance and income generated by
our principal business activities prior to the consideration of how non-cash
items affect that income, and believes that this financial measure is a useful
supplemental information for investors to analyze our performance and our
financial results. A reconciliation from net income or loss or loss to EBITDA
and adjusted EBITDA is as follows:
Year Ended Three Months Ended
December 31, December 31, September 30,
EBITDA - Non-GAAP Measure ($000s) 2025 2024 2025 2024 2025
Net (loss) income $ (193,119 ) $ 3,216 $ (141,148 ) $ (34,210 ) $ (19,950 )
Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
DD&A expenses 278,353 230,619 72,535 63,406 64,981
Interest expense 101,309 80,466 28,261 23,752 25,447
Income tax expense (39,753 ) 41,389 (36,678 ) 12,299 (11,276 )
EBITDA (non-GAAP) $ 146,790 $ 355,690 $ (77,030 ) $ 65,247 $ 59,202
Asset impairment 136,261 — 136,261 — —
Non-cash lease expense 5,821 5,923 1,173 1,759 1,187
Lease payments (5,973 ) (5,035 ) (1,287 ) (1,495 ) (1,574 )
Foreign exchange gain 8,734 (8,808 ) 896 (496 ) 284
Unrealized derivative instruments (gain) loss (8,633 ) 3,374 (7,669 ) 3,374 9,527
Transaction costs — 5,907 — 4,448 —
Other non-cash (gain) loss (2,558 ) — (2,913 ) — 265
Stock-based compensation expense 3,214 9,707 3,042 3,331 143
Adjusted EBITDA (non-GAAP) $ 283,656 $ 366,758 $ 52,473 $ 76,168 $ 69,034
Funds flow from operations, as presented, is defined as net income (loss)
adjusted for DD&A expenses, asset impairment, deferred tax expense or
recovery, stock-based compensation expense or recovery, amortization of debt
issuance costs, non-cash interest, non-cash lease expense, lease payments,
unrealized foreign exchange gains or losses, unrealized derivative instruments
gains or losses, and other non-cash gains or losses. Management uses this
financial measure to analyze performance and income or loss generated by our
principal business activities prior to the consideration of how non-cash items
affect that income or loss, and believes that this financial measure is also
useful supplemental information for investors to analyze performance and our
financial results. Free cash flow, as presented, is defined as funds flow from
operations adjusted for capital expenditures. Management uses this financial
measure to analyze cash flow generated by our principal business activities
after capital requirements and believes that this financial measure is also
useful supplemental information for investors to analyze performance and our
financial results. A reconciliation from net income or loss to funds flow from
operations and free cash flow is as follows:
Year Ended Three Months Ended
December 31, December 31, September 30,
Funds Flow From Operations - Non-GAAP Measure ($000s) 2025 2024 2025 2024 2025
Net (loss) income $ (193,119 ) $ 3,216 $ (141,148 ) $ (34,210 ) $ (19,950 )
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses 278,353 230,619 72,535 63,406 64,981
Asset impairment 136,261 — 136,261 — —
Deferred tax (recovery) expense (55,612 ) (27,888 ) (38,055 ) 4,444 (15,298 )
Stock-based compensation expense 3,214 9,707 3,042 3,331 143
Amortization of debt issuance costs 16,943 12,918 4,759 3,743 4,269
Non-cash interest 2,025 — 2,025 — —
Non-cash lease expense 5,821 5,923 1,173 1,759 1,187
Lease payments (5,973 ) (5,035 ) (1,287 ) (1,495 ) (1,574 )
Unrealized foreign exchange loss (gain) 1,040 (7,893 ) (1,896 ) (223 ) (1,865 )
Other non-cash (gain) loss (2,558 ) — (2,913 ) — 265
Unrealized derivative instruments (gain) loss (8,633 ) 3,374 (7,669 ) 3,374 9,527
Funds flow from operations (non-GAAP) $ 177,762 $ 224,941 $ 26,827 $ 44,129 $ 41,685
Capital expenditures $ 256,277 $ 248,103 $ 53,040 $ 78,579 $ 57,340
Free cash flow (non-GAAP) $ (78,515 ) $ (23,162 ) $ (26,213 ) $ (34,450 ) $ (15,655 )
DISCLOSURE OF OIL AND GAS INFORMATION
Gran Tierra’s Statement of Reserves Data and Other Oil and Gas Information
on Form 51-101F1 dated effective as at December 31, 2025, which includes
disclosure of its oil and gas reserves and other oil and gas information in
accordance with NI 51-101 and COGEH forming the basis of this press release,
is available on SEDAR+ at www.sedarplus.ca. All reserves values, future net
revenue and ancillary information contained in this press release as of
December 31, 2025 are derived from the GTE McDaniel Reserves Report, unless
expressly stated. Any reserves values or related information contained in this
press release as of a date other than December 31, 2025 has an effective date
of December 31 of the applicable year and is derived from a report prepared by
Gran Tierra’s independent qualified reserves evaluator as of such date and
have been prepared in compliance with NI 51-101 and the COGEH.
Estimates of net present value and future net revenue contained herein do not
necessarily represent fair market value of reserves. Estimates of reserves and
future net revenue for individual properties may not reflect the same level of
confidence as estimates of reserves and future net revenue for all properties,
due to the effect of aggregation. There is no assurance that the forecast
price and cost assumptions applied by McDaniel in evaluating Gran Tierra’s
reserves and future net revenue will be attained and variances could be
material. See Gran Tierra’s press release dated January 28, 2026 for a
summary of the price forecasts employed by McDaniel in the GTE McDaniel
Reserves Report and other information regarding the disclosed future net
revenue.
All evaluations of future net revenue contained in the GTE McDaniel Reserves
Report are after the deduction of royalties, operating costs, development
costs and abandonment and reclamation costs but before consideration of
indirect costs such as administrative, overhead and other miscellaneous
expenses. It should not be assumed that the estimates of future net revenue
presented in this press release represent the fair market value of the
reserves. There are numerous uncertainties inherent in estimating quantities
of crude oil and natural gas reserves and the future cash flows attributed to
such reserves. The reserve and associated cash flow information set forth in
the GTE McDaniel Reserves Report are estimates only and there is no guarantee
that the estimated reserves will be recovered. Actual reserves may be greater
than or less than the estimates provided therein.
Boes have been converted on the basis of six thousand cubic feet (“Mcf”)
natural gas to 1 boe of oil. Boes may be misleading, particularly if used in
isolation. A boe conversion ratio of 6 Mcf: 1 boe 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, given that the
value ratio based on the current price of oil as compared with natural gas is
significantly different from the energy equivalent of six to one, utilizing a
boe conversion ratio of 6 Mcf: 1 boe would be misleading as an indication of
value.
References to a formation where evidence of hydrocarbons has been encountered
is not necessarily an indicator that hydrocarbons will be recoverable in
commercial quantities or in any estimated volume. Gran Tierra’s reported
production is a mix of light crude oil and medium, heavy crude oil, tight oil,
conventional natural gas, shale gas and natural gas liquids for which there is
no precise breakdown since the Company’s sales volumes typically represent
blends of more than one product type. Drilling locations disclosed herein are
derived from the GTE McDaniel Reserves Report and account for drilling
locations that have associated Proved Undeveloped and Proved plus Probable
Undeveloped reserves, as applicable. Well test results should be considered as
preliminary and not necessarily indicative of long-term performance or of
ultimate recovery. Well log interpretations indicating oil and gas
accumulations are not necessarily indicative of future production or ultimate
recovery. If it is indicated that a pressure transient analysis or well-test
interpretation has not been carried out, any data disclosed in that respect
should be considered preliminary until such analysis has been completed.
References to thickness of “oil pay” or of a formation where evidence of
hydrocarbons has been encountered is not necessarily an indicator that
hydrocarbons will be recoverable in commercial quantities or in any estimated
volume.
Future Net Revenue
Future net revenue reflects McDaniel’s forecast of revenue estimated using
forecast prices and costs, arising from the anticipated development and
production of reserves, after the deduction of royalties, operating costs,
development costs and abandonment and reclamation costs and taxes but before
consideration of indirect costs such as administrative, overhead and other
miscellaneous expenses. The estimate of future net revenue below does not
necessarily represent fair market value.
Consolidated Properties at December 31, 2025
Proved (1P) Total Future Net Revenue ($ million)
Forecast Prices and Costs
Years Sales Revenue Total Royalties Operating Costs Future Development Capital Abandonment and Reclamation Costs Future Net Revenue Before Future Taxes Future Taxes Future Net Revenue After Future Taxes*
2026 - 2030 (5 Years) 4,479 (883 ) (1,443 ) (882 ) (31 ) 1,240 (280 ) 960
Remainder 3,167 (589 ) (1,413 ) (5 ) (345 ) 815 (212 ) 603
Total (Undiscounted) 7,645 (1,472 ) (2,856 ) (888 ) (376 ) 2,053 (492 ) 1,561
Total (Discounted @ 10%) 1,456 (318 ) 1,138
Consolidated Properties at December 31, 2025
Proved Plus Probable (2P) Total Future Net Revenue ($ million)
Forecast Prices and Costs
Years Sales Revenue Total Royalties Operating Costs Future Development Capital Abandonment and Reclamation Costs Future Net Revenue Before Future Taxes Future Taxes Future Net Revenue After Future Taxes*
2026 - 2030 (5 Years) 5,222 (1,040 ) (1,550 ) (1,016 ) (27 ) 1,589 (404 ) 1,185
Remainder 8,851 (1,944 ) (3,080 ) (666 ) (391 ) 2,770 (900 ) 1,870
Total (Undiscounted) 14,073 (2,984 ) (4,629 ) (1,682 ) (419 ) 4,359 (1,304 ) 3,055
Total (Discounted @ 10%) 2,461 (703 ) 1,758
Consolidated Properties at December 31, 2025
Proved Plus Probable Plus Possible (3P) Total Future Net Revenue ($ million)
Forecast Prices and Costs
Years Sales Revenue Total Royalties Operating Costs Future Development Capital Abandonment and Reclamation Costs Future Net Revenue Before Future Taxes Future Taxes Future Net Revenue After Future Taxes*
2026 - 2030 (5 Years) 5,790 (1,172 ) (1,613 ) (1,067 ) (26 ) 1,911 (529 ) 1,382
Remainder 12,799 (3,029 ) (4,078 ) (818 ) (407 ) 4,467 (1,516 ) 2,951
Total (Undiscounted) 18,589 (4,202 ) (5,691 ) (1,886 ) (433 ) 6,378 (2,044 ) 4,334
Total (Discounted @ 10%) 3,317 (1,033 ) 2,283
Definitions
Proved reserves are those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves.
Probable reserves are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
proved plus probable reserves.
Possible reserves are those additional reserves that are less certain to be
recovered than Probable reserves. It is unlikely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
proved plus probable plus possible reserves. There is a 10% probability that
the quantities actually recovered will equal or exceed the sum of 3P reserves.
Developed producing reserves are those reserves that are expected to be
recovered from completion intervals open at the time of the estimate. These
reserves may be currently producing or, if shut-in, they must have previously
been on production, and the date of resumption of production must be known
with reasonable certainty.
Developed non-producing reserves are those reserves that either have not been
on production or have previously been on production but are shut-in and the
date of resumption of production is unknown.
Undeveloped reserves are those reserves expected to be recovered from known
accumulations where a significant expenditure (e.g., when compared to the cost
of drilling a well) is required to render them capable of production. They
must fully meet the requirements of the reserves category (proved, probable,
possible) to which they are assigned.
Certain terms used in this press release but not defined are defined in NI
51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101 Standards of
Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324”) and/or
the COGEH and, unless the context otherwise requires, shall have the same
meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the
case may be.
Oil and Gas Metrics
This press release contains a number of oil and gas metrics, including NAV per
share, operating netback, cash netback, reserves replacement, and reserve life
index which do not have standardized meanings or standard methods of
calculation and therefore such measures may not be comparable to similar
measures used by other companies and should not be used to make comparisons.
Such metrics have been included herein to provide readers with additional
measures to evaluate the Company’s performance; however, such measures are
not reliable indicators of the future performance of the Company and future
performance may not compare to the performance in previous periods.
* NAV per share is calculated as the applicable NPV10 (before or after-tax, as
applicable) of the applicable reserves category minus estimated net debt,
divided by the number of shares of Gran Tierra’s common stock issued and
outstanding. Management uses NAV per share as a measure of the relative change
of Gran Tierra’s net asset value over its outstanding common stock over a
period of time.
* Operating netback and cash netback are calculated as described in this press
release. Management believes that operating netback and cash netback are
useful supplemental measures for the reasons described in this press release.
* Reserves replacement is calculated as reserves in the referenced category
divided by estimated referenced production. Management uses this measure to
determine the relative change of its reserves base over a period of time.
* Reserve life index is calculated as reserves in the referenced category
divided by the referenced production. Management uses this measure to
determine how long the booked reserves will last at current production rates
if no further reserves were added.
Disclosure of Reserve Information and Cautionary Note to U.S. Investors
Unless expressly stated otherwise, all estimates of proved developed
producing, proved, probable and possible reserves and related future net
revenue disclosed in this press release have been prepared in accordance with
NI 51-101. Estimates of reserves and future net revenue made in accordance
with NI 51-101 will differ from corresponding GAAP standardized measures
prepared in accordance with applicable SEC rules and disclosure requirements
of the U.S. Financial Accounting Standards Board (“FASB”), and those
differences may be material. NI 51-101, for example, requires disclosure of
reserves and related future net revenue estimates based on forecast prices and
costs, whereas SEC and FASB standards require that reserves and related future
net revenue be estimated using average prices for the previous 12 months and
that the standardized measure reflect discounted future net income taxes
related to the Company’s operations. In addition, NI 51-101 permits the
presentation of reserves estimates on a “company gross” basis,
representing Gran Tierra’s working interest share before deduction of
royalties, whereas SEC and FASB standards require the presentation of net
reserve estimates after the deduction of royalties and similar payments. There
are also differences in the technical reserves estimation standards applicable
under NI 51-101 and, pursuant thereto, the COGEH, and those applicable under
SEC and FASB requirements.
In addition to being a reporting issuer in certain Canadian jurisdictions,
Gran Tierra is a registrant with the SEC and subject to domestic issuer
reporting requirements under U.S. federal securities law, including with
respect to the disclosure of reserves and other oil and gas information in
accordance with U.S. federal securities law and applicable SEC rules and
regulations (collectively, “SEC requirements”). Disclosure of such
information in accordance with SEC requirements is included in the Company’s
Annual Report on Form 10-K and in other reports and materials filed with or
furnished to the SEC and, as applicable, Canadian securities regulatory
authorities. The SEC permits oil and gas companies that are subject to
domestic issuer reporting requirements under U.S. federal securities law, in
their filings with the SEC, to disclose only estimated proved, probable and
possible reserves that meet the SEC’s definitions of such terms. Gran Tierra
has disclosed estimated proved, probable and possible reserves in its filings
with the SEC. In addition, Gran Tierra prepares its financial statements in
accordance with United States generally accepted accounting principles, which
require that the notes to its annual financial statements include
supplementary disclosure in respect of the Company’s oil and gas activities,
including estimates of its proved oil and gas reserves and a standardized
measure of discounted future net cash flows relating to proved oil and gas
reserve quantities. This supplementary financial statement disclosure is
presented in accordance with FASB requirements, which align with corresponding
SEC requirements concerning reserves estimation and reporting.
The Company believes that the presentation of NPV10 is useful to investors
because it presents (i) relative monetary significance of its oil and natural
gas properties regardless of tax structure and (ii) relative size and value of
its reserves to other companies. The Company also uses this measure when
assessing the potential return on investment related to its oil and natural
gas properties. NPV10 and the standardized measure of discounted future net
cash flows do not purport to present the fair value of the Company’s oil and
gas reserves. The Company has not provided a reconciliation of NPV10 to the
standardized measure of discounted future net cash flows because it is
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