REG-Gran Tierra Energy Inc. Reports Third Quarter 2025 Results and Announces Further Exploration Success in Ecuador
30/10/2025 21:30
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* Gran Tierra Secures $200 Million Prepayment Facility Highlighting Strength
of Portfolio
* Increase and Extension of Canadian Credit Facility
* Three Major Ecuador Discoveries Add to the Existing Success in Country
* Colombia’s Southern Putumayo Cohembi Field Achieves Highest Production in
a Decade
CALGARY, Alberta, Oct. 30, 2025 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc.
(“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE:
GTE) announced the Company’s financial and operating results for the
quarter ended September 30, 2025 (the “Quarter”) and provided an
operational update. 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. For per boe amounts
based on net after royalty (“NAR”) production, see Gran Tierra’s
Quarterly Report on Form 10-Q filed October 30, 2025.
Message to Shareholders
“The Third Quarter showcased continued operational success across our
portfolio. In Ecuador, we achieved further exploration success with the Conejo
A-1 and A-2 wells and confirmed a new discovery at Chanangue-1, all of which
highlight the significant potential of our acreage position. We also recently
cased and cemented the Conejo A-2 well, targeting multiple prospective
reservoirs including the Basal Tena and Hollin. The well discovered 41 feet of
net reservoir with an average porosity of 13.8% in the Hollin formation
suggesting well-connected reservoir quality over the full Conejo structural
trap.
In Colombia, new wells at Costayaco continued to perform well, and the Cohembi
field delivered a strong waterflood response, with production reaching levels
not seen in over a decade. In Canada, we successfully drilled and brought two
additional Lower Montney wells onstream, both meeting or exceeding
expectations.
Production during the Quarter was temporarily impacted primarily by externally
driven events, including a landslide in Ecuador that required the shut in of
all Ecuador production for several weeks and trunk line repairs at the Moqueta
field which resulted in the field being shut in for the Quarter. These volumes
represent deferred bbls rather than lost production, and we are already seeing
a strong recovery, with current production((2)) averaging approximately 45,200
boepd. Based on the deferrals, we are forecasting the lower end of our
production guidance range. The underlying assets continue to perform well, and
our teams remain focused on ongoing optimization and maximizing production
efficiency and cash flow with an expected exit rate of 47,000 to 50,000 boepd.
We completed a number of initiatives to enhance liquidity and will be
releasing our 2026 budget in mid December which will focus on free cash flow
generation. The 2025 capital program was focused on fulfilling exploration
commitments, which resulted in numerous material discoveries, and facility
construction primarily in the Suroriente Block. With substantially all
commitments behind us, the focus turns to free cash flow generation from our
substantial, diversified resource base and deleveraging,” commented Gary
Guidry, President and Chief Executive Officer of Gran Tierra Energy.
Operational Update:
* Ecuador * Another successful exploration well, Conejo A-1 was drilled during
the Quarter on budget. The well was subsequently completed and tested the
Hollin and Basal Tena sands. * The Basal Tena and Hollin oil zones perforated
over 19 feet (“ft”) and 40 ft of reservoir, respectively. Under natural
flow conditions, the well has produced at stabilized rates over 308 hours at
1,328 bbls of oil per day (“bopd”), 26.9-degree API gravity oil, a 23.7%
water cut, and a gas-oil ratio of 289 standard cubic feet per stock tank
barrel. During the fourth quarter, the Company plans to re-enter the well to
install the final completion and conduct selective testing of each zone to
optimize total well production.
* The Conejo A-2 well was spud on October 4, 2025, targeting multiple
prospective reservoirs including the Basal Tena and Hollin. The well included
coring of key intervals to further evaluate reservoir characteristics and
potential. * The Conejo A-2 well discovered 41 ft of net reservoir with an
average porosity of 13.8% in the Hollin formation. Of particular interest is
the outstanding reservoir quality suggesting high deliverability over the full
Conejo structural trap.
* With the delivery of the Conejo A-2 well, Gran Tierra has completed all of
the Exploration commitments in Ecuador and we are now well-positioned to
continue to increase production into the development phase and establish our
long-term growth position in Ecuador.
* A new oil discovery was made in the legacy Chanangue-1 well drilled in 1990
and suspended in 1992 on the Chanangue Block. The well was re-entered to test
the previously bypassed Basal Tena formation, which was subsequently
perforated and brought online. The well is currently producing approximately
600 bopd on jet pump. This discovery highlights significant reserve potential
and is expected to generate additional future drilling opportunities on the
eastern side of the Chanangue Block.
* Colombia * During the Quarter, Gran Tierra’s development program in the
northern area of the Costayaco field continued to perform well, with all three
new wells contributing to production growth. The Costayaco-63, -64, and -65
wells were drilled and brought onstream between late June to mid-August,
achieving average initial 30-day oil rates ranging from approximately 600 to
1,100 bopd with water cuts between 25% and 70%. Combined production from these
wells during the Quarter averaged approximately 1,700 bopd with an average
water cut of around 60%, helping sustain stable field output. We are currently
changing the artificial lift system from jet pump to electronic submersible
pumps which is expected to add an incremental 1,000 - 1,500 bopd.
* Cohembi continues to deliver a strong waterflood response, with the five
development wells drilled during the first half of 2025. Output from the
northern area has increased by approximately 135%, rising from 2,800 to 6,700
gross bopd, with additional gains anticipated. Total field production has now
exceeded 9,000 gross bopd – levels not achieved since 2014. Drilling has
commenced a 6-well program which includes the Raju-1 exploration well, the 2nd
well in the program, which is expected to spud in early November. The Raju-1
exploration well will be targeting a large prospective area north of the
current development. We expect to have initial results from this well prior to
year end 2025.
* Canada * Two additional Lower Montney wells were drilled, completed, and
brought on stream in September, bringing total 2025 activity in Simonette to
4.0 gross (2.0 net) wells. Initial production performance has been very
encouraging, with one well exceeding high-case expectations and another
tracking closely to the base case and still cleaning up.
Capital Structure Optimization:
* Executed Oriente Crude Oil Agreements providing for an initial advance of up
to $150 million and an additional $50 million, to be repaid through scheduled
deliveries of Ecuadorian Oriente crude oil; proceeds are expected to be used
to repay debt and fund select capital initiatives.
* Amended Colombian credit facility to align with the new prepayment
structure, enhancing financial flexibility, reducing standby costs, and
optimizing Gran Tierra’s overall capital structure.
* Subsequent to the Quarter, the Company amended and restated the existing
credit agreement of Gran Tierra Canada Ltd. (“GT Canada”) pursuant to a
second amended and restated credit agreement dated October 30, 2025 to, among
other things, increase the total available borrowing capacity available under
its credit facilities (the “Canadian Credit Facilities”) from C$50.0
million to C$75.0 million. Other key amendments to the Canadian Credit
Facilities as a result of such amendment and restatement are summarized as
follows: * The tenor of the Canadian Credit Facilities was extended by one
year and converted from a “one year revolving facility with a one year
term-out period” into a “two year revolving facility” with a maturity
date of October 31, 2027;
* GT Canada’s lender completed its semi-annual borrowing base review, which
resulted in the borrowing base remaining at C$100.0 million; and
* The existing uncommitted accordion feature (which contemplates a further
increase of the Canadian Credit Facilities) was reduced from C$50.0 million to
C$25.0 million.
Key Highlights of the Quarter:
* Production: Gran Tierra’s total average WI production was 42,685 boepd,
which was 30% higher than the third quarter of 2024 due to the production from
the Canadian operations acquired on October 31, 2024 and positive exploration
well drilling results in Ecuador. Total average WI production was 10% lower
than the quarter ended June 30, 2025 (the “Prior Quarter”) primarily as a
result of a landslide in Ecuador that required the shut in of all Ecuador
production for several weeks and trunk line repairs at the Moqueta field which
resulted in the field being shut in for the Quarter. Working interest sales in
the Quarter were 44,077 boepd primarily due to the recognition of 143,730 bbls
of Ecuador oil production, which were held in inventory at the end of June and
subsequently sold in July.
* Current Production: The Company’s current average production((2)) has been
approximately 45,200 boepd.
* Net Income (Loss): Gran Tierra incurred a net loss of $20 million, compared
to a net loss of $13 million in the Prior Quarter and net income of $1 million
in the third quarter of 2024.
* Adjusted EBITDA((1)): Adjusted EBITDA((1)) was $69 million compared to $77
million in the Prior Quarter and $93 million in the third quarter of 2024.
* Funds Flow from Operations((1)): Funds flow from operations((1)) was $42
million ($1.18 per share), down 31% from the third quarter of 2024 and down
23% from the Prior Quarter.
* Net Cash Provided by Operating Activities: Net cash provided by operating
activities was $48 million ($1.36 per share), up 39% from the Prior Quarter
and down 39% from the third quarter of 2024.
* Cash and Debt: As of September 30, 2025, the Company had a cash balance of
$49 million, total debt of $804 million and net debt((1)) of $755 million.
During the Quarter, the Company repaid a total of $2 million of its credit
facility. In addition to the $49 million cash on hand as of September 30,
2025, the Company currently has approximately $67 million of undrawn capacity
with $111 million in credit and lending facilities and $44 million drawn as of
September 30, 2025.
Additional Key Financial Metrics:
* Capital Expenditures: Capital expenditures were $57 million during the
Quarter which were higher than the $51 million in the Prior Quarter and higher
than $53 million in the third quarter of 2024. During the Quarter, the
majority of capital expenditures incurred in Colombia and Ecuador related to
planned exploration drilling and infrastructure spend in Cohembi, and in
Canada for the drilling and completion of two Simonette wells (1.0 net).
* Oil, Natural Gas and Natural Gas Liquids (“NGL”) Sales: Gran Tierra
generated sales of $149 million, down 1% from the third quarter of 2024
primarily as a result of a 13% decrease in Brent pricing, partially offset by
37% higher sales volumes due to higher production and lower Castilla, Oriente,
and Vasconia oil differentials. Oil sales remained consistent when compared to
the Prior Quarter primarily due to a 2% increase in Brent price and lower
Oriente oil differentials, partially offset by higher Castilla and Vasconia
oil differentials, and lower sales volumes.
* South American Quality and Transportation Discounts: The Company’s quality
and transportation discounts in South America per bbl were slightly higher
during the Quarter at $10.76, compared to $10.30 in the Prior Quarter and
$14.10 in the third quarter of 2024. The Castilla oil differential per bbl was
$4.88, up slightly from $4.73 in the Prior Quarter and down $8.83 in the third
quarter of 2024 (Castilla is the benchmark for the Company’s Middle
Magdalena Valley Basin oil production). The Vasconia differential per bbl was
$1.88, slightly up from $1.71 in the Prior Quarter, and down from $5.07 in the
third quarter of 2024. The Ecuadorian benchmark, Oriente, per bbl was $7.20,
down from $7.26 in the Prior Quarter and down from $9.15 in the third quarter
of 2024. The current((5)) differentials are approximately $5.79 per bbl for
Castilla, $2.79 per bbl for Vasconia, and $7.66 per bbl for Oriente.
* Operating Expenses: Total operating expenses increased by 22% to $68 million
and on a per boe basis increased 26% when compared to the Prior Quarter as a
result of higher workover activities and lifting costs associated with
inventory fluctuations in Ecuador. When compared to the third quarter of 2024
total operating expenses increased by 48% from $46 million and on a per boe
basis they increased by 9% as a result of new Canadian operations and ramp-up
of operations in Ecuador.
* Transportation Expenses: The Company’s transportation expenses decreased
by 4% to $4.3 million, compared to the Prior Quarter’s transportation
expenses of $4.5 million as a result of lower sales volumes transported in
Colombia. When compared to the third quarter of 2024 transportation expenses
increased from $3.9 million due to the new Canadian operations, higher sales
volumes transported in Ecuador partially offset by lower sales volumes
transported in Colombia.
* Gross Profit: During the Quarter gross profit decreased 70% to $14.7 million
compared to $48.8 million in the third quarter of 2024 and 36% from $23.1
million in the Prior Quarter. On a per boe basis gross profit was $3.62
compared to $16.45 in the third quarter of 2024 and $5.54 compared to the
Prior Quarter.
* Operating Netback((1)(3)): The Company’s operating netback((1)(3)) was
$18.89 per boe, down 12% from the Prior Quarter and primarily as a result of
an increase in operating expenses and a decrease in sales volumes. Operating
netback((1)(3)) was down 45% when compared to the third quarter of 2024
primarily as a result of a decrease in pricing.
* General and Administrative (“G&A”) Expenses: G&A expenses before
stock-based compensation were $3.32 per boe, down from $3.48 per boe in the
Prior Quarter, due to lower business development costs. G&A expenses before
stock-based compensation were up from $3.20 per boe, compared to the third
quarter of 2024 as a result of higher costs in the depletable base for Ecuador
and the new Canadian operations.
* Cash Netback((1)): Cash netback((1)) per boe decreased to $10.28, compared
to $12.95 in the Prior Quarter, primarily as a result of lower operating
netback((1)) and were offset by positive cash settlement of derivative
instruments. Compared to one year ago, cash netback((1)) per boe decreased by
$10.06 from $20.34 per boe as a result of lower operating netback((1)) while
being offset by lower current tax expense by positive cash settlement of
derivative instruments.
Financial and Operational Highlights (all amounts in $000s, except per share
and boe amounts)
Consolidated Financial Data Three Months Ended September 30, Three Months Ended June 30, Nine Months Ended September 30,
2025 2024 2025 2025 2024
Net (Loss) Income $ (19,950 ) $1,133 $(12,741) $ (51,971 ) $37,426
Per Share – Basic and Diluted $ (0.57 ) $0.04 $(0.36) $ (1.47 ) $1.20
Gross Profit $ 14,670 $48,803 $23,061 $ 65,568 $160,457
Depletion and Accretion ((*)) 61,908 52,599 65,947 196,286 158,356
Operating Netback ((1)(3)) $ 76,578 $101,402 $89,008 $ 261,854 $318,813
Oil, Natural Gas and NGL Sales $ 149,254 $151,373 $149,357 $ 466,784 $474,559
Operating Expenses (68,379 ) (46,060) (55,855) (191,588 ) (141,561)
Transportation Expenses (4,297 ) (3,911) (4,494) (13,342 ) (14,185)
Operating Netback ((1)(3)) $ 76,578 $101,402 $89,008 $ 261,854 $318,813
G&A Expenses Before Stock-Based Compensation $ 13,453 $9,491 $14,460 $ 40,056 $31,240
G&A Stock-Based Compensation Expense (Recovery) 143 (3,145) 546 172 6,376
G&A Expenses, Including Stock Based Compensation $ 13,596 $6,346 $15,006 $ 40,228 $37,616
Adjusted EBITDA ((1)) $ 69,034 $92,794 $76,987 $ 231,183 $290,590
EBITDA ((1)) $ 59,202 $97,365 $84,908 $ 223,820 $290,443
Net Cash Provided by Operating Activities $ 48,149 $78,654 $34,677 $ 156,056 $212,714
Funds Flow from Operations ((1)) $ 41,685 $60,338 $53,906 $ 150,935 $180,812
Capital Expenditures (Before Changes in Working Capital) $ 57,340 $52,921 $51,170 $ 203,237 $169,525
Free Cash Flow ((1)) $ (15,655 ) $7,417 $2,736 $ (52,302 ) $11,287
Average Daily Production (boe/d)
WI Production Before Royalties 42,685 32,764 47,196 45,495 32,595
Royalties (6,723 ) (6,776) (7,396) (7,396 ) (6,650)
Production NAR 35,962 25,988 39,800 38,099 25,945
Decrease (Increase) in Inventory 1,391 (524) (1,469) 132 (367)
Sales 37,353 25,464 38,331 38,231 25,578
Royalties, % of WI Production Before Royalties 16 % 21% 16% 16 % 20%
Cash Netback ($/boe) ((1))
Gross Profit 3.62 16.45 5.54 5.26 18.17
Depletion and Accretion ((*)) 15.27 17.73 15.85 15.76 17.93
Operating Netback ((1)(3)) 18.89 34.18 21.39 21.02 36.10
Average Realized Price before Royalties 43.44 64.61 42.82 44.72 67.71
Royalties (6.63 ) (13.58) (6.93) (7.25 ) (13.97)
Average Realized Price 36.81 51.03 35.89 37.47 53.74
Transportation Expenses (1.06 ) (1.32) (1.08) (1.07 ) (1.61)
Average Realized Price Net of Transportation Expenses 35.75 49.71 34.81 36.40 52.13
Operating Expenses (16.86 ) (15.53) (13.42) (15.38 ) (16.03)
Operating Netback ((1)(3)) 18.89 34.18 21.39 21.02 36.10
G&A Expenses Before Stock-Based Compensation (3.32 ) (3.20) (3.48) (3.22 ) (3.54)
Transaction Costs — (0.49) — — (0.17)
Export Tax (0.65 ) — — (0.21 ) —
Realized Foreign Exchange (Loss) Gain (0.53 ) 0.34 (0.14) (0.39 ) 0.07
Cash Settlement on Derivative Instruments 1.84 — 0.39 0.77 —
Interest Expense, Excluding Amortization of Debt Issuance Costs (5.22 ) (5.66) (4.87) (4.89 ) (5.38)
Interest Income 0.05 0.23 0.06 0.07 0.27
Other Gain 0.31 — 0.09 0.13 —
Net Lease Payments (0.10 ) 0.07 0.04 — 0.07
Current Income Tax Expense (0.99 ) (5.13) (0.53) (1.16 ) (6.96)
Cash Netback ((1)) $ 10.28 $20.34 $12.95 $ 12.12 $20.46
Share Information (000s)
Common Stock Outstanding, End of Period 35,296 31,022 35,289 35,296 31,022
Weighted Average Number of Shares of Common Stock Outstanding – Basic and Diluted 35,291 30,733 35,335 35,466 31,274
South American Operational Information Three Months Ended September 30, Three Months Ended June 30, Nine Months Ended September 30,
2025 2024 2025 2025 2024
Operating Netback ((1)(3))
Gross Profit $ 11,096 $48,803 $19,210 $ 58,351 $160,457
Depletion and Accretion ((*)) 53,560 52,599 52,247 161,302 158,356
Operating Netback ((1)(3)) $ 64,656 $101,402 $71,457 $ 219,653 $318,813
Oil Sales $ 122,604 $151,373 $118,187 $ 379,462 $474,559
Operating Expenses (53,976 ) (46,060) (42,554) (147,357 ) (141,561)
Transportation Expenses (3,972 ) (3,911) (4,176) (12,452 ) (14,185)
Operating Netback ((1)(3)) $ 64,656 $101,402 $71,457 $ 219,653 $318,813
Capital Expenditures (Before Changes in Working Capital) $ 48,047 $52,836 $49,327 $ 162,358 $168,973
Average Daily Production (boe/d)
WI Production Before Royalties 26,573 32,764 29,700 28,642 32,595
Royalties (4,754 ) (6,776) (5,209) (5,265 ) (6,650)
Production NAR 21,819 25,988 24,491 23,377 25,945
Decrease (Increase) in Inventory 1,391 (524) (1,469) 132 (368)
Sales 23,210 25,464 23,022 23,509 25,577
Royalties, % of WI Production Before Royalties 18 % 21% 18% 18 % 20%
Operating Netback ($/boe) ((1)(3))
Brent $ 68.17 $78.71 $66.71 $ 69.91 $81.82
Quality and Transportation Discount (10.76 ) (14.10) (10.30) (10.78 ) (14.11)
Royalties (9.76 ) (13.58) (10.41) (10.82 ) (13.97)
Average Realized Price 47.65 51.03 46.00 48.31 53.74
Transportation Expenses (1.54 ) (1.32) (1.63) (1.59 ) (1.61)
Average Realized Price Net of Transportation Expenses 46.11 49.71 44.37 46.72 52.13
Operating Expenses (20.98 ) (15.53) (16.56) (18.76 ) (16.03)
Operating Netback ((1)(3)) $ 25.13 $34.18 $27.81 $ 27.96 $36.10
Canadian Operational Information ((4)) Three Months Ended September 30, Three Months Ended June 30, Nine Months Ended September 30,
2025 2024 2025 2025 2024
Operating Netback ((1)(3))
Gross Profit 3,574 — 3,851 7,217 —
Depletion and Accretion ((*)) 8,348 — 13,700 34,984 —
Operating Netback ((1)(3)) $ 11,922 $— $17,551 $ 42,201 $—
Oil Sales $ 21,884 $— $22,276 $ 64,984 $—
Natural Gas Sales 3,702 — 5,535 16,463 —
NGL Sales 4,314 — 5,519 16,249 —
Royalties (3,250 ) — (2,160) (10,374 ) —
Oil, Natural Gas and NGL Sales After Royalties $ 26,650 $— $31,170 $ 87,322 $—
Operating Expenses (14,403 ) — (13,301) (44,231 ) —
Transportation Expenses (325 ) — (318) (890 ) —
Operating Netback ((1)(3)) $ 11,922 $— $17,551 $ 42,201 $—
Capital Expenditures (Before Changes in Working Capital) $ 9,228 $— $1,796 $ 40,384 $—
Average Daily Production
Crude Oil (bbl/d) 4,013 — 4,335 3,992 —
Natural Gas (mcf/d) 49,260 — 50,124 49,746 —
NGLs (bbl/d) 3,889 — 4,807 4,571 —
WI Production Before Royalties (boe/d) 16,112 — 17,496 16,853 —
Royalties (boe/d) (1,969 ) — (2,187) (2,131 ) —
Production NAR (boe/d) 14,143 — 15,309 14,722 —
Sales (boe/d) 14,143 — 15,309 14,722 —
Royalties, % of WI Production Before Royalties 12 % —% 13% 13 % —%
Benchmark Prices
West Texas Intermediate ($/bbl) 65.07 75.28 63.81 66.74 77.71
AECO Natural Gas Price (C$/GJ) 0.60 0.65 1.60 1.42 1.38
Average Realized Price
Crude Oil ($/bbl) 59.28 — 56.47 59.63 —
Natural Gas ($/mcf) 0.82 — 1.21 1.21 —
NGLs ($/bbl) 12.06 — 12.62 13.02 —
Operating Netback ($/boe) ((1)(3))
Average Realized Price $ 20.17 $— $20.93 $ 21.23 $—
Royalties (2.19 ) — (1.36) (2.25 ) —
Transportation Expenses (0.22 ) — (0.20) (0.19 ) —
Operating Expenses (9.72 ) — (8.35) (9.61 ) —
Operating Netback ((1)(3)) $ 8.04 $— $11.02 $ 9.18 $—
((*)Calculated as DD&A expenses for the three months ended September 30, 2025
and 2024 of $65.0 million and $55.6 million, less depreciation of
administrative assets of $3.1 million and $3.0 million, respectively. For the
nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2
million, less depreciation of administrative assets of $9.5 million and $8.9
million, respectively. For the prior quarter, calculated as DD&A expenses of
$68.6 million, less depreciation of administrative assets of $2.7 million. )
((1)Funds flow from operations, operating netback, net debt, cash netback,
earnings before interest, taxes and depletion, depreciation and accretion
(“DD&A”) (“EBITDA”) and EBITDA adjusted for non-cash lease expense,
lease payments, foreign exchange gains or losses, stock-based compensation
expense, other gains or losses, transaction costs and financial instruments
gains or losses (“Adjusted EBITDA”), cash flow and free cash flow are
non-GAAP measures and do not have standardized meanings under generally
accepted accounting principles in the United States of America (“GAAP”).
Cash flow refers to funds flow from operations. Free cash flow refers to funds
flow from operations less capital expenditures. Refer to “Non-GAAP
Measures” in this press release for descriptions of these non-GAAP measures
and, where applicable, reconciliations to the most directly comparable
measures calculated and presented in accordance with GAAP.)
((2)Gran Tierra’s current average production is for the period from October
1 to October 29, 2025.)
((3)Operating netback, as presented, is defined as gross profit less depletion
and accretion related to producing assets. Management believes that operating
netback is a useful supplemental measure for management and investors to
analyze financial performance and provides an indication of the results
generated by our principal business activities prior to the consideration of
other income and expenses. See the table titled Financial and Operational
Highlights above for the components of consolidated operating netback and
corresponding reconciliation.)
((4)Gran Tierra entered Canada with the acquisition of i3 Energy which closed
October 31, 2024, therefore no comparative data is provided for the
corresponding periods of 2024.)
((5)Gran Tierra’s fourth quarter-to-date 2025 total average differentials
for the period are from October 1 to October 29, 2025.)
Conference Call Information:
Gran Tierra will host its third quarter 2025 results conference call on
Friday, October 31, 2025, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time,
and 3:00 p.m. Greenwich Mean Time. Interested parties may access the
conference call by registering at the following link:
https://register-conf.media-server.com/register/BI7d7b37fa1bf446089868272e73c863d4.
The call will also be available via webcast at www.grantierra.com.
Corporate Presentation:
Gran Tierra’s Corporate Presentation has been updated and is available on
the Company website at www.grantierra.com.
Contact Information
For investor and media inquiries please contact:
Gary Guidry
President & Chief Executive Officer
Ryan Ellson
Executive Vice President & Chief Financial Officer
+1-403-265-3221
info@grantierra.com
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 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.
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”). All statements other than statements of historical facts
included in this press release regarding our business strategy, plans and
objectives of our management for future operations, capital spending plans and
benefits of the changes in our capital program or expenditures, our liquidity
and financial condition, and those statements preceded by, followed by or that
otherwise include the words “expect,” “plan,” “can,” “will,”
“should,” “guidance,” “forecast,” “budget,” “estimate,”
“signal,” “progress”, “anticipates” and “believes,”
derivations thereof and similar terms identify forward-looking statements. In
particular, but without limiting the foregoing, this press release contains
forward-looking statements regarding: : the Company’s expectations regarding
committed funding (including but not limited to the signing of a mandate for
prepayment structure backed by crude oil deliveries), liquidity and its
leverage ratio target, the Company’s plans regarding strategic investments,
acquisitions, dispositions, synergies, and growth, the Company’s drilling
program and capital expenditures and the Company’s expectations of commodity
prices, exploration and production trends and its positioning for 2025. 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, pricing and cost
estimates (including with respect to commodity pricing and exchange rates),
the general continuance of assumed operational, regulatory and industry
conditions in Canada, Colombia and Ecuador, and the ability of Gran Tierra to
execute its business and operational plans in the manner currently planned.
Among the important factors that could cause our actual results to differ
materially from the forward-looking statements in this press release include,
but are not limited to: our ability to successfully integrate the assets and
operations of i3 Energy Plc (“i3Energy”) and realize the anticipated
benefits and operating synergies expected from the 2024 acquisition of i3
Energy; certain of 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 actual or anticipated
tariffs and trade policies, global health crises, geopolitical events,
including the conflicts in Ukraine and the Middle East, 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 the 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 prices and oil 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 access debt or equity capital markets from time to time to raise additional
capital, increase liquidity, fund acquisitions or refinance debt; the risk
that we are unable to successfully negotiate final terms and close an
anticipated prepayment structure backed by crude oil deliveries, our ability
to comply with financial covenants in our indentures and make borrowings under
our credit agreements; 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, 2024
filed February 24, 2025 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.
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 to not imply that more emphasis
should be placed on the non-GAAP measure.
Gross profit is derived from oil, natural gas and NGL sales, net of direct
production costs including operating expenses, transportation, and depletion,
depreciation, and accretion (“DD&A”). Gross profit does not include
general and administrative expenses, interest, taxes, or other non-operating
items.
Operating netback, as presented, is defined as gross profit less depletion and
accretion related to producing assets. Management believes that operating
netback is a useful supplemental measure for management and investors to
analyze financial performance and provides an indication of the results
generated by our principal business activities prior to the consideration of
other income and expenses. A reconciliation from oil sales to operating
netback is provided in the table below.
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, severance expenses, transaction costs,
export tax, realized foreign exchange gain, cash settlement on derivative
instruments, interest expense excluding amortization of debt issuance costs,
interest income other cash gain, net lease payments, and current income tax.
Management believes that operating netback and cash netback are useful
supplemental measures for management and investors to analyze financial
performance and provides an indication of the results generated by our
principal business activities prior to the consideration of other income and
expenses.
Three Months Ended September 30, Three Months Ended June 30, Nine Months Ended September 30,
Operating and Cash Netback – (Non-GAAP) Measure ($000s) 2025 2024 2025 2025 2024
Gross Profit $ 14,670 $ 48,803 $ 23,061 $ 65,568 $ 160,457
Adjustments to reconcile gross profit to operating netback
Depletion and accretion 61,908 52,599 65,947 196,286 158,356
Operating netback (non-GAAP) $ 76,578 $ 101,402 $ 89,008 $ 261,854 $ 318,813
Cash G&A expenses $ 13,453 $ 9,491 $ 14,460 $ 40,056 $ 31,240
Transaction costs $ — $ 1,459 $ — $ — $ 1,459
Export Tax $ 2,630 $ — $ — $ 2,630 $ —
Realized foreign exchange gain (loss) $ 2,149 $ (1,003 ) $ 602 $ 4,902 $ (642 )
Cash settlement on derivative instruments $ (7,461 ) $ — $ (1,631 ) $ (9,535 ) $ —
Interest expense, excluding amortization of debt issuance costs $ 21,178 $ 16,783 $ 20,284 $ 60,864 $ 47,539
Interest income $ (197 ) $ (684 ) $ (251 ) $ (873 ) $ (2,393 )
Other cash gain $ (1,268 ) $ — $ (377 ) $ (1,645 ) $ —
Net lease payments $ 387 $ (199 ) $ (180 ) $ 38 $ (624 )
Current income tax $ 4,022 $ 15,217 $ 2,195 $ 14,482 $ 61,422
Cash netback (non-GAAP) $ 41,685 $ 60,338 $ 53,906 $ 150,935 $ 180,812
EBITDA, as presented, is defined as net income or loss adjusted for DD&A
expenses, interest expense and income tax expense or recovery. Adjusted
EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease
expense, lease payments, foreign exchange gain or loss, stock-based
compensation expense or recovery, transaction costs, other gain or loss and
unrealized derivative instruments gain or loss. 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 useful
supplemental information for investors to analyze our performance and our
financial results. A reconciliation from net income or loss to EBITDA and
adjusted EBITDA is as follows:
Three Months Ended September 30, Three Months Ended June 30, Nine Months Ended September 30,
EBITDA – (Non-GAAP) Measure ($000s) 2025 2024 2025 2025 2024
Net (Loss) Income $ (19,950 ) $ 1,133 $ (12,741 ) $ (51,971 ) $ 37,426
Adjustments to reconcile net loss or income to EBITDA and Adjusted EBITDA
DD&A expenses 64,981 55,573 68,635 205,818 167,213
Interest expense 25,447 19,892 24,366 73,048 56,714
Income tax (recovery) expense (11,276 ) 20,767 4,648 (3,075 ) 29,090
EBITDA $ 59,202 $ 97,365 $ 84,908 $ 223,820 $ 290,443
Non-cash lease expense 1,187 1,370 1,725 4,648 4,164
Lease payments (1,574 ) (1,171 ) (1,545 ) (4,686 ) (3,540 )
Foreign exchange loss (gain) 284 (3,084 ) 3,716 7,838 (8,312 )
Stock-based compensation expense (recovery) 143 (3,145 ) 546 172 6,376
Transaction costs — 1,459 — — 1,459
Other loss 265 — 38 355 —
Unrealized derivative instrument loss (gain) 9,527 — (12,401 ) (964 ) —
Adjusted EBITDA $ 69,034 $ 92,794 $ 76,987 $ 231,183 $ 290,590
Funds flow from operations, as presented, is defined as net income or loss
adjusted for DD&A expenses, deferred tax expense or recovery, stock-based
compensation expense or recovery, amortization of debt issuance costs,
non-cash lease expense, lease payments, unrealized foreign exchange gain or
loss, other gain or loss and unrealized gain or loss on derivative
instruments. 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 both funds flow from operations and
free cash flow is as follows:
Three Months Ended September 30, Three Months Ended June 30, Nine Months Ended September 30,
Funds Flow From Operations – (Non-GAAP) Measure ($000s) 2025 2024 2025 2025 2024
Net (Loss) Income $ (19,950 ) $ 1,133 $ (12,741 ) $ (51,971 ) $ 37,426
Adjustments to reconcile net loss or income to funds flow from operations
DD&A expenses 64,981 55,573 68,635 205,818 167,213
Deferred tax (recovery) expense (15,298 ) 5,550 2,453 (17,557 ) (32,332 )
Stock-based compensation expense (recovery) 143 (3,145 ) 546 172 6,376
Amortization of debt issuance costs 4,269 3,109 4,082 12,184 9,175
Non-cash lease expense 1,187 1,370 1,725 4,648 4,164
Lease payments (1,574 ) (1,171 ) (1,545 ) (4,686 ) (3,540 )
Unrealized foreign exchange (gain) loss (1,865 ) (2,081 ) 3,114 2,936 (7,670 )
Other loss 265 — 38 355 —
Unrealized derivative instrument loss (gain) 9,527 — (12,401 ) (964 ) —
Funds flow from operations $ 41,685 $ 60,338 $ 53,906 $ 150,935 $ 180,812
Capital expenditures $ 57,340 $ 52,921 $ 51,170 $ 203,237 $ 169,525
Free cash flow $ (15,655 ) $ 7,417 $ 2,736 $ (52,302 ) $ 11,287
Net debt as of September 30, 2025, was $755 million, calculated using the sum
of the aggregate principal amount of 7.75% Senior Notes, 9.50% Senior Notes
outstanding and amount drawn on credit facilities, excluding deferred
financing fees, totaling $804 million, less cash and cash equivalents of $49
million. 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.
Presentation of Oil and Gas Information
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. 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.
This press release contains certain oil and gas metrics, including operating
netback and cash netback, 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. These metrics are calculated as described in this press release
and management believes that they are useful supplemental measures for the
reasons described in this press release.
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
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