All references herein to $ refer to United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
President & CEO, Corey C. Ruttan commented:
"2025 was a transformational year for Alvopetro. Mainly off the success of our 183-D4 well on our 100% owned Murucututu asset, year-over-year we increased average daily sales by 41% to 2,523 boepd and grew 2P reserves by 43% to 13.1 MMboe, replacing production over 5 times. With record production to start the year, we are well positioned for another exceptional year in 2026."
Operational Update
Following the success of our 183-D4 well on our 100% owned Murucututu field, we are now focused on enhancing and expanding our capacity to deliver additional Murucututu production, positioning this asset for sustained multi-year growth. We plan to expand our Murucututu field production facility and pipelines to support an increase in our Murucututu field capacity from our current level of approximately 150 e3m3/d up to 600 e3m3/d. Simultaneously, we plan to enhance our gas processing capabilities at UPGN Caburé to accommodate higher proportions of richer gas from Murucututu, and also targeting an overall capacity of up to 600 e3m3/d.
On the drilling and completions front, on our 100% owned Murucututu field, we have just recompleted our 183-1 well in a lower portion of the Gomo Formation and are working to bring the well back online. Upcoming plans on the field in 2026 involve drilling and completing a new well in the Caruaçu Formation, as well as permitting a new drilling pad to support future Caruaçu development updip of the successful 183-D4 well. We expect drilling to commence next month. At Caburé (56.2% working interest), 2026 capital plans include the sidetrack of one unfinished well from 2025.
In Canada, we have completed drilling two (1.0 net) additional wells in 2026 . One (0.5 net) well requires remedial action but we now have 7 (3.5 net) wells on production. We have also added an additional 5 gross sections of land in one of our core-areas bringing our land position to 80.5 gross sections (25,760 net acres) targeting the Mannville stack heavy oil play fairway with over 100 Tier 1 drilling locations.
On February 25, 2026, we announced our December 31, 2025 reserves based on the independent reserve assessment and evaluation prepared by GLJ Ltd. ("GLJ") dated February 25, 2026 with an effective date of December 31, 2025 (the "GLJ Reserves and Resources Report"). Highlights include:
1P reserves increased 79% to 8.1 MMboe after 2025 production of 0.9 MMboe, representing a 1P production replacement ratio(1) of 485%. The increase was mainly due to results from our 183-D4 well on our Murucututu field which commenced production in August 2025 and added an additional five proved undeveloped locations to our 1P reserves as well as newly added Canadian reserves of 0.3 MMboe.
2P reserve volumes increased 43% to 13.1 MMboe, representing a 2P production replacement ratio of 530%(1). Success on our 183-D4 well also contributed to the bulk of the increase to 2P reserves which includes eight undeveloped locations. In Canada, 0.7 MMboe of 2P reserves were assigned.
With increased reserve volumes, 1P net present value before tax, discounted at 10% ("NPV10") increased 38% to $245.6 million and 2P NPV10 increased 20% to $393.6 million.
2P reserves life index(1) of 12.5 years.
2P F&D costs(1) of $15.42/boe with a 2P recycle ratio(1) of 3.4 times.
Risked best estimate contingent resources decreased by 0.7 MMboe from 4.5 MMboe to 3.8 MMboe at December 31, 2025 with a NPV10 of $88.0 million, decreases from December 31, 2024 of 16% and 20% respectively. The decreases were associated with the migration of contingent resources to Reserves for the Caruaçu Formation at Murucututu.
Risked best estimate prospective resources increased from 10.2 MMboe to 12.1 MMboe with a NPV10 of $264.3 million, increases of 19% and 27% respectively from December 31, 2024. The increases were mainly due to additional prospective resource in the Caruaçu Formation at Murucututu adjacent to the assigned reserves area.
(1)
Refer to the sections entitled "Oil and Natural Gas Advisories, Other Metrics" for additional disclosures and assumptions used in calculating production replacement ratio, 2P reserves life index, 2P F&D costs and 2P recycle ratio.
Financial and Operating Highlights, Fourth Quarter of 2025
Average daily sales in Q4 2025 were 2,867 boepd(1) (+65% from Q4 2024 and +22% from Q3 2025). In Brazil, daily sales averaged 2,719 boepd (+56% compared to Q4 2024 and +23% from Q3 2025) and in Canada, oil sales averaged 148 bopd in the quarter (+7% from Q3 2025).
Our average realized natural gas price was $9.97/Mcf (-5% from Q4 2024 and -10% from Q3 2025). Our overall average realized sales price per boe was $59.75/boe (-6% from Q4 2024 and -9% from Q3 2025).
Our natural gas, oil and condensate revenue increased to $15.8 million (+54% from Q4 2024 and +11% from Q3 2025). The increases compared to Q4 2024 and Q3 2025 were driven by higher sales volumes, partially offset by lower realized prices.
Our operating netback(2) in the quarter was $49.70 per boe, a decrease of $5.39 per boe compared to Q4 2024 and a decrease of $6.20 per boe compared to Q3 2025 due mainly to lower realized prices and higher royalties.
We generated funds flows from operations(2) of $10.6 million ($0.28 per basic and per diluted share), increases of $3.6 million compared to Q4 2024 and $0.1 million compared to Q3 2025.
We reported net income of $5.6 million ($0.15 per basic and diluted share), an increase of $3.3 million compared to Q4 2024.
In October 2025, Alvopetro entered into an expanded area of mutual interest (the "Expanded AMI") with our existing partner in Saskatchewan. Under the terms of the Expanded AMI, Alvopetro agreed to fund 100% of the costs for drilling two earning wells in exchange for a 50% working interest in an additional 46.9 sections of land (15,010 net acres). The two earning wells were drilled in Q4 2025. Capital expenditures in Q4 2025 of $4.9 million included the cost of these two earning wells and a seismic program in Saskatchewan, additional Unit development costs to tie in the wells drilled earlier in the year as well as costs for facilities improvements at the Unit and Murucututu.
During the quarter Alvopetro entered into a $20 million loan agreement (the "Loan"). The Loan has a two-year term and bears interest at 7% per annum (payable quarterly), including all applicable charges and fees. Repayments of the Loan commence quarterly on November 30, 2026, ending on November 29, 2027.
Our working capital(2) surplus was $18.5 million as of December 31, 2025. Our working capital surplus net of debt was $2.5 million as of December 31, 2025.
Financial and Operating Highlights, Year Ended December 31, 2025
Our annual sales volumes averaged 2,523 boepd, an increase of 41% from 2024, with Brazil sales volumes of 2,417 boepd (+35% from 2024) and 106 bopd from the newly added Canadian operations.
We reported net income of $23.1 million, compared to $16.3 million in 2024 (+42%).
We generated funds flow from operations(1) of $40.6 million ($1.09 per basic share and $1.08 per diluted share), an increase of $7.3 million (+22%) compared to 2024.
Capital expenditures totaled $33.5 million in 2025.
Dividends declared totaled $0.42 per share in 2025 compared to $0.36 per share in 2024 (+17%).
(1) Alvopetro reported volumes are based on sales volumes which, due to the timing of sales deliveries, may differ from production volumes.(2) See "Non-GAAP and Other Financial Measures" section within this news release.
The following table provides a summary of Alvopetro's financial and operating results for the periods noted. The consolidated financial statements with the Management's Discussion and Analysis ("MD&A") are available on our website at www.alvopetro.com and will be available on the SEDAR+ website at www.sedarplus.ca.
As at and Three Months Ended
December 31,
As at and Year Ended
December 31,
2025
2024
Change (%)
2025
2024
Change (%)
Financial
($000s, except where noted)
Natural gas, oil and condensate sales
15,756
10,214
54
57,954
45,517
27
Net income
5,585
2,243
149
23,098
16,295
42
Per share, basic ($)(1)
0.15
0.06
150
0.62
0.44
41
Per share, diluted ($)(1)
0.15
0.06
150
0.61
0.43
42
Cash flows from operating activities
9,362
7,114
32
40,805
34,901
17
Per share, basic ($)(1)
0.25
0.19
32
1.09
0.94
16
Per share, diluted ($)(1)
0.25
0.19
32
1.08
0.93
16
Funds flow from operations(2)
10,561
6,966
52
40,597
33,275
22
Per share, basic ($)(1)
0.28
0.19
47
1.09
0.89
22
Per share, diluted ($)(1)
0.28
0.19
47
1.08
0.89
21
Dividends declared
4,408
3,283
34
15,384
13,170
17
Per share(1) (2)
0.12
0.09
33
0.42
0.36
17
Capital expenditures
4,883
4,682
4
33,493
15,305
119
Cash and cash equivalents
32,372
21,697
49
32,372
21,697
49
Net working capital(2)
18,450
13,181
40
18,450
13,181
40
Working capital, net of debt(2)
2,450
13,181
(81)
2,450
13,181
(81)
Weighted average shares outstanding
Basic (000s)(1)
37,260
37,315
-
37,270
37,289
-
Diluted (000s)(1)
37,717
37,566
-
37,666
37,558
-
Operations
Average daily sales volumes(3):
Brazil:
Natural gas (Mcfpd), by field:
Caburé (Mcfpd)
9,655
7,476
29
10,467
9,228
13
Murucututu (Mcfpd)
5,437
2,231
144
3,080
928
232
Total natural gas (Mcfpd)
15,092
9,707
55
13,547
10,156
33
NGLs, condensate (bopd)
184
109
69
149
90
66
Oil (bopd)
19
