The following Management's Discussion and Analysis ("MD&A") is dated November 5, 2025 and should be read in conjunction with the unaudited interim condensed consolidated financial statements and accompanying notes of Alvopetro Energy Ltd. ("Alvopetro" or the "Company") as at and for the three and nine months ended September 30, 2025, MD&A for the year-ended December 31, 2024 and the audited consolidated financial statements as at and for the years ended December 31, 2024 and 2023. Additional information for the Company, including the Annual Information Form ("AIF"), can be found on SEDAR+ at www.sedarplus.ca or at www.alvopetro.com. This MD&A contains financial terms that are not considered measures under IFRS Accounting Standards ("IFRS") and forward-looking statements. As such, the MD&A should be used in conjunction with Alvopetro's disclosure under the headings "Non-GAAP and Other Financial Measures" and "Forward Looking Information" at the end of this MD&A.

All amounts contained in this MD&A are in United States dollars ("USD"), unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.

MANAGEMENT'S DISCUSSION AND ANALYSIS

OVERVIEW

Description of Business

Alvopetro is engaged in the exploration for and the acquisition, development and production of hydrocarbons in Brazil and Canada. Alvopetro's shares are traded on the TSX Venture Exchange (TSX: ALV.V) and are also traded on the OTCQX® Best Market in the United States (OTCQX: ALVOF).

Strategy

Alvopetro is deploying a balanced capital allocation model where we seek to reinvest roughly half our cash flows into organic growth opportunities and return the other half to stakeholders. Alvopetro's organic growth strategy is to focus on the best combinations of geologic prospectivity and fiscal regime. Alvopetro is balancing capital investment opportunities in Canada and Brazil where we are building off the strength of our Caburé and Murucututu natural gas fields and the related strategic midstream infrastructure.

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

FINANCIAL & OPERATING SUMMARY

	As at and Three Months Ended			As at and Nine Months Ended
	September 30,			September 30,
	2025	2024	Change	2025	2024	Change (%)
Financial
($000s, except where noted)
Natural gas, oil and condensate sales	14,175	12,879	10	42,198	35,303	20
Net income	4,613	7,152	(36)	17,513	14,052	25
Per share – basic ($)(1)	0.12	0.19	(37)	0.47	0.38	24
Per share – diluted ($)(1)	0.12	0.19	(37)	0.46	0.37	24
Cash flows from operating activities	12,153	10,714	13	31,443	27,787	13
Per share – basic ($)(1)	0.33	0.29	14	0.84	0.75	12
Per share – diluted ($)(1)	0.32	0.28	14	0.83	0.74	12
Funds flow from operations(2)	10,448	9,886	6	30,036	26,309	14
Per share – basic ($)(1)	0.28	0.27	4	0.81	0.71	14
Per share – diluted ($)(1)	0.28	0.26	8	0.79	0.70	13
Dividends declared	3,673	3,295	11	10,976	9,887	11
Per share(1)(2)	0.10	0.09	11	0.30	0.27	11
Capital expenditures	11,249	4,747	137	28,610	10,623	169
Cash and cash equivalents	12,081	24,515	(51)	12,081	24,515	(51)
Net working capital(2)	2,209	15,848	(86)	2,209	15,848	(86)
Weighted average shares outstanding
Basic (000s)(1)	37,263	37,300	-	37,273	37,286	-
Diluted (000s)(1)	37,851	37,662	1	37,801	37,671	-
Operations
Average daily sales volumes(3):
Brazil:
Natural gas (Mcfpd), by field:
Caburé (Mcfpd)	8,735	11,378	(23)	10,741	9,817	9
Murucututu (Mcfpd)	3,558	616	478	2,286	490	367
Total natural gas (Mcfpd)	12,293	11,994	2	13,027	10,307	26
NGLs – condensate (bopd)	147	95	55	137	83	65
Oil (bopd)	9	12	(25)	8	12	(33)
Total (boepd) - Brazil	2,205	2,106	5	2,315	1,813	28
Canada:
Oil (bopd) - Canada	138	-	-	93	-	-
Total Company (boepd)	2,343	2,106	11	2,408	1,813	33
Average realized prices(2):
Natural gas ($/Mcf)	11.04	10.92	1	10.69	11.70	(9)
NGLs – condensate ($/bbl)	74.16	86.70	(14)	75.83	88.77	(15)
Oil ($/bbl)	50.42	68.36	(26)	49.36	68.48	(28)
Total ($/boe)	65.76	66.46	(1)	64.19	71.06	(10)
Operating netback ($/boe)(2)
Realized sales price	65.76	66.46	(1)	64.19	71.06	(10)
Royalties	(3.54)	(1.89)	87	(4.71)	(1.94)	143
Production expenses	(6.10)	(5.38)	13	(5.58)	(6.23)	(10)
Transportation expenses	(0.22)	-	-	(0.12)	-	-
Operating netback	55.90	59.19	(6)	53.78	62.89	(14)
Operating netback margin(2)	85%	89%	(4)	84%	89%	(6)

Notes:
(1) Per share amounts are based on weighted average shares outstanding other than dividends per share, which is based on the number of common shares outstanding at each dividend record date. The weighted average number of diluted common shares outstanding in the computation of funds flow from operations and cash flows from operating activities per share is the same as for net income per share.
(2) See "Non-GAAP and Other Financial Measures" section within this MD&A.
(3) Alvopetro reported volumes are based on sales volumes which, due to the timing of sales deliveries, may differ from production volumes.

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

HIGHLIGHTS AND SIGNIFICANT TRANSACTIONS FOR THE THIRD QUARTER OF 2025

Average daily sales in Q3 2025 were 2,343 boepd⁽¹⁾ (+11% from Q3 2024 and -4% from Q2 2025). In Brazil, daily sales averaged 2,205 boepd (+5% compared to Q3 2024 and -4% from Q2 2025) and in Canada, oil sales averaged 138 bopd in the quarter (consistent with Q2 2025).
Our average realized natural gas price was $11.04/Mcf (+1% from Q3 2024 and +4% from Q2 2025). Our overall averaged realized sales price per boe was $65.76/boe (-1% from Q3 2024 and +4% from Q2 2025).
Our natural gas, oil and condensate revenue increased to $14.2 million (+10% from Q3 2024 and +1% from Q2 2025). Compared to Q3 2024, the increase was driven by higher overall sales volumes, partially offset by lower realized prices. Compared to Q2 2025, the increase was as a result of higher realized prices, partially offset by lower sales volumes.
Our operating netback⁽²⁾ in the quarter was $55.90 per boe, a decrease of $3.29 per boe compared to Q3 2024 due mainly to addition of lower overall netbacks from Canadian operations. Compared to Q2 2025, our operating netback increased $1.18 per boe with higher realized prices, partially offset by higher royalties, production expenses and transportation expenses.
We generated funds flows from operations⁽²⁾ of $10.4 million ($0.28 per basic and per diluted share), increases of $0.6 million compared to Q3 2024 and $0.1 million compared to Q2 2025.
We reported net income of $4.6 million ($0.12 per basic and diluted share), a decrease of $2.5 million compared to Q3 2024 due mainly to impairment losses and higher depletion and depreciation expenses recognized in Q3 2025, partially offset by higher revenues with increased sales volumes, and lower tax expenses.
Capital expenditures totaled $11.2 million, including completion costs for the 183-D4 well on Alvopetro's 100% Murucututu field, Alvopetro's share of unit development costs on the Caburé field and Alvopetro's share of costs to drill and equip an additional two wells (1.0 net) in Saskatchewan.
Our working capital⁽²⁾ surplus was $2.2 million as of September 30, 2025, decreasing $4.6 million from June 30, 2025.

RECENT HIGHLIGHTS

October sales volumes averaged 2,923 boepd⁽¹⁾, including 2,766 boepd from Brazil (with natural gas sales of 15.3 MMcfpd, associated natural gas liquids sales from condensate of 206 bopd, and oil sales of 18 bopd) and 157 bopd from oil sales in Canada, based on field estimates, setting a new record for sales volumes at Alvopetro. Starting October 1, 2025, Alvopetro agreed to discounted spot pricing for daily volumes above our firm contracted volumes, contributing to higher sales in October.
In October 2025, Alvopetro entered into an expanded area of mutual interest (the "Expanded AMI") with our existing partner. Under the terms of the Expanded AMI, Alvopetro has 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).
Effective November 1, 2025, our natural gas price under our long-term gas sales agreement ("GSA") was adjusted to BRL1.81/m³ and will apply to all natural gas under our firm contract (up to 400,000 m³/d reference volumes (14.1MMcfpd)) from November 1, 2025 to January 31, 2026. Based on our average heat content to date and the October 31, 2025 BRL/USD exchange rate of 5.38, our expected realized price at the new contracted price is US$10.15/Mcf, net of applicable sales taxes, a decrease of 8% from the Q3 2025 realized price of $11.04/Mcf due to reduced Henry Hub prices in the third quarter as well as fluctuations in BRL relative to the USD. Amounts ultimately received in equivalent USD will be impacted by exchange rates in effect during the period November 1, 2025 to January 31, 2026.

⁽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 MD&A.

NATURAL GAS AND OIL PROPERTIES

As at September 30, 2025, Alvopetro held interests in the Caburé and Murucututu natural gas assets and one exploration block (Block 183), in the Recôncavo Basin onshore Brazil as well as a 50% non-operated working interest in 27.5 sections of land (13.8 sections net to Alvopetro) focused on the Mannville Formations in Western Saskatchewan.

BRAZIL

NATURAL GAS ASSETS AND MIDSTREAM INFRASTRUCTURE:

Caburé Natural Gas Field (56.2% Working Interest)

Alvopetro commenced commercial natural gas deliveries from the Caburé natural gas field (the “Caburé Field”) on July 5, 2020. The Caburé Field extends across four blocks in the Recôncavo Basin in the state of Bahia in Brazil (the “Unit”), two of which are held by Alvopetro and two of which are held by our partner (the “Partner”). Under Brazilian legislation, petroleum accumulations straddling two or more licensed blocks must undergo unitization (pooling) in order to promote efficient and fair exploration and development. In April 2018, Alvopetro and the Partner finalized the terms of the Unit Operating Agreement (“UOA”), the unit development plan and all related agreements, with Alvopetro’s Partner being named initial operator.

Under the terms of the UOA, the working interest to each party is subject to redeterminations and the first redetermination was completed in 2024 wherein the appointed independent third party expert (the “Expert”) accepted Alvopetro’s final proposal which resulted in Alvopetro’s working interest in the Unit being increased from our initial working interest of 49.1% to 56.2% (the “Redetermined Working Interest”) effective June 1, 2024. Alvopetro’s partner is disputing the Expert decision; however the findings of an emergency arbitration before the International Court of Arbitration of the International Chamber of Commerce (“ICC”), deemed the Expert decision to be binding until reviewed by an arbitral tribunal pursuant to the Rules of Arbitration (the “Rules”) of the ICC as provided for under the terms of the UOA. The full arbitration process is currently underway. See the section entitled “Risks and Uncertainties – Arbitration of Alvopetro’s Working Interest and Impact of Future Redeterminations” within the MD&A for the year ended December 31, 2024 for additional information. Operatorship of the Unit transitioned to Alvopetro in the third quarter of 2024.

Under the terms of the UOA each party is entitled to nominate for their working interest share of Unit production and for any natural gas not nominated for by the other party. Once a party produces their share of estimated proved plus probable recoverable hydrocarbons from the Unit, they will no longer be entitled to further production allocations. As of June 1, 2024, Alvopetro is entitled to 56.2% of natural gas production from the Unit plus any natural gas production not nominated by our Partner. Alvopetro’s ability to sell its share of natural gas production from the Unit is dependent on natural gas demand, subject to firm volumes pursuant to take-or-pay provisions under the terms of our gas sales agreement, as further described below.

Natural gas liquids (“NGLs”) production from the Unit (relating to condensate production) is split based on working interest. As of June 1, 2024, Alvopetro is entitled to 56.2% of NGL production from the Unit plus an additional 5% to recover the historical shortfall of NGL production that was allocated at the original 49.1% working interest.

The parties agreed to a 2025 development plan at the Unit including drilling and completing five (2.8 net) wells. Four (2.2 net) of the five development wells have now been drilled. Alvopetro’s share of unit development costs for the nine months ended September 30, 2025 was $7.4 million, with $5.4 million incurred in the third quarter. The timing of drilling of the fifth planned development well (0.6 net) is subject to receipt of regulatory approvals.

In January 2025 Alvopetro completed the commissioning phase of our recently installed compression system at the Caburé field, increasing our productive capacity from the Unit. Total capital expenditures of $0.3 million were incurred on this project in 2025.

Murucututu Natural Gas Field (100% Working Interest)

Alvopetro’s Murucututu natural gas project extends across Blocks 183 and 197, both held 100% by Alvopetro. There are four existing wells at the field including the 197(1) well and the 183(1) well, both of which were drilled in 2014, and the 183-A3 well which was drilled in 2023 and recompleted in the third quarter of 2024. The 183-D4 well was drilled in the first half of 2025 and in the third quarter, the well was completed in seven intervals. Total capital expenditures on the field in the nine months ended September 30, 2025 of $13.0 million and $3.6 million in the third quarter of 2025 largely related to this well. The well commenced production later

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

in August. Over the first 30 days of production, the well produced at an average rate of 5.8 MMcfpd (165 e³m³/d) and 97 bopd of NGLs. As a result, natural gas sales from the field increased to 3.6 MMcfpd in Q3 2025 (+478% from Q3 2024).

All Murucututu wells are tied into field production facilities. A 9-kilometre transfer pipeline connects the field to the Caburé transfer pipeline and to the natural gas processing facility.

Natural Gas Sales (100% Alvopetro)

Alvopetro's share of natural gas from the Caburé Field and the Murucututu natural gas field is shipped via our 11-kilometre Caburé transfer pipeline and processed through the natural gas processing facility (the "Facility") owned and operated by Enerflex Ltd. ("Enerflex") pursuant to our Gas Treatment Agreement. All natural gas is sold to Bahiagás, the local state distribution company, under the terms of our gas sales agreement ("GSA") and spot sales contracts from time to time.

The GSA provides for the sale of firm volumes and interruptible volumes and has take-or-pay provisions and ship-or-pay penalties based on firm volumes to ensure performance by both parties. In late 2024 Alvopetro and Bahiagás agreed to amend the terms of the GSA, increasing firm volumes by 33% to 14.1 MMcfpd (400 e³m³/d) effective January 1, 2025.

Take-or-pay provisions apply under the terms of the GSA where Bahiagás demand is below the firm volumes set out in the GSA. See "Sales Volumes" below for further details.

OIL ASSETS:

The Company has two oil fields (Bom Lugar and Mãe-da-lua). In the third quarter of 2025, Alvopetro entered into an assignment agreement to dispose of its interests in both fields for total consideration of $0.6 million, including deferred consideration. The closing of the sale is subject to standard regulatory approvals, including approval by the ANP. In the third quarter of 2025, Alvopetro transferred these properties and related liabilities to assets held for sale and liabilities held for sale. An impairment loss of $1.9 million was recognized at the time of the transfer.

EXPLORATION ASSETS (Block 183)

Alvopetro's E&E assets include the portion of Block 183 that is not part of the Murucututu project. Block 183 includes the 183-B1 well which was drilled in 2022. In Q4 2024, Alvopetro re-entered the existing wellbore with a plan to sidetrack the well.. Operational challenges prevented the project from continuing and the Company now plans to abandon the well. The Company has identified an additional prospect on the block which is expected to be drilled in advance of the newly extended expiry date of October 1, 2027.

WESTERN CANADA

In Q1 2025, Alvopetro entered into a farmin agreement with a private company in Canada (the "Farmin"). Under the terms of the Farmin, Alvopetro agreed to fund 100% of two earning wells in exchange for a 50% non-operated working interest in 12,243 acres of land in Western Saskatchewan. The two earning wells were drilled, completed and equipped and sales commenced in mid-April. In Q3 2025, an additional two wells (1.0 net to Alvopetro) were drilled, completed and equipped and sales commenced in September 2025. We currently hold a 50% non-operated working interest in 17,780 acres (8,890 acres net) in Western Saskatchewan.

In October 2025, Alvopetro entered into the Expanded AMI, with Alvopetro agreeing 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). These two earning wells are expected to be drilled near the end of the year and after drilling, Alvopetro will have a 50% interest in 74.4 sections of land (23,900 net acres).

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

FINANCIAL AND OPERATING REVIEW

Canadian operations commenced in the three months ended June 30, 2025. As such, all 2024 comparative data included in this MD&A relating to sales volumes, realized sales prices, natural gas, condensate and oil revenues, royalties, production expenses and operating netback relate solely to operations in Brazil.

Sales Volumes

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Total sales volumes(1):
Brazil:
Caburé (Mcf)	803,577	1,046,720	(23)	2,932,309	2,689,915	9
Murucututu (Mcf)	327,358	56,696	477	624,074	134,243	365
Total natural gas (Mcf)	1,130,935	1,103,416	2	3,556,383	2,824,158	26
NGLs – condensate (bbls)	13,525	8,731	55	37,295	22,766	64
Oil (bbls)	849	1,141	(26)	2,067	3,344	(38)
Total sales (boe) - Brazil	202,863	193,775	5	632,092	496,803	27
Canada:
Total oil sales (bbls) - Canada	12,696	-	-	25,263	-	-
Total Company sales (boe)	215,559	193,775	11	657,355	496,803	32
Average daily sales volumes(1):
Brazil:
Caburé (Mcfpd)	8,735	11,378	(23)	10,741	9,817	9
Murucututu(Mcfpd)	3,558	616	478	2,286	490	367
Total natural gas (Mcfpd)	12,293	11,994	2	13,027	10,307	26
NGLs – condensate (bopd)	147	95	55	137	83	65
Oil (bopd)	9	12	(25)	8	12	(33)
Average daily sales (boepd) - Brazil	2,205	2,106	5	2,315	1,813	28
Canada:
Average daily sales (bopd) - Canada	138	-	-	93	-	-
Average daily sales (boepd) - Total	2,343	2,106	11	2,408	1,813	33

(1) Alvopetro reported volumes are based on sales volumes which, due to the timing of sales deliveries, may differ from production volumes.

In Brazil, average daily sales volumes increased 5% compared to Q3 2024 and 28% in the nine months ended September 30, 2025 compared to the same period in 2024. Brazil sales decreased 4% from the Q2 2025 average daily sales of 2,298 boepd due mainly to a reduction in natural gas demand from end users.

In Canada, average daily sales volumes of 138 bopd were consistent with Q2 2025 sales volumes.

Average Daily Sales, by Quarter (boepd)

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Take-or-pay provisions – Brazil GSA

Under the terms of the GSA, Bahiagás must prepay for gas volumes where monthly demand is below 80% (or where annual demand is less than 90%) of the firm contract reference volumes under our contract. Any prepayment will be recovered through future natural gas deliveries where future offtake exceeds 90% of the firm volumes. Prepayment under the take-or-pay provisions in the GSA is reflected as unearned revenue through other liabilities on the Corporation’s consolidated statement of financial position and only recognized as revenue when the volumes are delivered. The take-or-pay provisions under the GSA did not apply at any time in the nine months ended September 30, 2025 or September 30, 2024.

Average Realized Sales Prices

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Average realized prices(1):
Brazil:
Natural gas ($/Mcf)	11.04	10.92	1	10.69	11.70	(9)
NGL – condensate ($/bbl)	74.16	86.70	(14)	75.83	88.77	(15)
Oil ($/bbl)	61.25	68.36	(10)	61.93	68.48	(10)
Average realized price ($/boe) - Brazil	66.76	66.46	-	64.83	71.06	(9)
Canada:
Average realized price - Oil ($/bbl)	49.70	-	-	48.33	-	-
Total Company:
Natural gas ($/Mcf)	11.04	10.92	1	10.69	11.70	(9)
NGL – condensate ($/bbl)	74.16	86.70	(14)	75.83	88.77	(15)
Oil ($/bbl)	50.42	68.36	(26)	49.36	68.48	(28)
Average realized price ($/boe)	65.76	66.46	(1)	64.19	71.06	(10)
Average benchmark prices:
Henry Hub ($/MMBtu)	3.03	2.11	44	3.45	2.11	64
Brent oil ($/bbl)	69.03	80.01	(14)	71.00	82.50	(14)
WTI ($/bbl)	65.78	76.43	(14)	67.31	78.58	(14)
WCS ($/bbl)	54.43	62.27	(13)	55.86	62.32	(10)
WCS (C$/bbl)	74.95	84.93	(12)	78.09	84.76	(8)
Average contracted natural gas price(2)
BRL/m³	1.96	1.94	1	1.97	1.95	1
Average foreign exchange rate:
$1 USD = BRL	5.449	5.545	2	5.560	5.244	(6)
$1 USD = CAD	1.377	1.364	(1)	1.398	1.360	(3)

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.
(2) Under the terms of the GSA, the volumes delivered are adjusted for heat content in the determination of the final amounts paid, representing a gross-up of approximately 8% to the contracted volumetric natural gas price, which contributes to a higher realized price overall relative to the contractual price. The contracted price is then grossed-up for applicable sales taxes.

Brazil

In December 2024, Alvopetro and Bahiagás agreed to amend the GSA effective January 1, 2025 to increase contracted firm reference volumes to 400 e³m³/d (14.1 MMcfpd) and to adjust the natural gas pricing model. Under the new pricing structure, the natural gas price is recalculated on a quarterly basis (rather than a semi-annual basis as in 2024 and prior years) and incorporates average USD benchmark prices for Brent and Henry Hub (no longer incorporating National Balancing Point prices). In addition, the floor and ceiling provisions with the original GSA were removed. The natural gas price is then converted to a BRL-denominated natural gas price based on historical average foreign exchange rates and billed monthly in BRL until the next price reset. As all invoices are issued in BRL, actual receipts and revenue recognized in equivalent USD will be subject to exchange rate variations. See "Foreign Exchange" discussion below.

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Alvopetro's average contracted price increased 1% in Q3 2025 compared to Q3 2024 and in the nine months ended September 30, 2025 compared to 2024. However, for the nine months ended September 30, 2025, our realized gas price decreased 9% due to the depreciation of the average BRL to USD in 2025 compared to 2024.

Condensate production from the Caburé Unit, the Murucututu natural gas field and the Facility is sold pursuant to contracts based on Brent, typically at a premium. Oil sales from the Bom Lugar field and the Mãe-da-lua fields are sold at a discount to Brent.

Canada

Oil sales in Canada are sold pursuant to contracts based on Canadian dollar Western Canadian Select ("WCS") prices, adjusted for quality discounts relative to the benchmark price.

All sales and realized prices are reported net of applicable sales taxes.

Natural Gas, Oil and Condensate Sales Revenue

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Brazil:
Natural gas	12,489	12,044	4	38,021	33,053	15
Condensate	1,003	757	32	2,828	2,021	40
Oil	52	78	(33)	128	229	(44)
Total - Brazil	13,544	12,879	5	40,977	35,303	16
Canada:
Oil – Total Canada	631	-	-	1,221	-	-
Total Company:
Natural gas	12,489	12,044	4	38,021	33,053	15
Condensate	1,003	757	32	2,828	2,021	40
Oil	683	78	776	1,349	229	489
Total Company	14,175	12,879	10	42,198	35,303	20

Total natural gas, oil and condensate revenues increased by $1.3 million (+10%) compared to Q3 2024 due to the 11% increase in average daily production, partially offset by the 1% decrease in the average realized sales price.

Royalties

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Royalties – Brazil	664	367	81	2,900	966	200
Royalties – Canada	99	-	-	195	-	-
Royalties – Total Company	763	367	108	3,095	966	220
Royalties per boe ($)(1):
Brazil	3.27	1.89	73	4.59	1.94	137
Canada	7.80	-	-	7.72	-	-
Royalties per boe ($)(1) – Total Company	3.54	1.89	87	4.71	1.94	143
Royalties as a % of sales(1)
Brazil	4.9%	2.8%	75	7.1%	2.7%	163
Canada	15.7%	-	-	16.0%	-	-
Royalties as a % of sales(1)–Total Company	5.4%	2.8%	93	7.3%	2.7%	170

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

Brazil

Alvopetro's sales (other than sales from the Bom Lugar field) are subject to a base 7.5% government royalty plus a 1% landowner royalty. The Bom Lugar field is subject to a base 5% government royalty plus a 0.5% landowner royalty. Government and landowner royalties on natural gas are based on production volumes at an inherent reference price attributable to the raw natural gas produced

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

at the wellhead (prior to midstream processing), resulting in lower effective royalty rates compared to base royalty rates. As Henry Hub spot prices are a significant component of the reference price used for natural gas royalties, Alvopetro's effective royalty rate fluctuates with changes in Henry Hub prices relative to Alvopetro's contracted natural gas price. With Henry Hub increasing $44\%$ in Q3 2025 compared to Q3 2024, government and landowner royalties increased as a percentage of sales.

There is an additional $2.5\%$ gross-overriding royalty ("GORR") on the portion of the Alvopetro's fields that were previously on Block 197. In Q1 2025, Alvopetro recognized an additional amount owing with respect to the GORR on natural gas from Block 197, the computation of which is in dispute with the holders of the GORR. Pursuant to dispute resolution provisions, the matter proceeded to arbitration following the Rules of Arbitration of the ICC. In 2025 Alvopetro received the decision of the arbitral tribunal finding in favour of the GORR holders, requiring Alvopetro to adjust the sales price used in the computation of the GORR. Alvopetro has estimated the additional GORR owing pursuant to the decision of the tribunal and recognized the expected additional royalty (including inflation adjustments) in 2025 with interest owing on the balance outstanding recognized in finance expenses. The additional GORR is estimated from the date natural gas sales commenced in July 2020. The final amount owing by Alvopetro is uncertain as of the date of this MD&A as it remains subject to the subject to the calculation method chosen by the arbitral tribunal and may be adjusted by the tribunal. As a result, the ultimate amount owing may be different than the amounts recognized by Alvopetro and such difference may be material. Q1 2025 royalties include the GORR relating to the three months ended March 31, 2025 as well as the GORR adjustment impacting prior periods (from the date natural gas sales commenced in July 2020 to December 31, 2024) resulting in higher royalties in the nine months ended September 30, 2025. Q3 2025 royalties include the additional GORR estimate relating to the three months ended September 30, 2025. For future periods we would expect our Brazilian royalties to be approximately $5\%$ to $7\%$ of natural gas, oil and condensate revenues, based on forecasted commodity prices, subject to the final outcome of the GORR dispute.

Western Canada

Royalties in Canada include Saskatchewan Crown royalties, Saskatchewan resource surcharge as well as royalties paid to freehold mineral rights owners and gross-overriding royalty holders. Royalties vary depending on the specific contract terms in place. With respect to Crown royalty charges in Saskatchewan, the government has a multi-lateral oil well drilling incentive program effective for wells drilled from April 1, 2024 to March 31, 2028, reducing the Crown royalty rate for a set volume of production depending on the number of laterals drilled. One (0.5 net) of the four producing wells (2.0 net) is subject to Saskatchewan Crown royalties and is eligible for the reduced Crown royalty rate for the first 100,000 barrels of production (50,000 net to Alvopetro).

(1) Includes additional non-recurring royalties arising out of GORR dispute, representing amounts from July 2020 to December 2024. For future periods we would expect our Brazilian royalties as a percentage of sales to be approximately $5\%$ to $7\%$ , based on forecasted commodity prices.

ALVOPTRE

Q3 2025 Management's Discussion and Analysis

Production Expenses

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Production expenses by type:
Personnel costs	321	232	38	1,023	543	88
Facility and infrastructure costs	426	401	6	1,237	1,272	(3)
Other fixed costs	253	290	(13)	693	764	(9)
Variable costs	314	120	162	711	388	83
Workover costs	-	-	-	7	127	(94)
Production expenses – Total Company	1,314	1,043	26	3,671	3,094	19
Production expenses - Brazil	1,259	1,043	21	3,556	3,094	15
Production expenses - Canada	55	-	-	115	-	-
	Three Months Ended September 30,			Nine Months Ended September 30,
---	---	---	---	---	---	---
	2025	2024	Change (%)	2025	2024	Change (%)
Production expenses per boe($) (1):
Personnel costs	1.49	1.19	25	1.56	1.09	43
Facility and infrastructure costs	1.98	2.07	(4)	1.88	2.56	(27)
Other fixed costs	1.17	1.50	(22)	1.05	1.54	(32)
Variable costs	1.46	0.62	135	1.08	0.78	38
Workover costs	-	-	-	0.01	0.26	(96)
Total Company – per boe($) (1)	6.10	5.38	13	5.58	6.23	(10)
Brazil	6.21	5.38	15	5.63	6.23	(10)
Canada	4.33	-	-	4.55	-	-

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

Brazil

With respect to Unit operations, the majority of production expenses are split between Alvopetro and our Partner based on monthly production allocations. As a result Alvopetro's share of such costs can fluctuate even where Alvopetro production levels are consistent due to fluctuations in our Partner's natural gas deliveries. Production expenses in Q3 2025 increased compared to Q3 2024 with Murucututu operations increasing as a result of the 183-D4 well coming online in August. 2025 production expense were also impacted by additional personnel associated with the compression operations at Caburé which commenced at the start of the year.

Canada

In Canada, production expenses include contract operator expenses, water trucking and disposal and other variable expenses.

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Transportation Expenses

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Transportation expenses – Canada	48	-	-	79	-	-
Transportation expenses – Total Company	48	-	-	79	-	-
Transportation expenses per boe ($)(1): Canada	3.78	-	-	3.13	-	-
Total Company – per boe($)(1)	0.22	-	-	0.12	-	-

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

Transportation expenses include the cost to truck clean crude oil from the field to sales points. Transportation expenses incurred relate solely to Canadian operations.

Operating Netback

Brazil:	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Operating netback(1)
Natural gas, oil and condensate sales	13,544	12,879	5	40,977	35,303	16
Royalties	(664)	(367)	81	(2,900)	(966)	200
Production expenses	(1,259)	(1,043)	21	(3,556)	(3,094)	15
Operating netback(1)	11,621	11,469	1	34,521	31,243	10
Operating netback - $ per boe(1):
Average realized sales price - $ per boe(1)	66.76	66.46	-	64.83	71.06	(9)
Royalties - $ per boe(1)	(3.27)	(1.89)	73	(4.59)	(1.94)	137
Production expenses - $ per boe(1)	(6.21)	(5.38)	15	(5.63)	(6.23)	(10)
Operating netback per boe	57.28	59.19	(3)	54.61	62.89	(13)
Operating netback margin(1)	86%	89%	(3)	84%	89%	(6)
Canada:	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Operating netback(1)
Natural gas, oil and condensate sales	631	-	-	1,221	-	-
Royalties	(99)	-	-	(195)	-	-
Production expenses	(55)	-	-	(115)	-	-
Transportation expenses	(48)	-	-	(79)	-	-
Operating netback(1)	429	-	-	832	-	-
Operating netback - $ per boe(1):
Average realized sales price - $ per boe(1)	49.70	-	-	48.33	-	-
Royalties - $ per boe(1)	(7.80)	-	-	(7.72)	-	-
Production expenses - $ per boe(1)	(4.33)	-	-	(4.55)	-	-
Transportation expenses - $ per boe(1)	(3.78)	-	-	(3.13)	-	-
Operating netback per boe	33.79	-	-	32.93	-	-
Operating netback margin(1)	68%	-	-	68%	-	-

ALVOPTRO

Q3 2025 Management's Discussion and Analysis

ALVOPETRO
Q3 2025 Management's Discussion and Analysis

Total Company:	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Operating netback(1)
Natural gas, oil and condensate sales	14,175	12,879	10	42,198	35,303	20
Royalties	(763)	(367)	108	(3,095)	(966)	220
Production expenses	(1,314)	(1,043)	26	(3,671)	(3,094)	19
Transportation expenses	(48)	-	-	(79)	-	-
Operating netback(1)	12,050	11,469	5	35,353	31,243	13
Operating netback - $ per boe(1):
Average realized sales price - $ per boe(1)	65.76	66.46	(1)	64.19	71.06	(10)
Royalties - $ per boe(1)	(3.54)	(1.89)	87	(4.71)	(1.94)	143
Production expenses - $ per boe(1)	(6.10)	(5.38)	13	(5.58)	(6.23)	(10)
Transportation expenses - $ per boe(1)	(0.22)	-	-	(0.12)	-	-
Operating netback per boe	55.90	59.19	(6)	53.78	62.89	(14)
Operating netback margin(1)	85%	89%	(4)	84%	89%	(6)

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

With lower realized sales prices and higher royalties in Brazil and lower operating netbacks on new production from Canadian operations, Alvopetro's operating netback decreased by $3.29 per boe (-6%) in Q3 2025 compared to Q3 2024 and by $9.11 per boe (-14%) in the nine months ended September 30, 2025 compared 2024.

Change in Operating Netback per boe by Component (Q3 2025 compared to Q3 2024)

Change in Operating Netback per boe by Component (Nine months ended September 30, 2025 compared to September 30, 2024)

Other Income

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Interest income	278	320	(13)	803	941	(15)
Tax recoveries from operations and other	367	135	172	663	356	86
Total	645	455	42	1,466	1,297	13

With lower interest rates in Canada in Q3 2025 and lower cash balances, interest income decreased 13% compared to Q3 2024 and 15% in the nine months ended September 30, 2025 compared 2024. This was offset by higher tax recoveries from operations in the current period due to higher production volumes in Brazil.

General and Administrative ("G&A") Expenses

G&A Expenses, by type:	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Personnel	1,135	1,028	10	3,173	2,833	12
Travel	41	45	(9)	120	115	4
Office and IT costs	92	89	3	265	230	15
Professional fees	278	346	(20)	728	798	(9)
General corporate costs	465	383	21	1,460	1,439	1
Gross G&A	2,011	1,891	6	5,746	5,415	6
Capitalized G&A	(429)	(319)	34	(1,173)	(850)	38
G&A expenses	1,582	1,572	1	4,573	4,565	-
$ per boe(1)	7.34	8.11	(9)	6.96	9.19	(24)

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

Growing staffing levels associated with the assumption of Caburé Unit operations in Q3 2024 as well as inflationary adjustments and higher activity levels increased personnel costs in 2025 compared to 2024, which also contributed to higher capitalized G&A, resulting in relatively consistent net G&A expense in both Q3 2025 and for the nine months ended September 30, 2025 compared to the same periods in 2024. On a per boe basis, G&A expenses were 24% lower in the nine months ended September 30, 2025 compared to 2024 due to higher production volumes.

ALVOPTRO

Q3 2025 Management's Discussion and Analysis

Cash Flows from Operating Activities and Funds Flow from Operations

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Cash flows from operating activities	12,153	10,714	13	31,443	27,787	13
Per share – basic ($)	0.33	0.29	14	0.84	0.75	12
Per share – diluted ($)	0.32	0.28	14	0.83	0.74	12
Funds flow from operations(1)	10,448	9,886	6	30,036	26,309	14
Per share – basic ($)	0.28	0.27	4	0.81	0.71	14
Per share – diluted ($)	0.28	0.26	8	0.79	0.70	13

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

Funds flow from operations in Q3 2025 increased $0.6 million from Q3 2024 (+6%) and $3.7 million in the nine months ended September 30, 2025 compared to 2024 (+14%) due to higher sales volumes and other income, partially offset by lower realized sales prices and higher royalties, production expenses, transportation expenses and current tax.

Change in Funds Flow From Operations (Q3 2025 compared to Q3 2024)

ALVOPTRO

Q3 2025 Management's Discussion and Analysis

Foreign Exchange

	As at			% Appreciation (Depreciation) of BRL/CAD to USD
	September 30, 2025	June 30, 2025	December 31, 2024	Q3 2025	YTD 2025
Rate at end of period:
$1 USD = BRL	5.319	5.457	6.192	3	14
$1 USD = CAD	1.392	1.364	1.439	(2)	3

The Company's reporting currency is the USD, and its functional currencies are the USD and the BRL. Substantially all costs incurred in Brazil are in BRL and the Company incurs head office costs in both USD and CAD. In each reporting period, the change in the values of the BRL and the CAD relative to the Company's reporting currency are recognized. Foreign exchange rates for the reporting periods as specified are as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,		% Appreciation (Depreciation) of BRL/CAD to USD
	2025	2024	2025	2024	Change from Q3 2024	Change from YTD 2024
Average rate in the period:
$1 USD = BRL	5.449	5.545	5.650	5.244	2	(8)
$1 USD = CAD	1.377	1.364	1.398	1.360	(1)	(3)

The assets and liabilities of Alvopetro's Brazilian subsidiaries are translated to USD at the exchange rate on the reporting period date. The income and expenses of BRL-denominated items are translated to USD at the exchange rates on the date of the relevant transactions. All resulting foreign currency differences are recorded in exchange gain or loss on translation of foreign operations in other comprehensive income or loss. The BRL appreciated 14% from December 31, 2024, resulting in an exchange gain in comprehensive income in the nine months ended September 30, 2025.

Foreign exchange fluctuations on USD-denominated balances of the Brazilian subsidiary are recognized in earnings, including fluctuations on USD denominated intercompany amounts advanced to the Brazilian subsidiaries and the USD denominated lease liability of the Brazilian subsidiary associated with the Facility. In Q3 2025, the Company recorded a foreign exchange gain of $0.1 million on intercompany advances (Q3 2024 - $0.3 million foreign exchange gain) and a foreign exchange gain of $0.2 million on the lease liability (Q3 2024 -$0.1 million foreign exchange gain). In the nine months ended September 30, 2025, the Company recorded a foreign exchange gain of $0.5 million on intercompany advances (2024 - $2.9 million foreign exchange loss) and a foreign exchange gain of $1.1 million on the lease liability (2024 -$1.0 million foreign exchange loss). As of September 30, 2025, the USD denominated intercompany balance was $0.3 million (December 31, 2024 - $4.7 million) and the USD denominated lease liability was $7.1 million (December 31, 2024 - $7.8 million).

As discussed above, the Company is exposed to foreign exchange fluctuations on its natural gas revenues in Brazil. With respect to Alvopetro's natural gas price resets on May 1, 2025 and August 1, 2025 respectively, the price determined in BRL was based on average historical exchange rates of 5.85 and 5.67 BRL to 1.00 USD. In Q3 2025, the actual average rate was 5.45, an appreciation of 4% compared to the exchange rate used in the August 1, 2025 price. The following table denotes the overall estimated impact on natural gas revenues of a 5% and 10% depreciation and appreciation of the BRL relative to the USD:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
Increase (Decrease) to Natural Gas Revenues from:
5% Appreciation of BRL to USD	713	634	2,157	1,740
10% Appreciation of BRL to USD	1,505	1,338	4,553	3,673
5% Depreciation of BRL to USD	(645)	(574)	(1,951)	(1,574)
10% Depreciation of BRL to USD	(1,231)	(1,095)	(3,725)	(3,005)

To mitigate exposure to foreign exchange volatility with respect to the BRL, the Company has periodically entered into BRL/USD forward exchange rate contracts. The Company recognizes the fair value of these contracts in the statement of financial position with

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

changes in fair value recognized as an unrealized gain or loss included in net income. Realized gains or losses are recognized in the period the contracts are settled. No forward contracts were entered into or outstanding at any time in 2024 or to date in 2025.

Head office transactions in CAD are recognized at the rates of exchange prevailing at the date of the transactions. At the end of each reporting period, monetary assets and liabilities are translated at the exchange rate in effect at the reporting period date. Non-monetary assets, liabilities, revenues and expenses are translated at transaction date exchange rates. Exchange gains or losses are included in the determination of earnings.

Depletion and Depreciation

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Depletion and depreciation on PP&E	3,255	1,719	89	8,631	4,683	84
Depreciation of right-of-use assets	304	301	1	886	885	-
Depletion and depreciation expense	3,559	2,020	76	9,517	5,568	71
$ per boe(1) – Total Company	16.51	10.42	58	14.48	11.21	29

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A.

Depletion is calculated on a unit-of-production basis for all upstream PP&E assets. All midstream PP&E assets are depreciated over the estimated useful life of the assets on a straight-line basis. With a higher depletable base depletion and depreciation on PP&E increased 89% in Q3 2025 and 84% in the nine months ended September 30, 2025 compared to the same periods in 2024.

The Company's right-of-use assets are depreciated over the lease term on a straight-line basis.

Impairment

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Impairment	1,859	-	-	1,865	91	1,949

In Q3 2025, Alvopetro entered into an assignment agreement to dispose of its interest in the Bom Lugar and Mãe da lua oil fields for total consideration of $0.6 million, including deferred consideration. In connection with the disposition, the purchaser will assume all abandonment liabilities associated with the fields. Closing of the agreement is subject to approval of the ANP. Alvopetro classified these assets and the related liabilities as held for sale as of September 30, 2025, recognizing an impairment charge of $1.9 million at the time of the transfer to reflect the carrying value as the anticipated proceeds to be received on the sale.

Share-Based Compensation Expense

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Share-based compensation expense	273	283	(4)	927	885	5

Share-based compensation expense is based on the fair value of stock options, restricted share units ("RSUs") and deferred share units ("DSUs") granted and amortized over the respective vesting periods. As of September 30, 2025, a total of 2.8 million awards were outstanding (September 30, 2024 – 2.8 million) with 1,869,664 stock options (September 30, 2024 – 1,809,441) and 944,951 RSUs and DSUs (September 30, 2024 – 946,712).

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Finance Expenses

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Lease interest	307	336	(9)	936	1,040	(10)
Accretion on decommissioning liabilities	21	25	(16)	94	75	25
Other	29	-	-	154	-	-
Finance expenses	357	361	(1)	1,184	1,115	6

Finance expenses increased 6% in the nine months ended September 30, 2025 compared to 2024 mainly due to estimated additional interest owing on the GORR dispute, as further described above.

Income Tax Expense

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Current income tax expense	714	503	42	2,054	1,606	28
Deferred income tax expense	40	699	(94)	753	854	(12)
Total	754	1,202	(37)	2,807	2,460	14
Effective tax rate	14.0%	14.4%	(3)	13.8%	14.9%	(7)

The statutory corporate tax rate in Brazil is 34%. This is comprised of a basic 15% corporate income tax, plus 10% surtax and a 9% social contribution tax. Alvopetro is eligible for Supertintendência de Desenvolvimento do Nordeste ("SUDENE"), a regional tax incentive offered in Bahia State. Under the incentive, special deductions reduce the inherent current tax payable on qualifying projects to an effective rate of 15.25% where SUDENE profits align with taxable income under the actual profit regime. The SUDENE incentive applies to natural gas and condensate profits Alvopetro earns for a period of ten taxation years, commencing January 1, 2021, and ending December 31, 2030. The incentive generally reduces corporate tax and surtax on qualifying projects by 75% where SUDENE profits align with taxable income under the actual profit regime, resulting in an effective tax rate of 15.25%. Where SUDENE profits exceed taxable income, it is possible to further reduce corporate income tax and surtax to a tax rate below 15.25%. As Alvopetro expects the majority of temporary differences to reverse during the SUDENE period, for deferred tax purposes Alvopetro has estimated the future tax rate applicable to temporary differences based on the SUDENE rate of 15.25%.

Current tax expense increased in 2025 compared to 2024 due to higher net income and lower available tax deductions. Deferred tax expense decreased due mainly to non-deductible impairment losses, partially offset by foreign exchange gains (compared to foreign exchange losses in 2024). Overall, the effective tax rate (computed as total income tax expense divided by income before taxes) is 13.8% in 2025, marginally lower than the SUDENE rate of 15.25% as SUDENE profits exceed taxable income in the period, resulting in a lower overall effective tax rate.

All current and deferred tax expense relates solely to Brazil operations. The Company has an unrecognized deferred tax asset in Canada of $2.0 million (December 31, 2024 - $1.3 million). Total tax pools of $11.6 million (December 31, 2024 - $6.7 million) are available to shelter future earnings from Canadian operations, including tax loss carryforwards of $7.2 million (December 31, 2024 - $6.9 million).

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Net Income

| | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | | |
| --- | --- | --- | --- | --- | --- | --- |
| | 2025 | 2024 | Change (%) | 2025 | 2024 | Change (%) |
| Net income | 4,613 | 7,152 | (36) | 17,513 | 14,052 | 25 |
| Per share – basic ($) | 0.12 | 0.19 | (37) | 0.47 | 0.38 | 24 |
| Per share – diluted ($) | 0.12 | 0.19 | (37) | 0.46 | 0.37 | 24 |

Net income in Q3 2025 decreased $2.5 million compared to Q3 2024 due mainly to impairment and higher depletion and depreciation and current tax expense, partially offset by higher operating netback and lower deferred tax expenses. In the nine months ended September 30, 2025 compared to the same period in 2024, net income increased $3.5 million as higher sales volumes and foreign exchange gains (compared to foreign exchange losses in 2024) more than offset higher depletion and depreciation expense, impairment and current tax expense.

Change in Net Income (Q3 2025 compared to Q3 2024)

Change in Net Income (Nine months ended September 30, 2025 compared September 30, 2024)

ALVOPTRO

Q3 2025 Management's Discussion and Analysis

Capital Expenditures

Capital Expenditures by Type	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
E&E
Drilling and completions	-	230	1,019	266
Land, lease, and similar payments	2	2	6	4
Equipment inventory purchases	633	94	2,188	617
Capitalized G&A	-	44	41	60
Total E&E	635	370	3,254	947
PP&E
Drilling & completions	9,316	3,431	22,260	4,141
Facility & equipment	643	655	1,335	4,642
Land, lease, and similar payments	113	5	179	18
Capitalized G&A	429	275	1,132	790
Furniture & fixtures and other	113	11	450	85
Total PP&E	10,614	4,377	25,356	9,676
Total Capital Expenditures	11,249	4,747	28,610	10,623
Capital Expenditures by Property	Three Months Ended September 30,		Nine Months Ended September 30,
---	---	---	---	---
	2025	2024	2025	2024
E&E - Brazil
Block 183	2	276	1,066	330
Equipment inventory purchases	633	94	2,188	617
Total E&E – Brazil	635	370	3,254	947
PP&E - Brazil
Caburé and associated midstream assets	5,436	572	7,742	4,466
Murucututu	3,622	3,793	13,029	5,187
Other	-	4	-	9
PP&E – Brazilian Properties	9,058	4,369	20,771	9,662
PP&E - Canada
Western Saskatchewan	1,515	-	4,246	-
PP&E – Corporate	41	8	339	14
Total PP&E	10,614	4,377	25,356	9,676
Total Capital Expenditures	11,249	4,747	28,610	10,623

Brazil capital expenditures in the third quarter on our 100% Murucututu field include completion costs for the 183-D4 well. Capital expenditures on the Caburé field include our share of unit development costs incurred in the quarter, including drilling and completing the first four (2.2 net) planned development wells. Capital expenditures in Canada in the quarter include drilling and completing two additional wells (1.0 net).

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Summary of Quarterly Results

	Q3 2025	Q2 2025	Q1 2025	Q4 2024	Q3 2024	Q2 2024	Q1 2024	Q4 2023
Financial
Natural gas, oil and condensate sales	14,175	14,010	14,013	10,214	12,879	10,672	11,752	15,300
Net income	4,613	6,830	6,070	2,243	7,152	2,350	4,550	652
Per share – basic ($)(1)	0.12	0.18	0.16	0.06	0.19	0.06	0.12	0.02
Per share – diluted ($)(1)	0.12	0.18	0.16	0.06	0.19	0.06	0.12	0.02
Cash flows from operating activities	12,153	10,473	8,817	7,114	10,714	8,860	8,213	7,904
Per share – basic ($)(1)	0.33	0.28	0.24	0.19	0.29	0.24	0.22	0.21
Per share – diluted ($)(1)	0.32	0.28	0.23	0.19	0.28	0.24	0.22	0.21
Funds flow from operations(2)	10,448	10,366	9,222	6,966	9,886	7,910	8,513	12,393
Per share – basic ($)(1)	0.28	0.28	0.25	0.19	0.27	0.21	0.23	0.33
Per share – diluted ($)(1)	0.28	0.27	0.24	0.19	0.26	0.21	0.23	0.33
Dividends declared	3,673	3,660	3,643	3,283	3,295	3,296	3,296	5,127
Per share ($) (1)(2)	0.10	0.10	0.10	0.09	0.09	0.09	0.09	0.14
Capital expenditures	11,249	8,986	8,375	4,682	4,747	3,437	2,439	4,934
Net working capital(2)	2,209	6,838	9,742	13,181	15,848	14,692	15,047	13,117
Operations
Average realized prices(2):
Natural gas ($/Mcf)	11.04	10.62	10.44	10.51	10.92	11.83	12.57	12.85
NGL – condensate ($/bbl)	74.16	72.32	81.05	75.95	86.70	92.27	87.89	89.45
Oil ($/bbl)	50.42	47.10	64.96	61.74	68.36	71.87	65.06	73.67
Average benchmark prices:
Henry Hub ($/Mmbtu)	3.03	3.19	4.14	2.44	2.11	2.06	2.15	2.74
Brent oil ($/bbl)	69.03	68.07	75.87	74.66	80.01	84.68	82.92	84.01
WTI ($/bbl)	65.78	64.57	71.78	70.73	76.43	81.81	77.50	78.53
WCS ($/bbl)	54.43	54.11	58.83	58.17	62.27	66.92	57.68	56.43
WCS (C$/bbl)	74.95	74.89	84.42	81.32	84.93	91.54	77.81	76.86
Average foreign exchange ($1 USD = BRL)	5.449	5.666	5.852	5.837	5.545	5.213	4.952	4.955
Operating netback ($/boe)(2)
Realized sales price	65.76	63.20	63.67	63.88	66.46	71.97	75.94	77.60
Royalties	(3.54)	(2.97)	(7.60)	(2.15)	(1.89)	(1.94)	(2.02)	(2.07)
Production expenses	(6.10)	(5.37)	(5.30)	(6.64)	(5.38)	(5.73)	(7.76)	(5.84)
Transportation expenses	(0.22)	(0.14)	-	-	-	-	-	-
Operating netback	55.90	54.72	50.77	55.09	59.19	64.30	66.16	69.69
Operating netback margin(2)	85%	87%	80%	86%	89%	89%	87%	90%
Average daily sales volumes:
Natural gas (Mcfpd)	12,293	13,002	13,803	9,707	11,994	9,244	9,666	12,245
NGL – condensate (bopd)	147	128	135	109	95	76	78	92
Oil (bopd)	147	141	10	11	12	12	12	10
Total average daily sales (boepd)	2,343	2,436	2,446	1,738	2,106	1,629	1,701	2,143
Brazil	2,205	2,298	2,446	1,738	2,106	1,629	1,701	2,143
Canada	138	138	-	-	-	-	-	-

Average daily sales volumes in Q3 2025 decreased 4% compared to Q2 2025 due mainly to reduced end user natural gas demand in Brazil. Despite lower sales volumes, natural gas oil and condensate revenue increased $0.2 million (+1%) from Q2 2025 due to higher realized sales prices per boe. With higher realized sales prices in Q3 2025, partially offset by higher royalties, production expenses and transportation expenses, our operating netback increased $1.18 per boe from Q2 2025. Overall, our funds flow from operations

ALVOPTRO

Q3 2025 Management's Discussion and Analysis

increased $0.1 million. Despite higher funds flow from operations, net income decreased by $2.2 million due to higher depletion and depreciation expense as well as impairment charges.

Over the past eight quarters, fluctuations in average daily sales volumes, the average realized sales price per boe and average foreign exchange rates have impacted natural gas, oil and condensate revenues and funds flow from operations. Net income has fluctuated over the same period due to changes in funds flow from operations, impairment losses and fluctuations in deferred tax expense and foreign exchange gains and losses. Capital expenditures have fluctuated throughout the period due to changes in the Company's planned spending levels on E&E and PP&E assets. With higher overall production and cash flows, the Board of Directors increased the quarterly dividend to $0.10 per share in Q1 through Q3 2025 compared to $0.09 per share throughout 2024.

Commitments and Contingencies

The following is a summary of Alvopetro's contractual commitments as at September 30, 2025:

	< 1 Year	1-3 Years	Thereafter	Total
Gas Treatment Agreement(1)	1,527	3,053	2,672	7,252
Total commitments	1,527	3,053	2,672	7,252

(1) Amounts for the Gas Treatment Agreement are BRL denominated commitments and reflected in the table above based on the U.S. dollar equivalent as at September 30, 2025. As a result, such commitments are subject to fluctuations in the USD/BRL foreign exchange rate.

Amounts presented above for the Gas Treatment Agreement represent the monthly service fees for operation and maintenance of the Facility and operating fees for Alvopetro's 11-kilometre transfer pipeline.

The Company has abandonment guarantees that are required to be posted with the ANP for the Bom Lugar, Mãe-da-lua, Caburé and Murucututu fields under the terms of the concession contract for each field. Alvopetro has recognized the estimated abandonment costs relating to these, all exploration assets, as well as all Canadian assets as part of decommissioning liabilities on the consolidated statements of financial position.

As is customary in the oil and gas industry, we may at times have work plans in place to reserve or earn certain acreage positions or wells. If we do not complete such work plans in a timely manner, the acreage positions or wells may be lost, or penalties may be applied.

In the normal course of operations we have disputes for which we currently cannot determine the ultimate results. The Company rigorously defends its positions in any such matters and has a policy to record contingent liabilities as the amounts become determinable and the probability of loss is more likely than not. In the nine months ended September 30, 2025, Alvopetro recognized a provision for additional GORR associated with the GORR dispute as further described in "Royalties". The Company currently has no contingent liabilities recorded however, the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters are unknown and could have a material impact on the Company's financial position, results of operations or cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Cash and Working Capital

At September 30, 2025, Alvopetro's cash and cash equivalents of $12.1 million were held as follows:

	Total	U.S. Dollar	CAD Dollar(1)	BRL(1)
Cash and cash equivalents held in Canada	7,667	7,481	186	-
Cash and cash equivalents held in Brazil	4,414	-	-	4,414
Total	12,081	7,481	186	4,414

(1) Amounts in the table above denote the U.S. dollar equivalent as at September 30, 2025.

The Company had cash and cash equivalents of $12.1 million and a total net working capital surplus of $2.2 million at September 30, 2025. Positive cash flows from natural gas deliveries and associated condensate sales from operations are projected to be sufficient to fund the Company's operational activities, planned capital projects and future dividends. However, the Company is exposed to a variety of risks which may adversely impact future cash flows. The Company manages these risks by forecasting cash flows for a

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

minimum period of twelve months, which involves preparation of capital expenditure, operating and general and administrative budgets, all of which are monitored closely, and adjusted as necessary. The Board of Directors has discretion with respect to any future dividend amounts and the Company has flexibility on future capital plans.

The liability for decommissioning obligations of Alvopetro was $1.5 million as at September 30, 2025, with $0.3 million expected to be incurred within one year. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows, if applicable.

At September 30, 2025, the Company had $6.1 million of equipment inventory to be utilized for future operations which is included in exploration and evaluation assets in the consolidated statements of financial position.

Lease Liabilities

The lease liability to Enerflex in respect of the monthly facility payments under our Gas Treatment Agreement represents the majority of the Company's lease liabilities as at September 30, 2025 and December 31, 2024. Additional lease liabilities outstanding relate to office space in Canada and Brazil and surface land access for our midstream assets. The Company's lease liabilities are as follows:

	As at
	September 30, 2025	December 31, 2024
Lease liabilities, beginning of period	7,863	8,681
Additions	147	114
Finance expense	936	1,370
Lease payments	(1,692)	(2,278)
Foreign currency translation	9	(24)
Lease liabilities, end of period	7,263	7,863
Current	1,173	1,069
Non-current	6,090	6,794
Total, end of period	7,263	7,863

Dividends

| | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | | |
| --- | --- | --- | --- | --- | --- | --- |
| | 2025 | 2024 | Change (%) | 2025 | 2024 | Change (%) |
| Dividends declared | 3,673 | 3,295 | 11 | 10,976 | 9,887 | 11 |
| Dividends declared – per share ($) (1) | 0.10 | 0.09 | 11 | 0.30 | 0.27 | 11 |

(1) See "Non-GAAP and Other Financial Measures" section within this MD&A. Dividends per share is based on the number of common shares outstanding at each dividend record date.

For all quarters to date in 2025, the Board of Directors increased the quarterly dividend to $0.10 per share compared to $0.09 per share paid throughout 2024. All dividends are designated as "eligible dividends" for the purpose of the Income Tax Act (Canada). The Company expects future dividends to be paid quarterly as part of Alvopetro's long-standing capital allocation objective to balance spending from cash flows between reinvestment in growth opportunities and returns to stakeholders. However, the decision to declare any future quarterly dividend and the amount of such dividend, if any, remains subject to the discretion of the Board and may vary depending on numerous factors. There can be no assurance that dividends will be paid at the intended rate or at any rate in the future.

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

Normal Course Issuer Bid

	Three Months Ended September 30,			Nine Months Ended September 30,
	2025	2024	Change (%)	2025	2024	Change (%)
Shares repurchased (#)	10,100	62,800	(84)	151,000	62,800	140
Average price per share (C$)	5.88	5.09	16	5.22	5.09	3
Total cost of share repurchases - $000s(1)	32	251	(87)	556	251	122

(1) Includes applicable fees.

On August 13, 2024, Alvopetro launched a normal course issuer bid (the "2024 NCIB") to repurchase Alvopetro common shares. The terms of the 2024 NCIB permitted Alvopetro to repurchase up to 2,953,044 common shares from August 13, 2024 to the earlier of August 12, 2025 or when the 2024 NCIB was completed or terminated by Alvopetro. In Q3 2025 10,100 shares were repurchased pursuant to the 2024 NCIB with a total of 151,000 repurchased in the nine months ended September 30, 2025. All shares repurchased were subsequently cancelled.

The 2024 NCIB expired on August 12, 2025.

OUTSTANDING SHARE DATA

The Company is authorized to issue an unlimited number of common shares and preferred shares in one or more series. As of November 5, 2025, there were 36,732,097 common shares, 1,869,664 stock options, 626,788 RSUs and 318,164 DSUs outstanding. There are no preferred shares outstanding.

NON-GAAP AND OTHER FINANCIAL MEASURES

This MD&A or documents referred to in this MD&A make reference to various non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as such terms are defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. Such measures are not recognized measures under GAAP and do not have a standardized meaning prescribed by IFRS and therefore might not be comparable to similar financial measures disclosed by other issuers. While these measures may be common in the oil and gas industry, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP and other financial measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company's reported financial performance or position. These are complementary measures that are used by management in assessing the Company's financial performance, efficiency and liquidity and they may be used by investors or other users of this document for the same purpose.

Below is a description of the non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures used in this MD&A.

Non-GAAP Financial Measures

Operating Netback

Operating netback is calculated as natural gas, oil and condensate sales revenues less royalties, production expenses and transportation expenses. This calculation is provided in the "Operating Netback" section of this MD&A using our IFRS measures. Operating netback is a common metric used in the oil and gas industry to demonstrate profitability from operations.

Non-GAAP Financial Ratios

Operating Netback per boe

Operating netback on a per unit basis, which is per barrel of oil equivalent ("boe"), is a common non-GAAP measure used in the oil and gas industry and management believes it assists in evaluating the operating performance of the Company. It is a measure of the economic quality of the Company's producing assets and is useful for evaluating variable costs as it provides a reliable measure regardless of fluctuations in production. Alvopetro calculated operating netback per boe as operating netback divided by total sales

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

volumes (barrels of oil equivalent). This calculation is provided in the "Operating Netback" section of this MD&A using our IFRS measures.

Operating Netback Margin

Operating netback margin is calculated as operating netback per boe divided by the realized sales price per boe. Operating netback margin is a measure of the profitability per boe relative to natural gas, oil and condensate sales revenues per boe and is calculated as follows:

| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| --- | --- | --- | --- | --- |
| | 2025 | 2024 | 2025 | 2024 |
| Operating netback - $ per boe | 55.90 | 59.19 | 53.78 | 62.89 |
| Average realized price - $ per boe | 65.76 | 66.46 | 64.19 | 71.06 |
| Operating netback margin | 85% | 89% | 84% | 89% |

Funds Flow from Operations Per Share

Funds flow from operations per share is a non-GAAP ratio that includes all cash generated from operating activities (as calculated below) divided by the weighted average shares outstanding for the respective period. For the periods reported in this document the cash flows from operating activities per share and funds flow from operations per share is as follows:

| $ per share | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| --- | --- | --- | --- | --- |
| | 2025 | 2024 | 2025 | 2024 |
| Per basic share: | | | | |
| Cash flows from operating activities | 0.33 | 0.29 | 0.84 | 0.75 |
| Funds flow from operations | 0.28 | 0.27 | 0.81 | 0.71 |
| Per diluted share: | | | | |
| Cash flows from operating activities | 0.32 | 0.28 | 0.83 | 0.74 |
| Funds flow from operations | 0.28 | 0.26 | 0.79 | 0.70 |

Capital Management Measures

Funds Flow from Operations

Funds flow from operations is a non-GAAP capital management measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The most comparable GAAP measure to funds flow from operations is cash flows from operating activities. Management considers funds flow from operations important as it helps evaluate financial performance and demonstrates the Company's ability to generate sufficient cash to fund future growth opportunities. Funds flow from operations should not be considered an alternative to, or more meaningful than, cash flows from operating activities however management finds that the impact of working capital items on the cash flows reduces the comparability of the metric from period to period. A reconciliation of funds flow from operations to cash flows from operating activities is as follows:

| | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| --- | --- | --- | --- | --- |
| | 2025 | 2024 | 2025 | 2024 |
| Cash flows from operating activities | 12,153 | 10,714 | 31,443 | 27,787 |
| Changes in non-cash working capital | (1,705) | (828) | (1,407) | (1,478) |
| Funds flow from operations | 10,448 | 9,886 | 30,036 | 26,309 |

Net Working Capital

Net working capital is computed as current assets less current liabilities. Net working capital is a measure of liquidity, is used to evaluate financial resources, and is calculated as follows:

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

	As at September 30,
	2025	2024
Total current assets	18,582	30,197
Total current liabilities	(16,373)	(14,349)
Net working capital	2,209	15,848

Supplementary Financial Measures

"Average realized natural gas price - $/Mcf" is comprised of natural gas sales as determined in accordance with IFRS, divided by the Company's natural gas sales volumes.

"Average realized NGL – condensate price - $/bbl" is comprised of condensate sales as determined in accordance with IFRS, divided by the Company's NGL sales volumes from condensate.

"Average realized oil price - $/bbl" is comprised of oil sales as determined in accordance with IFRS, divided by the Company's oil sales volumes.

"Average realized price - $/boe" is comprised of natural gas, condensate and oil sales as determined in accordance with IFRS, divided by the Company's total natural gas, NGL and oil sales volumes (barrels of oil equivalent).

"Dividends per share" is comprised of dividends declared, as determined in accordance with IFRS, divided by the number of shares outstanding at the dividend record date.

"Royalties per boe" is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales volumes (barrels of oil equivalent).

"Royalties as a percentage of sales" is comprised of royalties, as determined in accordance with IFRS, divided by the total natural gas, condensate and oil sales, as determined in accordance with IFRS.

"Production expenses per boe" is comprised of production expenses, as determined in accordance with IFRS, divided by the total natural gas, NGL and oil sales volumes (barrels of oil equivalent).

"Transportation expenses per boe" is comprised of transportation expenses, as determined in accordance with IFRS, divided by the total natural gas, NGL and oil sales volumes (barrels of oil equivalent).

"G&A expenses per boe" is comprised of net G&A expense, as determined in accordance with IFRS, divided by the total natural gas, NGL and oil sales volumes (barrels of oil equivalent).

"Depletion and depreciation expense per boe" is comprised of depletion and depreciation expense, as determined in accordance with IFRS, divided by the total natural gas, NGL and oil sales volumes (barrels of oil equivalent).

OFF BALANCE SHEET ARRANGEMENTS

Alvopetro has off-balance sheet arrangements consisting of various contracts entered into in the normal course of operations. Contracts that contain a lease are accounted for under IFRS 16 and recorded on the balance sheet as of September 30, 2025 to the extent the lease has commenced. All other contracts which are entered into in the normal course of operations are captured in the Commitments and Contingencies section above.

RISKS AND UNCERTAINTIES

Alvopetro is exposed to a variety of risks including, but not limited to: reservoir performance risk, market risk, exploration, exploitation, acquisition and disposition risk, operational and uninsurable risks, inflation and supply chain management risk, foreign operations risk, legal and regulatory risks including the impact of new and stricter environmental regulations, liquidity and financing risk and competitive risks within the oil and gas industry. Investors should carefully consider the risk factors set forth under the heading

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

"Risk Factors" in our Annual Information Form that can be found on SEDAR+ at www.sedarplus.ca and in our MD&A for the year-ended December 31, 2024.

There have been no significant changes in the nine months ended September 30, 2025 to the risks and uncertainties identified in the MD&A and Annual information Form for the year-ended December 31, 2024 other than with respect to the findings of the GORR dispute. As further described in the section entitled "Royalties", Alvopetro has recognized an additional provision with respect to the GORR on natural gas on Block 197. Pursuant to dispute resolution provisions, the dispute proceeded to arbitration under the Rules of Arbitration of the ICC. The Company had not previously recognized any additional provision related to the GORR as Alvopetro had expected to be successful in the dispute. However, in April 2025 Alvopetro received the findings of the arbitral tribunal wherein the tribunal found in favour of the GORR holders requiring Alvopetro to utilize the sales price to Bahiagás in the computation of the GORR. Alvopetro has estimated the additional GORR owing and recognized the additional royalty (including inflation adjustments) with interest owing on the balance outstanding recognized in finance expenses.

Alvopetro was required to submit all calculations of the additional GORR owing to the tribunal for review. The tribunal will then issue a final decision on the amount owing. The historical amount recorded in the three months ended March 31, 2025 for periods up to December 31, 2024, as well as the ongoing GORR calculations for the three and nine months ended September 30, 2025 represent management's best estimates, however the actual calculation will be determined by the tribunal and may be materially different. As a result, the final amount owing is uncertain as of the date of this MD&A as it remains subject to the approval of the tribunal and will be subject to any adjustment required by the tribunal. The final amount owing may be different than the amounts recognized by Alvopetro as of September 30, 2025 and such difference may be material. In addition, as the GORR award is subject to inflation and interest adjustments, the balance owing will increase over time.

CHANGES IN ACCOUNTING POLICIES INCLUDING INITIAL ADOPTION

The accounting policies used in preparation of the unaudited interim condensed consolidated financial statements as at and for the three and nine months ended September 30, 2025 are consistent with those disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2024. The Company has not early adopted any standard, interpretation, or amendment that has been issued but is not yet effective.

Management's Report on Internal Control over Financial Reporting. In connection with National Instrument 52-109 – Certification of Disclosure in Issuer's Annual and Interim Filings ("NI 52-109"), the Chief Executive Officer and Chief Financial Officer of the Company are required to file a Venture Issuer Basic Certificate with respect to the financial information contained in the unaudited interim financial statements and the audited annual financial statements and respective accompanying Management's Discussion and Analysis. The Venture Issuer Basic Certificate does not include representations relating to the establishment and maintenance of disclosure controls and procedures and internal control over financial reporting, as defined in NI 52-109.

Dividend Advisory. The decision to declare any future quarterly dividend and the amount and timing of such dividend, if any, remains subject to the discretion of the Board and may vary depending on numerous factors, including, without limitation, the Company's operational performance, available financial resources and financial requirements, capital requirements and growth plans. There can be no assurance that dividends will be paid at the intended rate or at any rate in the future.

Forward-Looking Statements. Certain information provided in this MD&A constitutes forward-looking statements. The use of any of the words "will", "expect", "intend" and other similar words or expressions are intended to identify forward-looking information. Forward-looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. More particularly and without limitation, this MD&A contains forward-looking statements concerning the arbitration procedures associated with the redetermination of working interests of the Unit, the anticipated outcome of the GORR dispute, expected royalty rates, the Company's dividend policy and plans for dividends in the future, plans relating to the Company's operational activities, proposed exploration and development activities and the timing for such activities, capital spending levels and future capital costs, exploration and development prospects of Alvopetro, future production and sales volumes, production rates and allocations from the Caburé natural gas field, expected production rates from certain wells, the expected natural gas price, gas sales and gas deliveries under Alvopetro's long-term gas sales agreement, and sources and availability of capital. Forward-looking statements are necessarily based upon assumptions and judgments with respect to the future including, but not limited to the success of future drilling, completion, testing, recompetition and development activities and the timing of such activities, the performance of producing wells and reservoirs, well development and operating performance, expectations and assumptions concerning the approval of and timing of regulatory licenses, equipment availability, environmental

ALVOPETRO

Q3 2025 Management's Discussion and Analysis

regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the outlook for commodity markets and ability to access capital markets, foreign exchange rates, the outcome of any redeterminations, the outcome of any disputes, general economic and business conditions, forecasted demand for oil and natural gas, the impact of global pandemics, weather and access to drilling locations, the availability and cost of labour and services, and the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Current and forecasted natural gas nominations are subject to change on a daily basis and such changes may be material. Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. Since forward looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, reliance on industry partners, availability of equipment and personnel, uncertainty surrounding timing for drilling and completion activities resulting from weather and other factors, changes in applicable regulatory regimes and health, safety and environmental risks), commodity price and foreign exchange rate fluctuations, market uncertainty associated with trade or tariff disputes and general economic conditions. Certain of these risks are set out in more detail in our 2024 Annual Information Form which has been filed on SEDAR+ and can be accessed at www.sedarplus.ca. Except as may be required by applicable securities laws, Alvopetro assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Abbreviations:
| ANP | = | The National Agency of Petroleum, Natural Gas and Biofuels of Brazil |
| --- | --- | --- |
| bbls | = | barrels of oil and/or natural gas liquids (condensate) |
| boepd | = | barrels of oil equivalent ("boe") per day |
| bopd | = | barrels of oil and/or natural gas liquids (condensate) per day |
| BRL | = | Brazilian real |
| CAD | = | Canadian dollar |
| e3m3/d | = | thousand cubic metre per day |
| m3 | = | cubic metre |
| m3/d | = | cubic metre per day |
| Mcf | = | thousand cubic feet |
| Mcfpd | = | thousand cubic feet per day |
| MMBtu | = | million British Thermal Units |
| MMcf | = | million cubic feet |
| MMcfpd | = | million cubic feet per day |
| NGLs | = | natural gas liquids |
| Q1 2025 | = | three months ended March 31, 2025 |
| Q3 2024 | = | three months ended September 30, 2024 |
| Q2 2025 | = | three months ended June 30, 2025 |
| Q3 2025 | = | three months ended September 30, 2025 |
| USD | = | United States dollar |

BOE Disclosure. The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6 Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this MD&A are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Contracted firm volumes. The 2025 contracted daily firm volumes of $400\mathrm{e}^3\mathrm{m}^3/\mathrm{d}$ (before any provisions for take or pay allowances) represents contracted volumes based on contract referenced natural gas heating value. Alvopetro's reported natural gas sales volumes are prior to any adjustments for the heating value of Alvopetro natural gas. Alvopetro's natural gas is approximately $7.8\%$ higher than the contract reference heating value. Therefore, to satisfy the contractual firm deliveries, Alvopetro would be required to deliver approximately $371\mathrm{e}^3\mathrm{m}^3/\mathrm{d}$ (13.1MMcfpd).

ALVOPTRO

Q3 2025 Management's Discussion and Analysis

AI assistant

Baylin Technologies Inc. — Management Reports 2025

47166_rns_2025-11-05_156419c3-ec4b-4d29-9107-45ffbedee539.pdf

MANAGEMENT'S DISCUSSION AND ANALYSIS

OVERVIEW

Description of Business

Strategy

HIGHLIGHTS AND SIGNIFICANT TRANSACTIONS FOR THE THIRD QUARTER OF 2025

RECENT HIGHLIGHTS

NATURAL GAS AND OIL PROPERTIES

BRAZIL

NATURAL GAS ASSETS AND MIDSTREAM INFRASTRUCTURE:

Caburé Natural Gas Field (56.2% Working Interest)

Murucututu Natural Gas Field (100% Working Interest)

Natural Gas Sales (100% Alvopetro)

OIL ASSETS:

EXPLORATION ASSETS (Block 183)

WESTERN CANADA

FINANCIAL AND OPERATING REVIEW

Sales Volumes

Canada

Natural Gas, Oil and Condensate Sales Revenue

Royalties

Brazil

Western Canada

Brazil

Canada

Depletion and Depreciation

Impairment

Share-Based Compensation Expense

Commitments and Contingencies

LIQUIDITY AND CAPITAL RESOURCES

Cash and Working Capital

Lease Liabilities

Dividends

OUTSTANDING SHARE DATA

NON-GAAP AND OTHER FINANCIAL MEASURES

Non-GAAP Financial Measures

Operating Netback

Non-GAAP Financial Ratios

Operating Netback per boe

Operating Netback Margin

Funds Flow from Operations Per Share

Capital Management Measures

Funds Flow from Operations

Net Working Capital

Supplementary Financial Measures

OFF BALANCE SHEET ARRANGEMENTS

RISKS AND UNCERTAINTIES

CHANGES IN ACCOUNTING POLICIES INCLUDING INITIAL ADOPTION

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Baylin Technologies Inc. Management Reports 2025