MD&A (Condor MDA 2025 Q4)

‌Condor Energies Inc. ("Condor" or the "Company") is an internationally focused energy transition company incorporated on October 20, 2006 that is uniquely positioned on the doorstep of European and Asian markets with three distinct first-mover energy security initiatives: increasing natural gas and condensate production from its eight gas fields in Uzbekistan; an ongoing project to construct and operate Central Asia's first LNG 'lower carbon fuel' diesel substitution facility in Kazakhstan; and a separate initiative to develop and produce critical minerals from brines in Kazakhstan. Condor has built a strong foundation for reserves, production and cashflow growth while also striving to minimize its environmental footprint.

‌Condor is a publicly traded company listed on the Toronto Stock Exchange under the symbol "CDR". Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2025, is available on SEDAR+ at: https://www.sedarplus.ca.

‌The Company's Management's Discussion and Analysis ("MD&A") which follows should be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2025 and 2024 (the "Financial Statements"). The Financial Statements have been prepared in accordance with IFRS Accounting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). This MD&A is dated March 19, 2026, the date that Condor's Board of Directors approved the Financial Statements and MD&A.

All financial amounts are in Canadian dollars, unless otherwise stated.

• Production in Uzbekistan for the fourth quarter of 2025 averaged 10,534 boe/d comprised of 10,218 boe/d (61,310 Mcf/d) of natural gas and 316 bopd of condensate or a total production increase of 5.6% from the third quarter of 2025. Uzbekistan natural gas and condensate sales for the fourth quarter of 2025 was

  $20.38 million or an 8.8% increase from the third quarter of 2025.

• Production in Uzbekistan for the year ended December 31, 2025 averaged 10,484 boe/d comprised of 10,202 boe/d (61,213 Mcf/d) of natural gas and 282 bopd of condensate. Uzbekistan natural gas and condensate sales for 2025 was $80.66 million.

• A multi-well drilling program commenced in Uzbekistan in September 2025 with two horizontal and one vertical well drilled to date. Two of the wells (one horizontal and one vertical) have been completed and were tested at a combined rate of 2,096 boe/d (12.6 MMcf/d) with completion activities underway for the other horizontal well. Drilling of the next horizontal well is ongoing and currently at 2,335 meters with the well estimated to be completed and tested by mid-April 2026.

• March 2026 month-to-date production has averaged 12,622 boe/d comprised of 12,274 boe/d (73.6 MMcf/d) of natural gas and 348 bopd of condensate and is primarily due to the completion of the newly drilled wells.

• A tendering process is underway to install the first phase of a field booster compression program in Uzbekistan, and the contract is expected to be awarded in the second quarter of 2026. Field booster compression is expected to increase gas production rates by lowering the gathering system pressure.

• The Company completed fabrication of its first LNG liquefaction facility in March 2026 (the "First LNG Facility") and is undergoing function and acceptance testing prior to shipment to Kazakhstan, which is expected in the second quarter of 2026.

• On April 15, 2025, the Company secured its third natural gas allocation in Kazakhstan for LNG feed gas, a portion of which will be allocated to the First LNG Facility.

• On August 12, 2025, the Company established a USD $5.0 million bridge loan facility (the "Bridge Loan") for the First LNG Facility which was originally set to mature on the earlier of March 30, 2026, and ten business days following the receipt of third-party project financing for the First LNG Facility. In March 2026, the Bridge Loan maturity date was extended to July 15, 2026, with all other terms remaining unchanged.

• On December 24, 2025, the Company completed a brokered private placement of convertible debentures for aggregate gross proceeds of $13.65 million, less cash issue costs of $1.06 million, which will be used to accelerate development activities and in-field compression facilities in Uzbekistan.

• The Company entered into a share purchase agreement on January 21, 2026, with a third-party buyer to sell the shares of the Company's wholly owned subsidiary which holds the Poyraz Ridge and Destan operating licenses and gas fields in Türkiye for a ten-year gross overriding royalty and a nominal cash payment.

The Company operates under a production enhancement services contract with JSC Uzbekneftegaz ("UNG") in Uzbekistan to increase the production, recovery, and overall system efficiency from an integrated cluster of eight conventional natural gas-condensate fields (the "PEC Project"). The cumulative license area is 282 km2 or the equivalent of 109 sections, with 71 active gas wells that produce mainly from a Jurassic Carbonate reservoir. Production in the fourth quarter of 2025 averaged 10,534 boe/d comprised of 10,218 boe/d (61,310 Mcf/d) of natural gas and 316 bopd of condensate or a total production increase of 5.6% compared to the third quarter of 2025 due mainly to successful workovers. March 2026 month-to-date production has averaged 12,622 boe/d comprised of 12,274 boe/d (73.6 MMcf/d) of natural gas and 348 bopd of condensate and is primarily due to the completion of the newly drilled wells.

In 2025, the Company reprocessed and interpreted 1,462 km2 of existing 3-D seismic data which has already identified more than 40 potential drilling locations. Drilling operations commenced in September 2025, and three wells have been drilled to date: two horizontal wells in the Andakli field (A-23 and A-21) and one vertical in the previously unidentified Kumli NW structure (K-45). The A-21 well was drilled with a 1,279-meter lateral section and a well test was conducted at a stabilized flowing rate of 7.3 MMscf/d (or 1,213 boe/d) through a 5/8" choke at a flowing tubing pressure of 722 psi for a two-hour period. The K-45 vertical well was drilled to a total depth of 2,410 meters and a well test was conducted at a stabilized flowing rate of 5.3 MMscf/d (or 883 boe/d) through a 1/2" choke at a flowing tubing pressure of 1,053 psi for seven hours. Both wells were tied into the production facilities immediately after testing. The A-23 horizontal well was drilled with a 1,007-meter lateral section and was recently completed with gas volumes flowing to surface. A faulty piece of completion equipment is being replaced before the well is tested and put into service.

Drilling of a fourth well, K-46 horizontal, started in late February 2026 on the same pad as K-45 and targets up to a 1,000-meter lateral section in the same reservoir. Based on K-45 results, the K-46 target pay section should also be dolomitized, which enhances the reservoir porosities and permeabilities and should contain an even higher reservoir quality compared to A-21 and A-23. Given the strong K-45 flow test results, the near virgin reservoir pressures observed, higher reservoir porosities than previously encountered, and the fact that horizontal wells often produce at two to four times the rate of vertical wells, the K-46 well could materially grow near term production rates. To date, K-46 has been drilled to 2,335 meters and intermediate casing set with completion and testing targeted for mid-April 2026.

Beyond the development of the Kumli NW structure, similar lightly developed structures have been identified from the Company's reprocessed 3-D seismic survey including the Kushimcha, Sharkiy Khatar, North Syuzma, and Kumli Central structures. Technical work is ongoing to estimate recoverable gas volumes and optimize well placements. These fields will be developed using a combination of vertical and horizontal wells later in 2026 and beyond. Of note is that the vertical wells will penetrate the deeper Jurassic clastics play, which is very lightly developed with promising upside. Two of the Company's highest daily gas rate wells are producing from this play at North Syuzma, and the Company plans to further delineate this play with the 2026 drilling program.

As noted above, the Company contracted the first drilling rig in September 2025 and drilled the A-23 and A-21 horizontal wells. A second drilling rig was contracted in December 2025, which drilled the K-45 vertical well and is now drilling the K-46 horizontal well. Multiple mechanical failures and significant nonproductive time were encountered by the first rig while drilling the A-23 and A-21 wells and this contract was recently terminated. The Company is actively sourcing a replacement rig with plans to drill up to twelve wells in 2026 to accelerate gas production volumes.

Installation of field booster compression remains a top priority for the Company in 2026. The tendering process is underway for the first phase with the contract expected to be awarded in the second quarter of 2026. Booster compression is expected to increase gas production by lowering the gathering system pressure, mitigating liquid loading effects in wellbores, and helping to manage the impact of fluctuating and increasing gas sales line pressures. Simulation work conducted by an independent third-party engineering company indicates compression could yield over 20 MMscf/d of incremental gas production and extend end-of-field life. The field compression facility is scheduled to be commissioned in the first quarter of 2027.

The Company has completed fabrication works on its First LNG Facility for the Saryozek plant site (the "Saryozek Site") and it is currently undergoing function and acceptance testing prior to its shipment to Kazakhstan in the second quarter of 2026. The Company expects to produce, distribute, and sell LNG to offset industrial diesel usage in Kazakhstan and end-user applications include rail locomotives, long-haul truck fleets, marine vessels, mining equipment, municipal bus fleets, and high-horsepower heavy equipment and machinery. All these LNG applications have successfully been implemented in other countries. LNG production is expected to commence late in the fourth quarter of 2026.

The First LNG Facility is expected to have an initial production capacity of 48,000 gallons (80 MT) of LNG per day, and due to its modular design, production at the Saryozek Site will subsequently be expanded by two additional 48,000 gallon per day facilities to fully utilize the gas allocation awarded for this site. The Saryozek Site is one of the three natural gas allocations awarded to the Company in Kazakhstan. The Company has secured 20 hectares of land at the Saryozek Site until July 2059 under an agreement which requires the Company to construct an LNG facility at the site prior to August 2030. The Company is also finalizing LNG off-taker agreements.

The Company is advancing third-party financing discussions to complete the First LNG Facility, and the Company may enter into one or more partnerships (or other joint venture structures) at its sites in Kazakhstan where it has already secured feed gas allocations (including the First LNG Facility).

As of December 31, 2025, the Company has incurred CAD $8.5 million of costs for the First LNG Facility, including $7.8 million for property, plant and equipment and $0.7 million for the third natural gas allocation. The estimated additional costs to complete the First LNG Facility construction and commissioning is USD $22.7 million (CAD $31.1 million) which includes various ancillary equipment, feed gas hookup and piping, power generation, electrical infrastructure, distribution equipment and storage tanks, LNG loading facilities and rolling stock.

Condor has received three natural gas allocations at three different locations within Kazakhstan, and the Company plans to construct modular LNG facilities at all three locations. Based on the natural gas allocations of 21,798 m3/hour, 29,110 m3/hour and 20,500 m3/hour, respectively, the total potential LNG fuel produced would have an energy-equivalent volume of 1.5 million litres of diesel daily, while also reducing CO2 emissions by 390,000 MT per year, which is equivalent to removing 85,000 cars from the road annually. See "Forward-Looking Statements" in this MD&A for further discussion on the risks and uncertainties related to the natural gas allocations and the Company's LNG initiatives.

On August 12, 2025, the Company, through a subsidiary, established a USD denominated $5.0 million Bridge Loan for the First LNG Facility which is on schedule to produce Kazakhstan's first LNG in the fourth quarter of 2026. The Bridge Loan was provided by EurAsia Resource Value SE, an existing significant shareholder of the Company, and provides funding to continue purchasing long lead equipment for the First LNG Facility while third-party project financing is being finalized. The Bridge Loan is unsecured, bears interest at 9.0% per annum, has no loan covenants, requires no repayment of principal or accrued interest until maturity, permits early repayment with no penalties or limitations, and was originally set to mature on the earlier of March 30, 2026, and ten business days following the receipt of third-party project financing for the First LNG Facility. In March 2026, the Bridge Loan was amended and the maturity date was extended to July 15, 2026, with all other terms remaining unchanged. The Bridge Loan's use of proceeds is for capital expenditures and general and administrative costs related to the construction and implementation of the First LNG Facility.

On December 24, 2025, the Company completed a brokered private placement of convertible debentures convertible into 6,825,000 common shares for aggregate gross proceeds of $13.65 million less cash debt issue costs of $1.06 million comprised of agent's fees, commissions, legal, advisory and regulatory fees and non-cash debt issue costs of $0.14 million related to broker and advisory warrants. The 2025 Debentures, as defined herein, are unsecured, bear interest at 12.0% per annum payable in cash semi-annually in arrears, have no loan covenants, mature on December 24, 2028, and the principal amount is convertible at any time at the option of the holder on or before the maturity date at a conversion price of $2.00 per common share. Any common shares issued upon conversion of the 2025 Debentures cannot be traded before April 25, 2026. The net cash proceeds of $12.59 million are expected to be used for development activities and in-field compression facilities in Uzbekistan, working capital and general corporate purposes.

The Company holds a 100% working interest in two contiguous critical minerals mining licenses which provide subsurface exploration rights for solid minerals, including lithium and copper, for respective six-year terms. The 37,300-hectare Sayakbay license was awarded in July 2023 and the nearby 6,800-hectare Kolkuduk license was awarded in February 2025. There has been a significant increase in the number of mining licenses awarded in the areas adjacent to the Company's license areas and active copper exploration activities are underway by major mining companies, including Rio Tinto.

A prior well drilled in the Kolkuduk license territory for hydrocarbon exploration encountered and tested brine deposits with lithium concentrations of up to 130 milligrams per litre as reported by the Ministry of Geology of the Republic of Kazakhstan. A 1,000-meter column of tested and untested brine reservoir has been identified from historical wireline log and core data. At Sayakbay, a prior legacy well drilled for hydrocarbon exploration encountered and tested brine deposits with lithium concentrations of 67 milligrams per litre in Carboniferous-aged intervals as reported by the Ministry of Geology of the Republic of Kazakhstan. A 670-meter column of tested and untested brine reservoir has been identified from historical wireline log and core data. Other critical minerals identified at the Kolkuduk and Sayakbay licenses include rubidium, strontium and cesium. Given the heavily faulted systems the Company has mapped in this geothermally active region, it appears that mineralized brines have migrated into the basin's reservoirs, as is evident by the lithium concentrations on Condor's blocks, as previously reported by the Ministry of Geology of the Republic of Kazakhstan.

The Company is not treating these historical estimates as current mineral resources or mineral reserves as additional drilling and testing is necessary, and a qualified person has not done sufficient work to classify the historical estimates as current mineral resources or mineral reserves. It is uncertain if further drilling will result in either area being delineated as a mineral resource or reserve. The historical lithium concentration estimates should not be relied upon as indicative of the actual lithium concentration or the likelihood that the Company will be able to achieve similar production results.

The initial development plan for Sayakbay includes drilling and testing two wells to verify deliverability rates, confirming the lateral extension and concentrations of lithium in the tested and untested intervals, conducting preliminary engineering for the production facilities, and preparing a mineral resource or mineral reserves report compliant with National Instrument 43-101 Standards of Disclosure for Mineral Projects. Drilling at Sayakbay is not expected to commence before 2027 and the estimated costs for the initial development plan are USD $6.7 million (CAD $9.1 million). The initial development plan for the Kolkuduk license acquired in February 2025 has not yet been determined.

‌The Company entered into a share purchase agreement (the "SPA") on January 21, 2026 (the "Signing Date") with a third-party buyer (the "Buyer") to sell the shares of the Company's wholly owned subsidiary which holds the Poyraz Ridge and Destan operating licenses and gas fields in Türkiye (the "Turkish Properties") for a ten-year gross overriding royalty and a nominal cash payment. The matter is subject to customary Turkish government approvals for a transaction of this nature (the "Government Approvals") and completion shall occur within ten business days of receiving the Government Approvals (the "Closing Date").

‌The SPA includes a gross overriding royalty at rates ranging from zero to 15% depending on average daily production volumes and calculated as sales revenues less government royalties and less transportation costs for a period of ten years subject to an aggregate cap of USD $10.0 million and a cash consideration of 18,000 Euros due on the Closing Date. There was no cash payment due on the Signing Date. Subject to certain considerations, the Buyer is required to perform a minimum work commitment (the "Minimum Work Commitment") which includes conducting various workover activities and drilling one new well on the Turkish Properties.

‌Commencing sixty days following the Signing Date, the Buyer is responsible for all operating expenditures until the Closing Date including production costs, general and administrative expenses and taxes.‌

‌The Buyer has the option during the period between the Signing Date and the Closing Date (the "Interim Period") to request the Company, as operator, to perform activities that will be credited towards the Minimum Work Commitment, and the Buyer shall be responsible for any related expenditures.

Either party may terminate the SPA if the Government Approvals are not received within one year of the Signing Date and the Company would be required to repay the capital expenditures incurred for the Minimum Work Commitment activities performed during the Interim Period from ninety percent of the free cashflow (revenues less operating costs and taxes) from future natural gas production and sales from the Turkish Properties, if any.

1 See "Royalties" in this MD&A which describes an immaterial adjustment made to royalties expense for the year ended December 31, 2024.

The Company's 2025 reserves in Uzbekistan were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. (see "Reserves Advisory" in this MD&A). The following reserves data as of December 31, 2025 is summarized by volume and net present value (before tax) discounted at 10% ("NPV10") in USD for: (i) the 100% property interest before deduction royalties ("100% Property Interest"); and (ii) Condor's 51% working interest share before deducting royalties ("51% Working Interest"). See "Non-Controlling Interest in the PEC Project" in this MD&A which describes these interests in reserves and future net revenue.

(* based on gas/boe conversion of 6 Mcf to 1 boe - see Reserves Advisory)

There are no economic reserves associated with the Company's properties in Türkiye and accordingly, an independent reserves evaluator has not been engaged to complete a reserve report as of December 31, 2025.

The Company recognizes 100% of the production volumes, sales volumes, sales revenues, royalties and expenses related to the PEC Project in Uzbekistan and then allocates 49% of the comprehensive income (loss) attributable to the non-controlling interest holder. This is consistent with the accounting and disclosure in the Financial Statements. Accordingly, the production volumes, sales volumes, sales revenues, royalties, expenses and netbacks disclosed in this MD&A related to the PEC Project are 100% of the amounts attributable to the PEC Project, of which 51% are attributable to the Company.

* Production commenced on March 1, 2024. Total and daily production volumes are for ten months and 306 days, respectively.

Production from the PEC Project in Uzbekistan for the fourth quarter of 2025 averaged 10,534 boe/d comprised of 10,218 boe/d (61,310 Mcf/d) of natural gas and 316 bopd of condensate, which is a 0.2% increase from the average production of 10,511 boe/d for the fourth quarter of 2024. Production from the PEC Project for the year ended December 31, 2025 averaged 10,484 boe/d comprised of 10,202 boe/d (61,213 Mcf/d) of natural gas and 282 bopd of condensate, which is a 1.9% increase from the average production of 10,292 boe/d for the ten months ended December 31, 2024. Since assuming operations in March 2024, the Company has flattened the natural production decline rates, which previously exceeded twenty percent annually.

Natural gas production in Türkiye was 397 Mcf or an average of 4 Mcf/d for the three months ended December 31, 2025 compared to 2,154 Mcf or an average of 23 Mcf/d for the same period in 2024, and was 2,739 Mcf or an average of 7 Mcf/d for the year ended December 31, 2025 compared to 29,478 Mcf or an average of 81 Mcf/d for the same period in 2024. The production decline is due mainly to the continuing natural decline of the maturing Poyraz Ridge field which has been producing for eight years with water production and natural pressure declines impeding gas production rates, along with the neighbouring Destan field being suspended in August 2024.

1. Operating netback is a non-GAAP measure and is a term with no standardized meaning as prescribed by GAAP and may

   not be comparable with similar measures presented by other issuers. See "Non-GAAP Financial Measures" in this MD&A. The calculation of operating netback is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook.

2. Amounts and per unit measures are only presented for the Uzbekistan segment.

3. Reconciliation to the respective financial statement amount for each netback component for the Uzbekistan segment.

4. See "Royalties" in this MD&A which describes an immaterial adjustment made to royalties expense for the year ended December 31, 2024.

5. Production commenced on March 1, 2024. Production volumes, sales and expenses for the year ended December 31, 2024 are for ten months (306 days).

‌Natural gas sales in Uzbekistan were consistent at $18.73 million on 5,269,061 Mcf or $3.55 per Mcf for the three months ended December 31, 2025 as compared to $18.73 million on 5,255,725 Mcf or $3.56 per Mcf for the same period in 2024 and increased to $74.21 million on 20,817,673 Mcf or $3.56 per Mcf for the year ended December 31, 2025 compared to $60.14 million on 17,149,079 Mcf or $3.50 per Mcf for the period from March 1, 2024 to December 31, 2024 due primarily to the increased sales volumes from twelve months of sales in 2025 as compared to ten months in 2024.‌

Condensate sales in Uzbekistan decreased to $1.65 million on 28,609 barrels or $57.50 per barrel for the three months ended December 31, 2025 compared to $2.20 million on 26,823 barrels or $81.98 per barrel for the same period in 2024, primarily due to lower condensate sales prices, partially offset by higher sales volumes in the fourth quarter of 2025. Condensate sales increased to $6.45 million on 102,030 barrels or $63.22 per barrel for the year ended December 31, 2025 compared to $6.10 million on 76,544 barrels or $79.65 per barrel for the period from March 1, 2024 to December 31, 2024 due primarily to increased sales volumes from twelve months of sales in 2025 as compared to ten months in 2024, partially offset by lower sales prices in 2025.

Natural gas sales in Türkiye decreased to less than $0.01 million on 309 Mcf for the three months ended December 31, 2025 from $0.05 million on 1,436 Mcf for the same period in 2024, and decreased to $0.03 million on 2,159 Mcf for the year ended December 31, 2025 from $0.39 million on 25,464 Mcf for the same period in 2024, due primarily to lower production volumes in 2025. Excluding the respective inflation adjustment impact on gas sales for each period, realized gas prices increased to $13.06 per Mcf for the three months ended December 31, 2025 from $12.25 per Mcf for the same period in 2024, and decreased to $13.06 per Mcf for the year ended December 31, 2025 from $13.35 per Mcf for the same period in 2024. There were no condensate sales in Türkiye for the years ended December 31, 2025 and 2024.

‌In Uzbekistan, natural gas is collected by gathering lines into two in-field facilities for initial processing to remove water and condensate and then transported by pipeline to a nearby third-party facility for further processing and onward transport by pipeline to the designated delivery point. Natural gas sales are domestic sales at local market prices. A portion of the associated condensate is separated from the natural gas at the two in-field facilities, and the remainder is separated and processed at the third-party facility. Condensate is sold to the buyer directly at each of the three facilities and the buyer is responsible for all onward transportation costs. Condensate sales prices are based upon Brent crude (a global benchmark for pricing crude oil) less a discount for processing, transportation and marketing.

‌In Türkiye, natural gas sales are domestic sales via pipeline at TRL denominated prices published monthly by the state-owned pipeline transportation company BOTAS Petroleum Pipeline Corporation ("BOTAS"). The benchmark for Condor's gas sales is BOTAS Level 2 wholesale tariffs less a marketing differential. Natural gas from the neighbouring Destan gas field is produced, compressed and trucked to the Company's owned and operated Poyraz Ridge gas plant and is marketed along with Poyraz Ridge gas production which is directly tied into the gas plant. Associated condensate is compressed and trucked to a near-by facility for blending, storage and onward sales at prices based on the nearest accessible global free market and determined by a formula provided for under the Petroleum Market Law and published monthly in TRL by the Turkish Petroleum Corporation, the Turkish national oil company.

‌Royalties and production entitlements in Uzbekistan decreased to $2.81 million for the three months ended December 31, 2025 compared to $2.90 million for the same period in 2024 due primarily to lower condensate sales prices in the fourth quarter of 2025, and were $11.15 million for the year ended December 31, 2025 compared to $9.17 million for the period from March 1, 2024 to December 31, 2024 due primarily to the increased natural gas and condensate sales volumes from twelve months of sales in 2025 as compared to ten months in 2024.

‌In accordance with the terms of the PEC Project, certain of the Company's payment obligations for royalty expenses are deferred. These liabilities are initially recognized at fair value by discounting the expected future payments at the Company's estimated incremental borrowing rate of 16% and are subsequently accreted over the deferral period to the principal amount on the due date with a corresponding non-cash accretion charge recognized in finance expense.

An immaterial adjustment has been made to the royalty expenses and non-cash finance income in the consolidated statements of income (loss) and comprehensive income (loss) and cash flows for the year ended December 31, 2024. Previously, the difference between the fair value of the payment obligations and the undiscounted value of these royalty expenses was recorded as non-cash finance income upon recognition. These royalty expenses should have been recorded at the discounted amount and non-cash finance income should not be recognized.

‌The adjustment for the three months ended December 31, 2024 is $0.98 million and the impact on the statement of income (loss) and comprehensive income (loss) is to reduce finance income from $1.07 million to $0.09 million and royalty expenses from $3.88 million to $2.90 million with a corresponding adjustment to total revenue from $17.10 million to $18.08 million. The impact on cash flows from operating activities is to reduce non-cash finance income from $0.98 million to $Nil and reduce the change in other long-term liabilities from $1.78 million to $0.80 million.

‌The adjustment for the year ended December 31, 2024 is $3.09 million and the impact on the statement of income (loss) and comprehensive income (loss) is to reduce finance income from $3.31 million to $0.23 million and royalty expenses from $12.30 million to $9.22 million with a corresponding adjustment to total revenue from

$54.32 million to $57.41 million. The impact on cash flows from operating activities is to reduce non-cash finance income from $3.09 million to $Nil and reduce the change in other long-term liabilities from $7.54 million to $4.45 million.

‌Excluding the respective discounting impact on certain royalty expenses for each period, the Company is subject to a 10% production entitlement payable to UNG (the "UNG Entitlement") and a 10% subsoil tax that is reimbursed to UNG on the natural gas and condensate produced under the PEC Project based on realized sales prices. The calculation of subsoil tax includes certain adjustments for processing and transportation costs. The effective total royalty and production entitlement rate including the discounting impact for the three months and year ended December 31, 2025 is 13.8% for both periods (December 31, 2024 - 13.8% for both periods).‌

In Türkiye, the Company is subject to a 12.5% royalty rate on natural gas and condensate sales. Royalties in Türkiye were less than $0.01 million for the three months ended December 31, 2025 compared to $0.01 million for the same period in 2024, and were less than $0.01 million for the year ended December 31, 2025 compared to $0.05 million for the same period in 2024, due primarily to lower natural gas production and realized sales prices in 2025.

Production costs to produce natural gas in Uzbekistan were $8.58 million or $1.63 per Mcf for the three months ended December 31, 2025 compared to $7.99 million or $1.52 per Mcf for the same period in 2024, and were

$33.88 million or $1.63 per Mcf for year ended December 31, 2025 compared to $25.06 million or $1.46 per Mcf for the period from March 1, 2024 to December 31, 2024. Production costs to produce condensate in Uzbekistan were $0.19 million or $6.75 per boe for the three months ended December 31, 2025 compared to

$0.18 million or $6.86 per boe for the same period in 2024, and were $0.70 million or $6.89 per boe for the year ended December 31, 2025 compared to $0.51 million or $6.64 per boe for the period from March 1, 2024 to December 31, 2024. Total production costs have increased primarily due to twelve months of sales in 2025 as compared to ten months in 2024. Per unit production costs for both natural gas and condensate have increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to additional personnel to manage the eight gas fields and in-field facilities, increased vehicle and equipment rental fees, and maintenance costs. Production costs in Uzbekistan are mainly comprised of facility, processing, compression, personnel, vehicle, equipment rental, safety and maintenance costs.

‌Total production costs in Türkiye were $0.16 million for the three months ended December 31, 2025 compared to $0.20 million for the same period in 2024, and were $0.60 million for the year ended December 31, 2025 compared to $0.72 million for the same period in 2024, primarily due to lower sales volumes. Production costs are primarily fixed in nature and are comprised mainly of field personnel, fuel, utilities, chemicals, water disposal, safety and maintenance costs.

Transportation and selling costs in Uzbekistan for natural gas were $0.65 million or $0.12 per Mcf for the three months ended December 31, 2025 compared to $0.66 million or $0.12 per Mcf for the same period in 2024, and were $2.60 million or $0.12 per Mcf for the year ended December 31, 2025 compared to $2.13 million or

$0.12 per Mcf for the period from March 1, 2024 to December 31, 2024. Transportation and selling costs for condensate were $0.01 million or $0.38 per boe for the three months ended December 31, 2025 compared to

$0.01 million or $0.37 per boe for the same period in 2024, and were $0.04 million or $0.38 per boe for the year ended December 31, 2025 compared to $0.03 million or $0.38 per boe for the period from March 1, 2024 to December 31, 2024. These costs are comprised of pipeline costs to deliver natural gas and associated condensate to the processing facilities and to deliver natural gas onwards to the designated sales delivery point and are fixed on a per unit basis.

Transportation and selling costs in Türkiye on natural gas sales decreased to less than $0.01 million or $0.62 per Mcf for the three months ended December 31, 2025 compared to $0.02 million or $0.61 per Mcf for the same period in 2024, and were less than $0.01 million or $0.69 per Mcf for the year ended December 31, 2025 compared to $0.21 million or $7.24 per Mcf for the same period in 2024. Transportation and selling expenses for natural gas sales are comprised of pipeline transmission fees and compressed natural gas trucking costs on Destan sales and for condensate sales are comprised of trucking, blending, storage and loading costs. These costs were higher in 2024 due mainly to the higher proportion of sales from Destan which requires additional trucking costs.

General and administrative expenses, comprised mainly of personnel, professional services, office, and travel costs, increased to $9.98 million for the year ended December 31, 2025 from $9.33 million for the same period in 2024, primarily due to higher personnel, consultants, professional services, travel and office costs related to the Uzbekistan project and higher costs in 2025 related to other new business initiatives.

Depletion and depreciation increased to $13.92 million for the year ended December 31, 2025 from $5.77 million for the same period in 2024. The increase is primarily due to increased depletion in Uzbekistan resulting from higher sales volumes in 2025 and a higher per unit depletion rate commencing in the fourth quarter of 2024, with another increase in the fourth quarter of 2025, based on the Company's reserve reports as of December 31, 2024 and 2025, respectively. Changes in decommissioning costs in Türkiye and Kazakhstan relating to oil and gas properties with no net book value are recognized immediately as depletion and depreciation expense and amounted to $0.73 million and $0.81 million, respectively, for the year ended December 31, 2025 (December 31, 2024 - $0.33 million and $1.84 million, respectively).

Stock based compensation expenses increased to $1.53 million for the year ended December 31, 2025 from

$0.70 million for the same period in 2024. The expense is recognized on a graded basis and fluctuates based on the fair value of stock options determined at the date of grant, the timing of the grants, vesting periods and estimated forfeiture rates.

Finance income increased to $0.46 million for the year ended December 31, 2025 from $0.23 million for the same period in 2024. Finance income is related to interest income earned on cash and cash equivalents and other long-term assets. See "Royalties" in this MD&A which describes an immaterial adjustment made to non-cash finance income for the year ended December 31, 2024.

Finance expense increased to $4.19 million for the year ended December 31, 2025 from $2.96 million for the same period in 2024. The non-cash accretion expense on certain PEC Project payment obligations for royalty expenses for the year ended December 31, 2025 was $0.73 million (December 31, 2024 - $0.16 million). See "Royalties" in this MD&A which describes this arrangement and an immaterial adjustment made to certain royalty expenses and non-cash finance income for the year ended December 31, 2024. The total undiscounted cash outflows required to settle these obligations are $12.88 million and are due between March 2029 and December 2030.

Effective interest expense on the loan facilities and Debentures was $2.51 million for the year ended December 31, 2025 (December 31, 2024 - $2.19 million), and accretion of provisions was $0.63 million for the year ended December 31, 2025 (December 31, 2024 - $0.46 million).

The Company had no risk management contracts that would be affected by interest rates in place during the years ended December 31, 2025 and 2024.

The foreign exchange gain for the year ended December 31, 2025 amounted to $0.97 million compared to a loss of $1.21 million for the same period in 2024, due primarily to the USD denominated Loan Facility, Bridge Loan and 2024 Debentures, as defined herein, partially offset by USD cash and cash equivalents held by the Company. The Company is exposed to significant foreign currency risk as the Company's natural gas and condensate sales and a substantial portion of foreign activities are transacted in or referenced to foreign currencies, a portion of the Company's cash and cash equivalents are held in USD and the Company's Loan Facility, Bridge Loan and 2024 Debentures are denominated in USD. Natural gas and condensate sales in Uzbekistan are domestic sales at local market prices, and natural gas sales in Türkiye are denominated in TRL.

The Company had no forward exchange rate contracts in place during the years ended December 31, 2025 and 2024.

As the 2024 Debentures are denominated in a currency other than the Company's functional currency, the conversion feature in the 2024 Debentures is accounted for as an embedded derivative liability and its fair value is estimated at each reporting period date with changes in fair value recognized in earnings as an unrealized gain or loss. The Company recognized an unrealized gain on embedded derivative of $0.55 million for the year ended December 31, 2025, compared to an unrealized loss of $0.69 million for the same period in 2024.

On April 15, 2025, the Company acquired the rights to a natural gas allocation in Kazakhstan for USD $0.48 million (CAD $0.66 million) to provide LNG feed gas for the First LNG Facility. The natural gas allocation does not meet the recognition criteria for an asset and was expensed during the year ended December 31, 2025.

Other expense of $1.92 million for the year ended December 31, 2024 relates to a termination and settlement agreement effective August 1, 2024 with third-party advisors who assisted Condor in pursuing investment opportunities in Uzbekistan. The associated liability is recorded to other long-term liabilities.

The Company recognized a net monetary gain of $0.01 million for the year ended December 31, 2025 (December 31, 2024 - $0.09 million) due to an increase in the Turkish inflation rate of approximately 31% (December 31, 2024 - 44%) since January 1, 2025.

Income tax expense for the year ended December 31, 2025 is comprised of current income tax expense of

$3.15 million (December 31, 2024 - $3.23 million) and deferred income tax recovery of $0.96 million (December 31, 2024 - $0.23 million) primarily related to Uzbekistan, where the tax rate is 15% of taxable income. The Company has not recognized the tax benefits associated with the operating activities of other business segments.

Net income for the year ended December 31, 2025 decreased to $1.23 million compared to $3.49 million for the same period in 2024, primarily due to higher expenses for production, general and administrative, depletion and depreciation and finance expense, partially offset by increased sales volumes and revenues from twelve months of sales in 2025 as compared to ten months in 2024, foreign exchange gain, gain on unrealized embedded derivative and changes in other expenses.

A third-party NCI shareholder holds 49% of the shares of Condor Natural Gas B.V. ("CNG"), the sole shareholder of the Company's subsidiary which is conducting the production enhancement services under the PEC Project in Uzbekistan. This NCI is allocated 49% of the comprehensive income of CNG commencing March 1, 2024. During the year ended December 31, 2025, dividends of $2.74 million were paid to this NCI (December 31, 2024 - $Nil).

A third-party NCI shareholder holds 10% of the shares of Condor LNG Ltd. ("CLNG"), the sole shareholder of three Kazakhstan subsidiaries which are developing LNG facilities in Kazakhstan. This NCI is allocated 10% of the comprehensive loss of CLNG commencing April 24, 2024.

The Company refers to "operating netback" in this MD&A, a term with no standardized meaning as prescribed by GAAP and which may not be comparable with similar measures presented by other issuers. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with GAAP. Operating netback is calculated as sales less royalties, production costs and transportation and selling costs on a dollar basis and divided by the sales volume for the period on a per Mcf basis for natural gas and per boe basis for condensate. The reconciliation of this non-GAAP measure is presented in the "Operating Netback" section of this MD&A. This non-GAAP measure is commonly used in the oil and gas industry to assist in measuring operating performance against prior periods on a comparable basis and has been presented to provide an additional measure to analyze the Company's sales on a per unit basis and the Company's ability to generate funds.

The Company commenced production enhancement services under the PEC Project in Uzbekistan in March 2024 and is responsible for all capital expenditures and operating costs associated with performing its services, including a minimum development work program as described in "Commitments and Contingent Liabilities" in this MD&A. In June 2024, the Company initiated a multi-well workover campaign which involved the installation of various artificial lift equipment, perforating previously non-depleted and bypassed pay zones, performing downhole stimulation treatments, and isolating identified water intervals. In September 2025, the Company commenced a multi-well drilling program and plans to drill up to twelve wells in 2026. The design and installation of field booster compression is ongoing and is expected to be commissioned in December 2026.

The Company has an LNG initiative in Kazakhstan and is seeking to produce and deliver LNG to displace diesel fuel usage in Central Asia.

The Sayakbay exploration license in Kazakhstan contains contractual work commitments of $0.2 million per annum during the first three years and $0.3 million per annum during the final three years of the six-year term. The Kolkuduk exploration license in Kazakhstan contains contractual work commitments of approximately $0.05 million per annum during the first three years and $0.1 million per annum during the final three years of the six-year term. The contractual work commitments may be amended from time to time in accordance with planned exploration activities proposed by the Company and approved by the Government of Kazakhstan and additional contractual work commitment amounts could be significant.

These initiatives will require the Company to use a combination of cash on hand, increase cashflows from operating activities, secure funding from debt or equity financing, dispose of assets or make other arrangements. There is no assurance that the Company will be successful with these initiatives and the outcome of these matters is uncertain.

The Company has borrowing arrangements which include: i) a term loan facility ("Loan Facility") which is unsecured, non-revolving, bears interest at 9.0% per annum paid quarterly, and with various quarterly principal payments due until maturity on July 14, 2026; ii) the Bridge Loan, which is unsecured, bears interest at 9.0% per annum with no repayment of principal or accrued interest due until the extended maturity date of July 15, 2026; iii) convertible debentures (the "2024 Debentures") convertible into 2,950,336 common shares which are unsecured, bear interest at 9.0% per annum payable in cash semi-annually, and with the principal due on the maturity date of March 21, 2027, unless converted into common shares at a conversion price of USD $1.61676 per common share; and iv) convertible debentures (the "2025 Debentures") convertible into 6,825,000 common shares which are unsecured, bear interest at 12.0% per annum payable in cash semi-annually, and with the principal due on the maturity date of December 24, 2028, unless converted into common shares at a conversion price of $2.00 per common share. The 2024 Debentures and 2025 Debentures are collectively referred to as the "Debentures".

As at December 31, 2025, the Company had a deficit of $8.10 million (December 31, 2024 - $3.89 million). For the year ended December 31, 2025, the Company reported net income of $1.23 million (December 31, 2024 -

$3.49 million) and cash flows from operating activities of $22.32 million (December 31, 2024 - $5.36 million). The Company's working capital balance has decreased from $25.98 million as at December 31, 2024 to a working capital deficiency of $4.13 million as at December 31, 2025. The working capital balance as at December 31, 2025 includes $7.29 million (December 31, 2024 - $7.78 million) related to the 2024 Debentures which are due on March 21, 2027, but are required under IFRS to be presented as a current liability given the conversion feature is accounted for as a financial liability and the principal amount is convertible at any time at the option of the holder into common shares of the Company on or before the maturity date.

Under the terms of the PEC Project, the Company is required to complete a five-year minimum development work plan (the "MDWP") which began in 2024 and establishes how the Company intends to enhance and optimize production from the eight natural gas-condensate fields. The MDWP includes the following work program: perform seventy-five well workovers, install artificial lifts in sixty wells, acquire 225 km2 of 3-D seismic, install water separation equipment, drill twenty-five new wells, install three field compression units, and perform upgrades for two in-field processing facilities. At the inception of the PEC Project, the estimated capital expenditures associated with the work program are USD $138.4 million (CAD $189.7 million), and the Company is entitled to determine the schedule and timing of completing the work program within the five-year period. The MDWP also includes estimated operating expenses of USD $170.5 million (CAD $233.7 million). The Company is actively executing on the activities set out in the MDWP work program and incurring the associated capital and operating expenditures. The performance and implementation of the MDWP is monitored regularly and may be amended by agreement between the Company and UNG. If the Company is unable to substantially complete the MDWP by December 31, 2028, except due to certain specified conditions, this is a specific material breach which allows for UNG to terminate the PEC Project, unless the Company can successfully negotiate an extension or amendment to the MDWP with UNG. Actual expenditures required to complete the specified work program and to operate the fields may be significantly different from the above estimates.

The PEC Project in Uzbekistan contains contractual provisions that allow for termination of the project in the event of a material breach. With respect to the Company, a material breach may include, but is not limited to, failure to substantially complete the MDWP, failure to use its best efforts in accordance with good oilfield practices to increase production, failure to perform production enhancement operations in accordance with the terms of the PEC Project or causing a deterioration in the production conditions of natural gas and condensate that existed on March 1, 2024. If such a breach occurs and is not remedied by the Company within the specified correction period, UNG may terminate the PEC Project. The Company actively monitors compliance with all contractual terms and maintains internal controls to mitigate the risk of a material breach. However, there can be no assurance that all risks will be fully mitigated, and the termination of the PEC Project could have a significant adverse effect on the Company's results of operations, cash flows and financial condition.

The Company has capital commitments for the First LNG Facility in Kazakhstan of USD $5.4 million (CAD $7.4 million), and the payments are due in a combination of time and milestone-based instalments until the First LNG Facility is commissioned, which is expected to be in the fourth quarter of 2026.

The Company has 100% interest in and operates the Poyraz Ridge and Destan operating licenses and gas fields in Türkiye. In March 2025, the competent authority in Türkiye extended the Poyraz Ridge license until June 2035 and the Destan license until June 2030. There are no work commitments related to the Poyraz Ridge or Destan licenses.

The Sayakbay exploration license in Kazakhstan contains contractual work commitments of $0.2 million per annum during the first three years and $0.3 million per annum during the final three years of the six-year term. The Kolkuduk exploration license in Kazakhstan contains contractual work commitments of approximately

‌$0.05 million per annum during the first three years and $0.1 million per annum during the final three years of the six-year term. The contractual work commitments may be amended from time to time in accordance with planned exploration activities proposed by the Company and approved by the Government of Kazakhstan and additional contractual work commitment amounts could be significant.

Credit risk

Credit risk arises from the possibility that a counterparty to which the Company provides goods or services is unable or unwilling to fulfil their contractual obligations. The maximum exposure to credit risk at period end is as follows:

The Company limits its exposure to credit risk on cash and cash equivalents and bank deposits by depositing and investing in banks with investment grade credit ratings.

Credit risk on trade receivables is related mainly to natural gas marketers, and the risk of financial loss if a customer, partner or counterparty to a financial instrument fails to meet its contractual obligations. During the years ended December 31, 2025 and 2024, sales of natural gas were sold to one customer in each of Uzbekistan and Türkiye, and sales of condensate in Uzbekistan were sold to UNG and therefore all sales transactions are subject to concentration risk. As at December 31, 2025, these three customers represented 99% of outstanding trade and other receivables (December 31, 2024 - 99%). Of the $16.05 million trade and other receivables balance as of December 31, 2025, $14.2 million has been collected subsequent to December 31, 2025.

Credit risk is mitigated by management's policies and practices. Natural gas and condensate produced in Uzbekistan are supplied to the domestic market through sales agreements with national companies of Uzbekistan. For condensate sales receivables in Uzbekistan, if full payment is not received from UNG when due, the Company may withhold the outstanding amount receivable from the payment due to UNG for the UNG Entitlement. For natural gas sales in Türkiye, the Company holds a bank guarantee provided by the buyer of its natural gas amounting to two month's estimated gas sales as security on gas sales receivables.

Liquidity risk and capital management

Liquidity risk is the risk the Company will encounter difficulty in meeting financial obligations and commitments and repaying liabilities as they fall due. The Company's objective is to ensure, as far as possible, that it will have sufficient liquidity to meet its obligations when due. The Company requires liquidity mainly to satisfy financial obligations and operating requirements related to activities in Uzbekistan, Kazakhstan and Türkiye. The Company looks to manage liquidity by adjusting its capital structure by issuing new equity or debt, disposing of assets and making adjustments to its capital expenditure program to the extent the capital expenditures are not committed.

As at December 31, 2025, the Company does not have sufficient resources or committed financing to fund all the development activities described in "Commitments and Contingent Liabilities" in this MD&A and the Company's long term success and ability to manage these obligations is dependent upon its continued ability to generate positive cash flows from operating activities, securing funding from debt or equity financing, disposing of assets, making other arrangements, or deferring certain non-committed components of its development program. While the Company believes it has sufficient resources to manage these obligations for the next year, there is no assurance that the Company will be successful with these longer term initiatives and the outcome of these matters is uncertain.

As at December 31, 2025, the Company had a deficit of $8.10 million (December 31, 2024 - $3.89 million). For the year ended December 31, 2025, the Company reported net income of $1.23 million (December 31, 2024 -

$3.49 million) and cash flows from operating activities of $22.32 million (December 31, 2024 - $5.36 million). The Company's working capital balance has decreased from $25.98 million as at December 31, 2024 to a working capital deficiency of $4.13 million as at December 31, 2025. The working capital balance as at December 31, 2025 includes $7.29 million (December 31, 2024 - $7.78 million) related to the 2024 Debentures which are due on March 21, 2027, but are required under IFRS to be presented as a current liability given the conversion feature is accounted for as a financial liability and the principal amount is convertible at any time at the option of the holder into common shares of the Company on or before the maturity date.

To manage capital expenditures and operating cashflows, annual budgets are prepared, monitored regularly and updated as required. The Company also utilizes authorizations for expenditures to manage capital spending.

The cash flows presented in the tables below are the contractual undiscounted cash flows and accordingly certain amounts differ from the amounts included in the consolidated statements of financial position. The Company's undiscounted contractual obligations are as follows:

Market risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices and their impact on the future performance of the business. Market risk is comprised of three types of market price changes: foreign currency exchange rates, interest rates and commodity prices. Derivative instruments may be used to reduce exposure to these risks.

Foreign currency exchange risk

The Company is exposed to significant foreign currency risk as the Company's natural gas and condensate sales and a substantial portion of foreign activities are transacted in or referenced to foreign currencies, a significant portion of the Company's cash and cash equivalents are held in USD and the Company's Loan Facility, Bridge Loan and 2024 Debentures are denominated in USD. Natural gas and condensate sales in Uzbekistan are domestic sales at local market prices and natural gas sales in Türkiye are denominated in TRL. In general, an increase in the value of the CAD as compared to the USD or the TRL will reduce the prices received by the Company for its natural gas and condensate sales. The Company had no forward exchange rate contracts in place during the years ended December 31, 2025 and 2024.

During the year ended December 31, 2025, the CAD appreciated from 1.44 per 1.00 USD to 1.37, the KZT appreciated from 523.5 per 1.00 USD to 502.6, and the TRL depreciated from 35.2 per 1.00 USD to 42.9, which led to a foreign exchange gain of $0.97 million (December 31, 2024 - loss of $1.21 million) related primarily to the USD denominated Loan Facility, Bridge Loan and 2024 Debentures, partially offset by USD cash and cash equivalents held by the Company.

During the year ended December 31, 2025, the CAD appreciated from 1.44 per 1.00 USD to 1.37, the KZT depreciated from 363.9 per 1.00 CAD to 367.2, and the TRL depreciated from 24.4 per 1.00 CAD to 31.3, resulting in a $0.96 million translation loss adjustment through equity (December 31, 2024 - $1.04 million translation gain).

Interest rate risk

Interest rate risk is the risk that the value of the financial instrument or future cash flows associated with the financial instrument will fluctuate as a result of changes in market interest rates. The Company's Loan Facility, Bridge Loan and 2024 Debentures all bear fixed-rate interest at 9.0% per annum, and the 2025 Debentures bear fixed-rate interest at 12.0% per annum. The value of these instruments is exposed to interest rate risk from changes in market interest rates. The Company had no risk management contracts that would be affected by interest rates in place during the years ended December 31, 2025 and 2024.

Commodity price risk

Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. The Company is exposed to changes in commodity prices inherent in the oil and natural gas industry. Commodity prices for oil and natural gas are impacted by economic events and factors which are beyond the Company's control. Fluctuations in petroleum and natural gas prices may have a significant effect on the Company's results of operations and cash flows from operating activities, and may also affect the value of the oil and gas properties, the level of spending for exploration and development and the Company's ability to raise capital. The Company had no derivative commodity price contracts in place during the years ended December 31, 2025 and 2024.

Natural gas sales in Uzbekistan are domestic sales at local market prices. Condensate sales prices in Uzbekistan are based on Brent crude less a discount for processing, transportation and marketing.

Natural gas sales in Türkiye are domestic sales via pipeline at prices published monthly by the state-owned pipeline transportation company BOTAS. The benchmark for Condor's gas sales in Türkiye is BOTAS Level 2 wholesale tariffs less a marketing differential.

Condor has offices, activities and operations in various areas in Canada, Uzbekistan, Türkiye and Kazakhstan. Company personnel are stationed and work and travel to and from these locations as required. Such personnel are exposed from time to time to concentrated groups of people at various locations both within and outside the Company's direct control, for varying lengths of time. Any personnel or visitors that become infected with a serious illness that has the potential to spread rapidly throughout the organization could place the personnel and the operations of the Company at risk.

Although the Company takes precautions and follows industrial hygiene and occupational health guidelines, there can be no assurance that an infectious illnesses will not negatively impact Condor's personnel or its operations and may in the future result in fluctuating demand for oil and gas, volatile oil and gas prices and the implementation of various travel restrictions which constrain or prohibit international travel and limit or forbid movement within the individual countries of operation.

Condor's future operations could be materially impacted by these factors, as well as related emergency measures including, but not limited to: travel restrictions including shelter in place orders, curfews and lockdowns which may impact the timing and ability of Company personnel, suppliers and contractors to travel internationally or domestically and to access or deliver services, goods and equipment to the fields of operation; the risk of shutting-in or reducing production due to travel restrictions, government orders, crew illnesses and the availability of goods, works and essential services for the fields of operations; the potential for gas pipeline or sales market interruptions; the risk of changes to foreign currency controls, availability of foreign currencies, availability of hard currency, and currency controls or banking restrictions which restrict or prevent the repatriation of funds from or to foreign jurisdiction in which the Company operates; the timing and ability to meet financial and other reporting deadlines; potential decreased interest in and ability to conclude farm-in transactions, potential decreased ability to raise additional capital to fund current operations and new business projects; and the inherent increased risk of information technology failures and cyber-attacks.

As at December 31, 2025, there were 68,376,783 common shares of the Company outstanding and as of the date of this MD&A, there were 68,378,783 common shares of the Company outstanding.

As at December 31, 2025, the Company has outstanding 5,548,900 stock options with a weighted average exercise price of $0.99 per common share. As of the date of this MD&A, the Company has outstanding 5,528,900 stock options with a weighted average exercise price of $0.98 per common share.

As at December 31, 2025 and the date of this MD&A, the Company has outstanding 2,918,672 common share purchase warrants as follows:

• 255,000 warrants at an exercise price of $0.48 per common share and expire on June 30, 2026;

• 2,278,334 warrants at an exercise price of $0.48 per common share and expire on July 14, 2026;

• 221,163 warrants at an exercise price of $2.20 per common share and expire on December 9, 2026; and

• 164,175 warrants at an exercise price of $2.00 per common share and expire on December 24, 2028.

As at December 31, 2025 and the date of this MD&A, outstanding convertible debentures include the 2024 Debentures convertible into 2,950,336 common shares at a conversion price of USD $1.61676 per common share until March 21, 2027 and the 2025 Debentures convertible into 6,825,000 common shares at a conversion price of $2.00 per common share until December 24, 2028.

On June 20, 2024, Condor's shareholders resolved by special resolution that the Company's share capital be reduced, without payment of or reduction to the Company's stated capital or paid-up capital, by the amount of the deficit as of December 31, 2023 of $219.39 million.

The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future.

The Company did not have any off-balance sheet arrangements as at December 31, 2025.

Key management comprises the executive officers and directors of the Company. Key management's compensation was comprised of $1.8 million of salary and benefits (December 31, 2024 - $1.8 million) and stock-based compensation expense of $0.6 million (December 31, 2024 - $0.3 million). In the event of termination or change of control, members of key management (excluding directors) are each entitled to two years' annual compensation.

The Bridge Loan was provided by EurAsia Resource Value SE, an existing significant shareholder of the Company, as described in "USD $5.0 Million LNG Bridge Loan Financing" in this MD&A.

‌The following table sets forth selected financial information of the Company for the eight most recently completed quarters to December 31, 2025:

1. The net income (loss) in all periods has been impacted by, among other things, production and sales volumes, commodity prices, operating costs, general and administrative costs, depletion and depreciation, finance expenses from the loan facilities and Debentures, unrealized gain (loss) on embedded derivative, changes in other expenses and foreign exchange gains and losses in the respective periods. The net income (loss) amounts include significant changes in revenues and expenses from the first quarter of 2024 onwards related to the Company commencing production enhancement activities under the PEC Project in Uzbekistan on March 1, 2024, as described in the relevant sections above in this MD&A.

2. Net income (loss) attributable to common shareholders is presented after the allocation of net income (loss) attributable to non-controlling interests. See "Non-controlling interest ("NCI")" in this MD&A which describes the two NCIs.

3. Per share amounts are basic and diluted and attributable to common shareholders. The Company treats the common shares as either dilutive or anti-dilutive based on net income (loss). If the common shares are anti-dilutive at this level, they are treated as anti-dilutive for all other per share calculations.

The timely preparation of financial statements requires management to make use of judgments, estimates and assumptions when transactions affecting the current accounting period cannot be finalized until future periods. These estimates will affect assets, liabilities and the disclosure of assets and liabilities at the date of the financial statements, as well as revenues and expenses during the reporting periods. Such estimates are based on informed judgments made by management. Actual results could differ from those estimates as future confirming events occur. Significant assumptions and estimates about the future and other sources of estimation uncertainty that management has made at the financial position reporting date that could result in a material adjustment to the carrying amount of assets and liabilities, in the event that actual results differ from assumptions made, are outlined below.

• Identification of Impairment Indicators - Property, plant and equipment: Significant judgment is required to assess when internal or external indicators of impairment or impairment reversal exist, and impairment testing is required. Management considers internal and external sources of information including future natural gas and condensate prices, expected production volumes, future operating, royalty and capital costs, anticipated recoverable quantities of proved plus probable oil and gas reserves and rates used to discount the related future cash flow estimates. A downward revision in the reserve estimates or future forecast prices or an upward revision to future capital costs could result in an asset impairment which would reduce future earnings and the associated net book value of assets. Judgment is required to assess these factors when determining if the carrying amount of an asset or CGU is impaired, or in the case of a previously impaired asset or CGU, whether the previous amount impaired can be reversed;

• Depletion: estimates include the amount of reserve volumes and future development capital. A downward revision in the reserve estimates or an upward revision to future capital may result in increased depletion and a reduction in net book value of assets if such a revision results in an accounting impairment. Depletion is charged on a unit-of-production basis over the Proved plus Probable reserves for each cash generating unit and a revision in the productive capacity of the assets may result in increased depletion and a reduced net book value of assets;

• E&E expenditures: costs associated with acquiring oil and gas licenses and exploratory drilling are accumulated as E&E assets pending determination of technical feasibility and commercial viability. Establishment of technical feasibility and commercial viability is subject to judgment and involves management's review of project economics, resource quantities, expected production techniques, production costs and required capital expenditures to develop and extract the underlying resources. Management uses the establishment of commercial reserves within the exploration area as the basis for determining technical feasibility and commercial viability. Upon determination of commercial reserves, E&E assets attributable to those reserves are tested for impairment and reclassified from E&E assets to a separate category within property, plant and equipment referred to as oil and gas properties;

• Identification of Impairment Indicators - E&E assets: the Company assesses its E&E assets to determine whether any indication of impairment exists at the end of each reporting period if facts and circumstances suggest the carrying amount exceeds the recoverable amount. Significant judgment is required in determining whether indicators of impairment exist, including factors and considerations such as the remaining period for which the Company has the right to explore, whether expenditures on further exploration and evaluation of properties are budgeted, whether commercially viable quantities of mineral resources have been discovered or whether data exists to suggest the carrying amount is unlikely to be recovered;

• Decommissioning provisions: estimates include the amount and expected timing of asset retirements, discount and inflation rates and future cashflows. As a result of the long-term nature of the Company's operations, these estimates may change over time which may result in a change in the decommissioning provision and corresponding asset value, and impact future earnings (loss) as a result of changes in accretion and depletion expense;

• Convertible debentures: The conversion feature associated with the USD denominated 2024 Convertible Debentures has been identified as a derivative financial liability. Derivative financial liabilities are recorded upon recognition and subsequently at each period-end date at fair value, with changes in fair value being recognized in earnings. The fair value estimate involves assumptions regarding the probability a forced conversion will occur, the expected life of the Debentures, dividend yields, risk-free interest rates and volatility of the Company's common shares. The fair value is measured using the Black-Scholes option pricing model, and using an alternate pricing model could produce different results;

• Stock based compensation: estimates include determining appropriate share price volatility, expected lives, forfeiture rates and risk-free rates. The expense is measured using the Black-Scholes option pricing model, and using an alternate pricing model could produce different results;

• Going concern: estimates include the ability to fund operations by generating positive cashflows from operations, securing funding from additional debt or equity financing, disposing of assets or making other arrangements;

• Income taxes: tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As such, income taxes are subject to measurement uncertainty. Deferred tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings. Changes in the estimate of future taxable income and the recovery of deductible temporary differences may result in the recognition of a deferred tax asset on the statement of financial position and an increase in earnings at the time when the tax recovery is recorded; and

• As part of its capital management process, the Company prepares budgets and forecasts, which are used by management and the Board of Directors to direct and monitor the strategy and ongoing operations and liquidity of the Company. Budgets and forecasts are subject to significant judgement and estimates relating to activity levels, future cashflows and the timing thereof and other factors which may or may not be within the control of the Company (see "Liquidity and Capital Resources").

Amendments to IAS 21 "The Effects Changes in Foreign Exchange Rates": On January 1, 2025, the Company adopted the amendments to IAS 21 that help to determine whether a currency is exchangeable into another currency, and which spot exchange rate to use when it is not. The Company determined that the amendments did not have a material impact on the consolidated financial statements.

IFRS 18 "Presentation and Disclosure in Financial Statements": On April 9, 2024, the IASB issued IFRS 18, which will replace International Accounting Standard 1, "Presentation of Financial Statements". IFRS 18 will establish a revised structure for the Consolidated Statements of Income and Comprehensive Income and improve comparability across entities and reporting periods. IFRS 18 is effective for annual periods beginning on or after January 1, 2027. The standard is to be applied retrospectively, with certain transition provisions. The Company is still assessing the impact of IFRS 18 on the consolidated financial statements, particularly with respect to the structure of consolidated statements of income (loss), consolidated statements of cash flows and the additional disclosures required for management-defined performance measures.

Amendments to IFRS 9 "Financial Instruments" and IFRS 7 "Financial Instruments: Disclosures": On May 30, 2024, the IASB issued targeted amendments to IFRS 9 and IFRS 7 which include new requirements for financial institutions and corporate entities to clarify the date of recognition and derecognition of some financial assets and liabilities, with a new exception for some financial liabilities settled through an electronic cash transfer system. These new requirements will apply from January 1, 2026, with early application permitted. The Company does not expect the amendments to have a material impact on the consolidated financial statements.

Contracts Referencing Nature-dependent Electricity - Amendments to IFRS 9 and IFRS 7: In December 2024, the IASB issued targeted amendments to IFRS 7 and IFRS 9 to allow entities to better reflect nature-dependent electricity contracts in the financial statements. The Company does not expect the amendments to have a material impact on the consolidated financial statements.

The Company's President and Chief Executive Officer ("CEO") and Vice President, Finance and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Financial Statements for external purposes in accordance with IFRS Accounting Standards.

The DC&P have been designed to provide reasonable assurance that material information relating to Condor is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by Condor under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation.

‌The CEO and CFO are required to cause the Company to disclose any change in the Company's ICFR that occurred during the most recent period that has materially affected, or is reasonably likely to materially affect, the Company's ICFR. During the year ended December 31, 2025, there were no changes to the Company's ICFR that have materially affected or are reasonably likely to materially affect, the Company's ICFR. It should be noted that a control system, including the Company's DC&P and ICFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICFR will prevent all errors or fraud.

The CEO and CFO have evaluated the Company's DC&P and ICFR as at December 31, 2025 based on the framework in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation, the CEO and CFO concluded that the Company's design and operation of DC&P and ICFR were effective as of December 31, 2025.

In the normal course of business, the Company is exposed to a variety of risks and uncertainties. In addition to the risks associated with liquidity and capital resources, commitments and contingent liabilities, critical accounting estimates, financial instruments, credit risk and market risk described in this MD&A, the Company is exposed to various operational, technical, financial and regulatory risks and uncertainties, many of which are beyond its control and may significantly affect future results. Operations may be unsuccessful or delayed as a result of competition for services, supplies and equipment, mechanical and technical difficulties, the ability to attract and retain employees and contractors on a cost-effective basis, commodity and marketing risk and seasonality. The Company is exposed to considerable risks and uncertainties including, but not limited to:

• the timing and ability to find natural gas, condensate and critical mineral reserves on an economical basis;

• uncertainties related to estimating the initial production rate of the type curve horizontal wells;

• uncertainties related to estimating the increased production rates for installing field compression;

• uncertainties related to estimating the Company's reserves;

• financial risks including access to debt or equity markets on acceptable terms;

• technical problems which could lead to unsuccessful wells, well blowouts and environmental damage;

• obtaining regulatory approvals on a timely basis or at all;

• third-party related operational risks including the ability to obtain access to wells, access to third party processing facilities, and access to pipelines, railways and other transportation infrastructure;

• obtaining qualified personnel, parts, equipment and service providers in a timely and cost-efficient manner;

• fluctuations in commodity prices, interest rates and foreign currency exchange rates;

• adverse factors including climate, geographical and weather conditions and natural disasters;

• risks associated with human resources management including labor disputes;

• timing of future debt and other obligations;

• potential for prior year tax reassessments not aligned with previously filed and assessed periods;

• regulatory legislation and policies, including the fulfillment of contractual minimum work programs, the compliance with which may require significant expenditures and non-compliance with which may result in fines, penalties, production restrictions, suspensions or revocations of contracts;

• changes to taxation policies, laws and interpretations thereof;

• political risks inherent with international activities and doing business in foreign jurisdictions;

• medical and health risks inherent with international activities and doing business in foreign countries including travel bans or travel restrictions;

• obtaining comprehensive and appropriate insurance coverage at reasonable rates;

• obtaining approval for extensions to development periods;

• obtaining approval for extensions to exploration periods, and, upon commercial discovery, negotiating and signing development contracts;

• negative public or community response to natural gas, condensate and critical minerals exploration, development and production and related environmental impacts could adversely affect Condor's business and the price of its securities; and

• information technology and system risks including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, data privacy and destruction or interruption of the Company's information technology.

‌Please see the Company's Annual Information Form, filed on SEDAR+ at https://www.sedarplus.ca for further discussion on these risks.

In 2022, Russia commenced a military operation in Ukraine, and in response to the invasion several countries imposed financial and other trade sanctions against Russia, including prohibitions or restrictions from doing business anywhere in the world with listed Russian individuals or companies. New or additional sanctions or new or additional military operations in relation to the invasion are unknown at this time. Similarly, the results, continuation or escalation of the Israeli-Palestinian conflict, the Middle East conflicts (including the attacks by the U.S. and Israel on Iran and Iranian retaliation) and the U.S. intervention in Venezuela are unknown at this time. To-date these events have not impacted the Company's ability to carry on business, there have been no significant delays or direct security issues affecting the Company's operations, offices or personnel, and the enacted sanctions have not affected the Company's operations. The outcome of these events is uncertain at this time and may impact the peace and stability of the region and the world and could affect the global economy including regions and markets in which the Company operates. Any subsequent commodity supply shortages or volatile commodity prices could have adverse impacts on the world economy and the Company's business. If these events continue, re-occur or escalate, they could have a material adverse effect on Condor's business, financial condition or results of operations.

This MD&A includes information pertaining to the Evaluation of Crude Oil and Natural Gas Reserves as of December 31, 2025 prepared by independent reserves evaluator McDaniel & Associates Consultants Ltd. ("McDaniel"). The report was prepared by qualified reserves evaluators in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and is based on contractual pricing for natural gas and McDaniel forecast pricing for condensate effective December 31, 2025. Additional reserve information as required under NI 51-101 is included in the Company's Annual Information Form filed on SEDAR+ at: https://www.sedarplus.ca.

Statements relating to reserves are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated. The reserve estimates described herein are estimates only. The actual reserves may be greater or less than those calculated. Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations, probabilistic methods and analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

References herein to barrels of oil equivalent ("boe") are derived by converting gas to oil in the ratio of six thousand standard cubic feet ("Mcf") of gas to one barrel of oil based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf to 1 barrel, utilizing a conversion ratio at 6 Mcf to 1 barrel may be misleading as an indication of value, particularly if used in isolation.

"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves.

"Probable" reserves are those additional reserves that are less certain to be recovered than Proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves.

Certain statements in this MD&A constitute forward-looking information under applicable securities legislation. Such statements are generally identifiable by the terminology used, such as "expect", "plan", "believe", "intend", "estimate", "may", "will", "should", "could", "would", "potential", "ongoing", "seek", "future", "forecast", "continue", "capable", "schedule" or other similar wording. Forward-looking information in this MD&A includes, but is not limited to, information concerning: the timing and ability of the Company to execute growth and sustainability strategies including the financing for these activities; the timing and ability to substantially complete the MDWP under the PEC Project; the timing and ability to maintain compliance with contractual provisions that allow for termination of the PEC Project; the timing and ability to conduct the multi-well drilling program; the timing and ability of the identified drilling locations to be drilled and become producing wells; the timing and ability to drill a 1,000 meter lateral section in the K-46 well; the timing and ability for the K-46 target pay section to be a dolomitized reservoir; the timing and ability of a dolomitized reservoir to have enhanced reservoir porosities and permeabilities and to potentially

increase reserve volumes and production rates; the timing and ability to contract a replacement drilling rig; the timing and ability to complete the planned 2026 drilling program; the timing and ability to test new wells and put them on production; the timing and ability to identify new structures based on reprocessed seismic and the timing and ability to estimate recoverable reserves, optimize well placements, drill wells, penetrate deeper plays and to further delineate these prospects; the timing and ability to install field booster compression; the timing and ability of the field compression to increase production and reduce back pressure; the timing and ability to receive and utilize the natural gas allocations as feed gas for the planned modular LNG production facilities; the Company's expectations in respect of the future uses of LNG; the timing and ability to acquire, transport and construct modular LNG production facilities; the timing and ability to obtain funding for the construction of modular LNG production facilities on favourable terms, or at all; the timing and ability to secure third-party financing for the First LNG Facility; the timing and ability to enter into one or more partnerships (or other joint venture structures) at the Company's sites in Kazakhstan where it has already secured feed gas allocations; the timing and ability to produce and deliver LNG to displace diesel fuel usage in Central Asia; the Company's expectations regarding reduction in CO2 emissions based on productivity of the LNG facilities; the timing and ability to conduct function and acceptance testing and transport the First LNG Facility to Kazakhstan; the timing and ability to commence LNG production; the estimated costs to complete the First LNG Facility construction and commissioning; the timing and ability to liquefy natural gas to produce LNG; the timing and ability to confirm LNG volume commitments with potential end-users; the timing and ability of the First LNG Facility to produce 48,000 gallons of LNG per day; the timing and ability of the Company to construct two additional modular LNG facilities capable of producing 48,000 gallons of LNG per day at the First LNG Facility site; the timing and ability to finalize LNG off-taker agreements; the potential for the Sayakbay and Kolkuduk license to contain commercial deposits; the timing and ability of the Company to fund, permit and complete planned activities at Sayakbay including drilling two wells and conducting preliminary engineering for the production facilities; the timing and estimated costs of the initial development plan for Sayakbay; the timing and ability of the Company to generate a report in compliance with National Instrument 43-101 Standards of Disclosure for Mineral Projects; the timing and ability to commence exploration mining activities to evaluate the potential for commercial lithium brine deposits; the timing and ability to obtain the required government approvals and complete the sale of the Turkish Properties; the potential consequences of failing to obtain Government Approval to complete the sale of the Turkish Properties, including the right of either party to terminate the SPA; the timing and ability to receive funding from the potential buyer for the work commitments and operating costs of the Turkish Properties; the accuracy of the projections and timing with respect to natural gas and condensate production; expected markets, prices and costs for future natural gas and condensate sales; the timing and ability of the Company to obtain various approvals and conduct its planned exploration and development activities; the timing and ability to access natural gas pipelines; the timing and ability to access domestic and export sales markets; the accuracy of the anticipated capital expenditures; forecasted capital and operating budgets and cashflows; anticipated working capital; sources and availability of financing for potential budgeting shortfalls; the timing and ability to obtain future funding on favourable terms, if at all; the potential for additional contractual work commitments to be significant; the ability to satisfy and fund the contractual work commitments; projections relating to the adequacy of the Company's provision for taxes; the expected reporting impacts of adopting amendments to IFRS accounting policies; and treatment under governmental regulatory regimes and tax laws.

This MD&A also includes forward-looking information regarding health risk management including, but not limited to: travel restrictions including shelter in place orders, curfews and lockdowns which may impact the timing and ability of Company personnel, suppliers and contractors to travel internationally, travel domestically and to access or deliver services, goods and equipment to the fields of operation; the risk of shutting in or reducing production due to travel restrictions, government orders, crew illness, and the availability of goods, works and essential services for the fields of operations; decreases in the demand for oil and gas; decreases in the prices of natural gas, condensate and crude oil; potential for gas pipeline or sales market interruptions; the risk of changes to foreign currency controls, availability of foreign currencies, availability of hard currency, and currency controls or banking restrictions which restrict or prevent the repatriation of funds from or to foreign jurisdiction in which the Company operates; the Company's financial condition, results of operations and cash flows; access to capital and borrowings to fund operations and new business projects on terms acceptable to the Company; the timing and ability to meet financial and other reporting deadlines; and the inherent increased risk of information technology failures and cyber-attacks.

By its very nature, such forward-looking information requires Condor to make assumptions that may not materialize or that may not be accurate including, but not limited to, the assumptions that: the Company will be able to secure necessary drilling rigs, support services, and off-taker agreements in a timely manner; the Company will be able to secure third-party financing for the First LNG Facility; the Company will be able to enter into one or more partnerships (or other joint venture structures) at its sites in Kazakhstan where it has already secured feed gas allocations; the engineering design and final investment decisions for additional LNG facilities will proceed as planned; the Company will complete construction of its LNG facilities and that the LNG feed gas for such facilities will be supplied; the Government of Kazakhstan will continue to invest in infrastructure supporting the TITR expansion; the Company's additional drilling and testing will be successful in verifying deliverability rates and confirming mineral concentrations; the Company will be able to fund its initiatives through a combination of cash on hand, increased cashflows, debt or equity financing, asset sales, or other arrangements; the Company will be able to manage liquidity and capital expenditures through budgeting and authorizations for expenditures; the Company will be able to manage health, safety, and operational risks through existing precautions and guidelines; the Company will be able to adapt to changing trade policies, tariffs, and restrictions; and the Company will be able to manage the impact of geopolitical instability and sanctions. Forward-looking information is subject to both known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such information. Such risks and uncertainties include, but are not limited to: regulatory changes including changes to environmental regulations; the timing of regulatory approvals; the risk that actual minimum work programs will exceed the initially estimated amounts; the results of exploration and development drilling and related activities; the risk that prior lithium testing results may not be indicative of future testing results or actual results; the risk of imprecision of reserves estimates and ultimate recovery of reserves; the risk that historical production and testing rates may not be indicative of future production rates, capabilities or ultimate recovery; the risk that the historical composition and quality of oil and gas does not accurately predict its future composition and quality; general economic, market and business conditions; risks relating to the uncertainty related to marketing and transportation; competitive action by other companies; fluctuations in oil and natural gas prices; the effects of weather and climate conditions; fluctuation in interest rates and foreign currency exchange rates; the ability of suppliers to meet commitments; actions by governmental authorities, including increases in taxes, tariffs, levies and fees; decisions or approvals of administrative tribunals and the possibility that government policies or laws may change or the possibility that government approvals may

be delayed or withheld; risks associated with oil and gas operations, both domestic and international; and other factors, many of which are beyond the control of Condor.

These risk factors are discussed in greater detail in filings made by Condor with Canadian securities regulatory authorities including the Company's most recent Annual Information Form, which may be accessed through SEDAR+ at https://www.sedarplus.ca.

Readers are cautioned that the foregoing list of factors affecting forward-looking information is not exhaustive. The forward-looking information contained in this MD&A are made as of the date of this MD&A and, except as required by applicable law, Condor does not undertake any obligation to update publicly or to revise any of the included forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained in this MD&A is expressly qualified by this cautionary statement.

The following is a summary of abbreviations used in this MD&A: 3-D Three dimensional

Mbbl Thousands of barrels of oil

Mboe Thousands of barrels of oil equivalent Mcf Thousands of standard cubic feet

Mcf/d Thousands of standard cubic feet per day MMcf/d Millions of standard cubic feet per day

bbl Barrels of oil

bopd Barrels of oil per day

boe Barrels of oil equivalent

boe/d Barrels of oil equivalent per day

MT Metric tonnes

GAAP Generally Accepted Accounting Principles YTD Year to date

CAD Canadian Dollars

KZT Kazakhstan Tenge

TRL Turkish Lira

USD United States Dollars

LNG Liquefied natural gas

Türkiye Republic of Türkiye Kazakhstan Republic of Kazakhstan Uzbekistan Republic of Uzbekistan