Condor Announces 2026 Third Quarter Results and Record Production of 18,631 boe/d

CALGARY, Alberta, Nov. 12, 2026 (GLOBE NEWSWIRE) -- Condor Energies Inc. (“Condor” or the “Company”) (TSX:CDR), a Canadian based, internationally focused energy transition company focused on Central Asia is pleased to announce the release of its unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2026 (the “Financial Statements”), together with the related management’s discussion and analysis. These documents will be made available under Condor’s profile on SEDAR+ at www.sedarplus.ca and on the Condor website at www.condorenergies.ca. Readers are invited to review the latest corporate presentation available on the Condor website. All financial amounts in this news release are presented in Canadian dollars, unless otherwise stated.

HIGHLIGHTS

• Production in Uzbekistan for the third quarter of 2026 averaged 16,693 boe/d comprised of 16,240 boe/d (97.4 MMscf/d) of natural gas and 453 bopd of condensate which is a total production increase of 20% from the second quarter of 2026 and a total production increase of 67% from the third quarter of 2025.
• Uzbekistan natural gas and condensate sales for the third quarter of 2026 increased to $33.6 million or a 24% increase from the second quarter of 2026.
• During the period from November 1, 2026 through November 11, 2026, the Company achieved a new average production record of 18,631 boe/d primarily due to the completion and tie in of recently drilled wells.
• Five new wells were drilled and completed during the third quarter of 2026 and the Company has now drilled and completed eleven wells to date in 2026 and plans to drill and complete up to an additional four wells by year end.
• Initial test results from the Andakli-22 horizontal well (“A-22”) drilled in October 2026 indicate that commercially recoverable gas may be produced outside of conventionally targeted four-way structural closures.
• The Company also drilled its first deeper Jurassic clastic reservoirs well at North Syuzma (“NS-14”) in October and November 2026 and encountered 54 meters of net gas pay based on wireline logs. The drilling rig is being moved off location and completion and testing activities will commence shortly.
• In August 2026 an EPC contract was awarded to install the first phase of a field booster compressor station (the “Compressor Station”) in Uzbekistan which is expected to increase production rates by lowering the gathering system pressure.
• In October 2026 acceptance testing was completed for the Company’s first LNG facility (the “First LNG Facility”) for the Saryozek plant site (the “Saryozek Site”) and shipping to Kazakhstan is underway with an expected arrival in December 2026.
• In October 2026, the Company completed an offering of 12% unsecured convertible debentures for gross proceeds of $72.0 million. The debentures are convertible into common shares of the Company at a conversion price of $6.00 per common share and mature on October 15, 2029.
  
  

MESSAGE FROM CONDOR’S CEO

Don Streu, President and CEO of Condor commented: “2026 has been a transformational growth year for Condor as demonstrated by the recent performance accomplishments noted above. We have achieved record production rates, revenues and operating netbacks in Uzbekistan with our successful application of proven technologies while maturing new opportunities to support this trend. Our current activities in Uzbekistan are providing sustainable growth for reserves, production, and cashflow while we concurrently advance our LNG fuel substitution project and our early-stage copper and lithium critical minerals opportunities in Kazakhstan.

We are very excited and well positioned to continue building strong, near-term shareholder value from our diverse energy transition portfolio”.

Production in Uzbekistan

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 78 producing wells which produce gas mainly from Jurassic carbonate reservoirs.

Production in Uzbekistan for the third quarter of 2026 averaged 16,693 boe/d comprised of 16,240 boe/d (97.4 MMscf/d) of natural gas and 453 bopd of condensate which is a 20% production increase compared to the second quarter of 2026 and a 67% increase compared to the third quarter of 2025.

The Company continues to target previously undeveloped reservoirs within its 282 km2 (~109 sections equivalent) license area with the objective of generating sustained production growth. Although most of the 2026 drilling activity has focused on the Kumli license, one of the two drilling rigs was recently relocated to the northern Andakli license and drilled A-22 outside of existing mapped structural closure boundaries. A-22 has demonstrated that commercially recoverable gas can be produced outside of conventionally targeted four-way structural closures which could become part of the Company’s next growth engine.

A-22 was drilled to a total measured depth of 3,455 meters with a lateral interval of 1,127 meters. After A-22 was acid stimulated, it was tested for an 8-hour period that yielded an average flowing rate of 6.0 MMscf/d (1,000 boepd) on a 1” choke at 444 psi average flowing tubing pressure. There was no condensate produced and the liquid rate was 667 barrels per day, which consisted primarily of drilling and completion fluids and spent acid. The well was immediately tied into the gas sales line and continues to produce while further cleaning up. The A-22 test rate is a short-term test rate and may not be indicative of long-term performance or ultimate recovery. The Company believes the A-22 test result is very impactful as it may open significant areas of prospective drilling acreage at Andakli and help derisk the commerciality of a stratigraphic horizontal well development program. Numerous Andakli follow up wells are planned as part of the 2027 drilling campaign.

After drilling the A-22 stratigraphic play, the rig moved to the Company’s North Syuzma field to drill the NS-14 vertical delineation well that targeted the deeper Jurassic clastic stacked reservoir sands. The Company previously perforated a portion of this sand package on two legacy wells in November 2025 which flowed at a combined gas rate of 13.3 MMscf/d as previously disclosed. NS-14 was drilled to 2,810 meters to evaluate the full extent of the stratigraphic column and encountered 54 meters of net gas pay based on wireline logs, with 40 meters of net gas pay in the clastic reservoirs and 14 meters in the carbonate reservoirs. Completion activities are planned to commence once the drilling rig is moved off the location and testing is expected to begin by the end of November 2026. Pending test results, up to three additional vertical and three additional horizontal follow up locations could be drilled at North Syuzma.

The Company is currently drilling the K-53 horizontal well (“K-53”) on a separate structure within the Kumli license area. K-53 was originally designed as a multilateral well with two horizontal sections (“Legs”) targeting separate carbonate reservoirs. While drilling the first leg, K-53 encountered a previously unmapped fault that resulted in the lateral penetrating both target reservoirs, effectively achieving the reservoir access originally contemplated through two horizontal legs. Given this outcome, the Company has elected to complete K-53 as a single-leg horizontal well which is expected to reduce additional drilling time and capital requirements.

Multilateral well designs remain an important option for future development, offering the potential for increased reservoir contact and production, lower drilling and tie-in costs relative to separate horizontal wells, and a reduced surface footprint. The Company intends to deploy this technology where reservoir and drilling conditions support its use.

Nine wells have been drilled in the Kumli NW structure so far in 2026, with one additional well planned in December 2026. Of the nine wells, only the Kumli-50 horizontal well (“K-50”) has yet to be tied into the gas sales pipeline. During well cleanup operations, K-50 flowed at rates estimated up to 10 MMscf/d but has not yet flowed through well testing equipment due to produced drilling fluids, completion fluids and formation water that hinder its continuous flow. The well produces when the wellbore is lifted with nitrogen but the well cannot independently lift these fluids and has been shut in to monitor pressures while alternate methods to lift the fluids are evaluated for planned implementation in the fourth quarter of 2026 in conjunction with other well workover activities.

In October 2026, the Company conducted a pre-stimulation cleanup flow test on the Kumli-51 horizontal well (“K-51”), which is another well in the Kumli NW structure. Prior to stimulation, K-51 flowed at 11.6 MMscf/d (1,933 boe/d) during a 1.5-hour test through a 1-inch choke at a stabilized tubing pressure of 703 psi. The well produced drilling and completion fluids at 356 bopd with no condensate observed. K-51 was subsequently placed on production and is expected to undergo an acid stimulation in December 2026. The K-51 test rate is a short-term test rate and may not be indicative of long-term performance or ultimate recovery.

Installation of the Compressor Station remains a top priority for the Company, and an EPC contract was awarded in August 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 downstream pipeline pressures. Simulation work conducted by an independent third-party engineering company indicates compression could yield up to 30 MMscf/d of incremental gas production and extend end-of-field life. The Compressor Station is scheduled to be commissioned in the second quarter of 2027.

LNG in Kazakhstan

The Company’s LNG initiative in Kazakhstan fully supports the government of Kazakhstan’s strategic focus on creating energy security solutions that provide viable diesel fuel alternatives to ensure the country’s transport sector functions despite worldwide fuel and energy disruptions. The Company’s First LNG Facility for the Saryozek Site completed final pressure testing of the fully assembled unit and is expected to arrive in Kazakhstan in December 2026. Although the delivery schedule has slipped due to the delayed arrival and installation of the control system components, LNG production is expected to commence in the second quarter of 2027. The Company expects to produce, distribute, and sell LNG to offset industrial diesel usage in Kazakhstan and potential 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 of which are being utilized in other countries.

The First LNG Facility is designed with 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 is expected to be subsequently 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 reviewing third-party financing alternatives to complete the First LNG Facility, and the Company may enter 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 September 30, 2026, the Company has incurred CAD $10.5 million of costs for the First LNG Facility, and the estimated additional remaining costs for construction and commissioning are USD $21.0 million (CAD $29.8 million) including 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 is estimated to have an energy-equivalent volume of 1.5 million litres of diesel daily and could reduce CO2 emissions by 390,000 MT per year, which is estimated to be equivalent to removing 85,000 cars from the road annually. See “Forward-Looking Statements” in this news release for further discussion on the risks and uncertainties related to the natural gas allocations and the Company’s LNG initiatives.

$72.0 Million Financing of Convertible Debentures

In October 2026, the Company completed an offering of convertible debentures for aggregate gross proceeds of $72.03 million which are convertible into 12,005,481 common shares (the “2026 Debentures”) and comprised a brokered public offering for gross proceeds of $28.75 million including the full exercise of the over-allotment option by the agents (the “Public Offering”) and a concurrent non-brokered private placement for gross proceeds of $43.28 million (the “Private Placement”) on the same terms and conditions except the 2026 Debentures issued under the Private Placement are subject to a statutory four-month hold period expiring on February 16, 2027.

The 2026 Debentures are unsecured, have no associated financial covenants, bear interest at 12% per annum payable quarterly in cash and in arrears, and the principal amount is convertible at any time at the option of the holder on or before the maturity date of October 15, 2029, at a conversion price of $6.00 per common share. The 2026 Debentures issued under the Public Offering are traded on the Toronto Stock Exchange under the symbol CDR.DB and those issued under the Private Placement are expected to commence trading following the four-month hold period on or about February 16, 2027.

The estimated issuance costs associated with the 2026 Debentures of $3.3 million are comprised of agent commissions, intermediary fees, legal and advisory fees, and regulatory costs. The net proceeds from the 2026 Debentures offering of $68.7 million is intended to be used to fund the Compressor Station in Uzbekistan, the First LNG Facility in Kazakhstan, working capital and general corporate purposes.

Critical Minerals Licenses in Kazakhstan

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.

The Company has advanced an integrated geophysical program at Sayakbay. Historical gravity data was digitized, reprocessed, and incorporated into a three-dimensional density model, refining the interpretation of the Sayakbay Dome, adjacent structural depressions, and a major shear zone along the Moyunkum uplift. Unmanned Aerial Vehicle (“UAV”) magnetic surveys further defined the geometry of the Sayakbay Dome, faults intersecting the structure, and other structural features that may be relevant to mineralizing fluid migration and copper deposition.

The Company is currently processing and interpreting a ground transient electromagnetic (“TEM”) survey over the central portion of Sayakbay. The survey is designed to map prospective geoelectric horizons and structural features to depths of approximately 700 meters and to improve the identification and ranking of potential mineralized targets. Preliminary results have demonstrated good correlation with historical well resistivity data and have identified several geoelectric layers and lateral resistivity variations that may reflect changes in lithology, fluid saturation, or structure.

At Kolkuduk, the Company completed a UAV-borne magnetic survey during 2026. Interpretation of magnetic data, together with historical gravity, seismic, and geological information, further defined the anticlinal structure, faults, and prospective Taskuduk and Zhezkazgan formations. These formations are recognized hosts for sandstone-hosted copper mineralization within the Chu-Sarysu Basin.

The Company continues to evaluate the lithium-brine potential of both licenses. A prior well drilled within the Kolkuduk license territory for hydrocarbon exploration encountered and tested brine deposits with lithium concentrations of up to 130 milligrams per liter as reported by the Ministry of Geology of the Republic of Kazakhstan. A 1,000-meter column of tested and untested brine reservoirs 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 liter 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 reservoirs 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 2027 Sayakbay capital program is expected to be determined following completion and integration of the TEM results with the gravity, magnetic, and historical geological data. Depending on the results, the Company may densify the TEM survey grid over prospective areas and/or begin preparations for a core drilling program to test the highest-priority targets. If the Sayakbay TEM program demonstrates that the method is effective and produces promising results, the Company may undertake a similar TEM survey at Kolkuduk during 2027.

The initial development plan for Sayakbay includes conducting targeted geophysical surveys, coring programs and 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 2028 and the estimated costs for the initial development plan are USD $6.7 million (CAD $9.5 million). The initial development plan for the Kolkuduk license has not been determined.

SELECTED FINANCIAL INFORMATION

Non–Controlling Interest in the PEC Project

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 news release related to the PEC Project are 100% of the amounts attributable to the PEC Project, of which 51% are attributable to the Company.

Production in Uzbekistan

Total Production	Three months ended  September 30, 2026	Three months ended September 30, 2025	Change
Natural gas (Mcf)	8,964,316	5,397,457	3,566,859
Natural gas (boe)	1,494,053	899,576	594,477
Condensate (barrels)	41,706	18,401	23,305
Total (boe)	1,535,759	917,977	617,782
Daily Production
Natural gas (Mcf/d)	97,438	58,668	66%
Natural gas (boe/d)	16,240	9,778	66%
Condensate (bopd)	453	200	126%
Total (boe/d)	16,693	9,978	67%

Total Production	Nine months ended September 30, 2026	Nine months ended September 30, 2025	Change
Natural gas (Mcf)	22,510,050	16,702,386	5,807,664
Natural gas (boe)	3,751,675	2,783,731	967,944
Condensate (barrels)	109,376	73,987	35,389
Total (boe)	3,861,051	2,857,718	1,003,333
Daily Production
Natural gas (Mcf/d)	82,454	61,181	35%
Natural gas (boe/d)	13,742	10,197	35%
Condensate (bopd)	401	271	48%
Total (boe/d)	14,143	10,468	35%

Operating Netbacks in Uzbekistan

Operating Netback – Natural Gas 1,2	Natural Gas
	Three months ended September 30				Nine months ended September 30
	2026		2025		2026		2025
Sales ($000's)	29,961		17,623		74,191		55,480
Royalties ($000's)	(4,119)		(2,427)		(10,218)		(7,641)
Production costs ($000's)	(10,688)		(8,324)		(29,424)		(25,305)
Transportation and selling ($000's)	(1,047)		(634)		(2,545)		(1,948)
Operating netback ($000's)1,2	14,107		6,238		32,004		20,586
Sales volume (Mcf)	8,400,470		5,019,603		20,988,647		15,548,613
Sales ($/Mcf)	3.56		3.51		3.53		3.57
Royalties ($/Mcf)	(0.49)		(0.48)		(0.49)		(0.49)
Production costs ($/Mcf)	(1.27)		(1.66)		(1.40)		(1.63)
Transportation and selling ($/Mcf)	(0.12)		(0.13)		(0.12)		(0.13)
Operating netback ($/Mcf)1,2	1.68		1.24		1.52		1.32

Operating Netback – Condensate 1,2	Condensate
	Three months ended September 30				Nine months ended September 30
	2026		2025		2026		2025
Sales ($000's)	3,590		1,116		9,058		4,806
Royalties ($000's)	(520)		(161)		(1,311)		(693)
Production costs ($000's)	(209)		(124)		(606)		(510)
Transportation and selling ($000's)	(16)		(7)		(40)		(28)
Operating netback ($000's)1,2	2,845		824		7,101		3,575
Sales volume (bbl)	40,849		18,063		106,123		73,421
Sales ($/bbl)	87.88		61.78		85.35		65.46
Royalties ($/bbl)	(12.73)		(8.91)		(12.35)		(9.44)
Production costs ($/bbl)	(5.12)		(6.86)		(5.71)		(6.95)
Transportation and selling ($/bbl)	(0.39)		(0.39)		(0.38)		(0.38)
Operating netback ($/bbl)1,2	69.64		45.62		66.91		48.69

Operating netback reconciliation Uzbekistan segmented information For the three months ended September 30, 20261,2,3	Natural Gas		Condensate		Total
Sales ($000's)	29,961		3,590		33,551
Royalties ($000's)	(4,119)		(520)		(4,639)
Production costs ($000's)	(10,688)		(209)		(10,897)
Transportation and selling ($000's)	(1,047)		(16)		(1,063)
Operating netback ($000's)1	14,107		2,845		16,952
For the three months ended September 30, 20251,2,3
Sales ($000's)	17,623		1,116		18,739
Royalties ($000's)	(2,427)		(161)		(2,588)
Production costs ($000's)	(8,324)		(124)		(8,448)
Transportation and selling ($000's)	(634)		(7)		(641)
Operating netback ($000's)1	6,238		824		7,062

Operating netback reconciliation Uzbekistan segmented information For the nine months ended September 30, 2026 1,2,3	Natural Gas		Condensate		Total
Sales ($000's)	74,191		9,058		83,249
Royalties ($000's)	(10,218)		(1,311)		(11,529)
Production costs ($000's)	(29,424)		(606)		(30,030)
Transportation and selling ($000's)	(2,545)		(40)		(2,585)
Operating netback ($000's)1	32,004		7,101		39,105
For the nine months ended September 30, 2025 1,2,3
Sales ($000's)	55,480		4,806		60,286
Royalties ($000's)	(7,641)		(693)		(8,334)
Production costs ($000's)	(25,305)		(510)		(25,815)
Transportation and selling ($000's)	(1,948)		(28)		(1,976)
Operating netback ($000's)1	20,586		3,575		24,161

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 news release. 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.

NON-GAAP FINANCIAL MEASURES

The Company refers to “operating netback” in this news release, 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. 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.

BARRELS OF OIL EQUIVALENT ADVISORY

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.

FORWARD-LOOKING STATEMENTS

Certain statements in this news release constitute forward-looking information under applicable securities legislation. Such statements are generally identifiable by the terminology used, such as “anticipate”, “expect”, “plan”, “believe”, “intend”, “estimate”, “may”, “will”, “could”, “would”, “should”, “potential”, “prospective”, “pending”, “ongoing”, “future”, “forecast”, “target”, “continue”, “capable”, “schedule”, “remain” or other similar wording. Forward-looking information in this news release 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 realize sustainable growth for reserves, production, and cashflow; the timing and ability to build strong, near-term shareholder value; the timing and ability to conduct the planned multi-well drilling program in 2026 and 2027; the timing and ability of the identified drilling locations to be drilled and become producing wells; the timing and ability to complete, test and produce the new wells; the timing and ability to target previously undeveloped reservoirs and the timing and ability to generate sustained production growth; the timing and ability to produce commercially recoverable gas outside of conventionally targeted four-way structural closures; the timing and ability of new and stratigraphic play types to become part of the Company’s next growth engine; the timing and ability of A-22 test results to open significant areas of prospective drilling acreage at Andakli and derisk the commerciality of a stratigraphic horizontal well development program; the timing and ability to drill numerous Andakli follow up wells in 2027; the timing and ability to drill NS-14 and penetrate the deeper Jurassic clastic stacked reservoir sands; the timing and ability for NS-14 to reach the targeted depth of up to 3000 meters and the timing and ability to evaluate the full extent of the stratigraphic column; the timing and ability to drill follow up wells at North Syuzma; the timing and ability to perform an acid stimulation on K-51; the timing and ability to target separate carbonate reservoirs from a single surface location; the timing and ability to utilize proven technology to realize higher expected production rates; the timing and ability to realize increased reservoir contact, reduced well drilling and tie-in costs and a smaller environmental footprint; the timing and ability to implement alternate methods to lift fluids from K-50 and tie K-50 into the gas sales pipeline; the timing and ability to design, construct and commission the Compressor Station; the timing and ability of the Compressor Station to increase production and reduce back pressure; 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 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 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 construct the First LNG Facility at the Saryozek Site prior to August 2030 as required under the related land agreement; 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 planned use of proceeds from the 2026 Debentures offering including the Compressor Station, First LNG Facility, working capital and general corporate purposes; the potential for the Sayakbay and Kolkuduk license to contain commercial deposits; the timing and ability to integrate the aeromagnetic survey results with historical gravity data and regional geological information; the timing and ability of the Sayakbay sediment to be suitable for hosted copper mineralization; the timing and ability to advance an integrated geophysical program at Sayakbay and incorporated the data into a three-dimensional density model; the timing and ability to refine the interpretation of various license area features; the timing and ability of UAV magnetic surveys to further define the area geometries, faults, formations and other structural features; the timing and ability to complete, process and interpret the TEM survey; the timing and ability to map prospective geoelectric horizons and structural features and to improve the identification and ranking of potential mineralized targets; the timing and ability to correlate preliminary results with historical well resistivity data; the timing and ability to identify geoelectric layers and lateral resistivity variations; the timing and ability to determine and complete the 2027 Sayakbay capital program; the timing and ability to densify the TEM survey grid; the timing and ability to begin preparations and to conduct a core drilling program; the timing and ability to undertake a TEM survey at Kolkuduk during 2027; the timing and ability of the Company to fund, permit and complete planned activities at Sayakbay; 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 determine, fund, permit and execute an initial exploration or development plan for the Kolkuduk license; 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 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 news release 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 manage its working capital deficiency; the Company will be able to drill the planned wells and install and commission the Compressor Station; the Compressor Station will perform substantially in accordance with the simulation work conducted by an independent third-party engineering company; the results of the A-22 test and other recently drilled wells will be indicative of the results of future follow up wells; the Company will be able substantially complete the MDWP and comply with the terms of the PEC Project; 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 First LNG Facility will arrive in Kazakhstan and be commissioned in accordance with the Company’s current schedule; 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 support energy security solutions, including LNG development, that provide viable diesel fuel alternatives; the Company’s additional drilling and testing will be successful in verifying deliverability rates and confirming mineral concentrations; commodity prices, foreign currency exchange rates and interest rates will be consistent with the Company’s expectations; 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 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 news release is made as of the date of this news release 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 news release is expressly qualified by this cautionary statement.

ABBREVIATIONS
The following is a summary of abbreviations used in this news release:
Mcf  Mcf/d MMcf/d bbl bopd boe boe/d MT IFRS GAAP CAD USD LNG Türkiye Kazakhstan Uzbekistan 3-D EPC NE NW USGS	Thousands of standard cubic feet Thousands of standard cubic feet per day Millions of standard cubic feet per day Barrels of oil Barrels of oil per day Barrels of oil equivalent Barrels of oil equivalent per day Metric tonnes International Financial Reporting Standards Generally Accepted Accounting Principles Canadian Dollars United States Dollars Liquefied natural gas Republic of Türkiye Republic of Kazakhstan Republic of Uzbekistan Three dimensional Engineering, Procurement and Construction North-East North-West United States Geological Survey

The TSX does not accept responsibility for the adequacy or accuracy of this news release.

For further information, please contact Don Streu, President and CEO or Sandy Quilty, Vice President of Finance and CFO at 403-201-9694.