Condor Announces 2025 Year-End Results
CALGARY, Alberta, March 19, 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 audited consolidated financial statements for the years ended December 31, 2025 and 2024 (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 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.
MESSAGE FROM CONDOR’S CEO
Don Streu, President and CEO of Condor commented: “It’s been a transformational year for Condor as indicated by the numerous performance accomplishments noted above. 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. The divestiture of our Turkish holdings is consistent with management’s focus on higher-return growth initiatives.
We’ve demonstrated the successful application of proven Western technologies in Uzbekistan, including drilling horizontal wells, and are continuing to create material value as confirmed by this month’s to-date average daily production rate, which has already increased by 20% from 2025’s average daily production rate. This increase is despite the reservoir’s natural decline rate of more than 20% per year. Not only has the team drilled Uzbekistan’s longest horizontal well, but we’re also realizing a continual reduction in cost and drilling days with each successive well. Our reprocessed 3-D seismic has already identified numerous undrilled structures with multiple infill, undrained attic closures that has generated a new drilling inventory of over 50 wells.
A major LNG milestone was also recently achieved by completing fabrication of the First LNG Facility, and we look forward to shipping it next quarter for assembly in Kazakhstan. Due diligence work is ongoing with multiple third-party finance groups to finalize definitive agreements for the First LNG Facility. Having already secured three LNG feed gas allocations, Condor is uniquely positioned to benefit as the LNG industry evolves in Kazakhstan. The recent surge in activity related to Kazakhstan’s critical minerals, including copper and lithium, also bodes well for potential growth in that market, especially given the strategic location of Condor’s two critical minerals licenses to neighboring China.
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 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.
LNG in Kazakhstan
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.
USD $5.0 Million LNG Bridge Loan Financing
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.
$13.65 Million Private Placement of Convertible Debentures
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.
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.
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.
Sale of Turkish Properties
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.
SELECTED FINANCIAL INFORMATION
As at, and for the years ended December 31
| ($000’s except for share amounts) | 2025 | 2024 | 2023 | ||||
| Natural gas and condensate sales | 80,690 | 66,626 | 643 | ||||
| Total revenue (sales less royalties) | 69,538 | 57,408 | 552 | ||||
| Net income (loss) | 1,232 | 3,493 | (11,392 | ) | |||
| Net loss attributable to common shareholders | (4,212 | ) | (4,072 | ) | (11,392 | ) | |
| Net loss per share (basic and diluted) | (0.06 | ) | (0.07 | ) | (0.20 | ) | |
| Total assets | 98,419 | 66,607 | 6,769 | ||||
| Non-current financial liabilities | 19,208 | 9,364 | 5,504 | ||||
RESULTS OF OPERATIONS
Reserves – Uzbekistan
The Company’s 2025 reserves in Uzbekistan were evaluated by independent reserves evaluator McDaniel & Associates Consultants Ltd. (see “Reserves Advisory”). 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 PEC Project” in this news release which describes these interests in reserves and future net revenue.
|
100% Property Interest as of December 31, 2025 |
Natural Gas (MMcf) |
Condensate (Mbbl) |
Boe Reserves (Mboe)* |
NPV 10 Before Tax (in USD 000’s) |
| Proved | 153,394 | 746 | 26,312 | 78,489 |
| Probable | 27,856 | 134 | 4,777 | 20,555 |
| Proved plus Probable | 181,250 | 880 | 31,089 | 99,044 |
|
51% Working Interest as of December 31, 2025 |
||||
| Proved | 78,231 | 381 | 13,419 | 40,029 |
| Probable | 14,206 | 68 | 2,436 | 10,483 |
| Proved plus Probable | 92,437 | 449 | 15,855 | 50,512 |
(* based on gas/boe conversion of 6 Mcf to 1 boe – see Reserves Advisory)
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 – Uzbekistan | ||||
|
Total Production |
Three months ended December 31, 2025 |
Three months ended December 31, 2024 |
Change Volume |
|
| Natural gas (Mcf) | 5,640,518 | 5,637,255 | 3,263 | |
| Natural gas (boe) | 940,086 | 939,542 | 544 | |
| Condensate (barrels) | 29,033 | 27,541 | 1,492 | |
| Total (boe) | 969,119 | 967,083 | 2,036 | |
|
Daily Production |
||||
| Natural gas (Mcf/d) | 61,310 | 61,274 | 0.1 | % |
| Natural gas (boe/d) | 10,218 | 10,212 | 0.1 | % |
| Condensate (bopd) | 316 | 299 | 5.7 | % |
| Total (boe/d) | 10,534 | 10,511 | 0.2 | % |
|
Total Production |
Year ended December 31, 2025 |
Ten months ended December 31, 2024* |
Change Volume |
|
| Natural gas (Mcf) | 22,342,904 | 18,431,933 | 3,910,971 | |
| Natural gas (boe) | 3,723,817 | 3,071,989 | 651,828 | |
| Condensate (barrels) | 103,020 | 77,386 | 25,634 | |
| Total (boe) | 3,826,837 | 3,149,375 | 677,462 | |
|
Daily Production |
||||
| Natural gas (Mcf/d) | 61,213 | 60,235 | 1.6 | % |
| Natural gas (boe/d) | 10,202 | 10,039 | 1.6 | % |
| Condensate (bopd) | 282 | 253 | 11.5 | % |
| Total (boe/d) | 10,484 | 10,292 | 1.9 | % |
* Production commenced on March 1, 2024. Total and daily production volumes are for ten months and 306 days, respectively.
Operating Netback – Uzbekistan
|
Operating Netback – Natural Gas1 |
Natural Gas | |||||||
|
Three months ended December 31 |
Year ended December 31 |
|||||||
| 2025 | 2024 | 2025 | 20243 | |||||
| Sales ($000's) | 18,731 | 18,731 | 74,211 | 60,135 | ||||
| Royalties ($000's) | (2,577 | ) | (2,580 | ) | (10,218 | ) | (8,286 | ) |
| Production costs ($000's) | (8,576 | ) | (7,988 | ) | (33,881 | ) | (25,064 | ) |
| Transportation and selling ($000's) | (651 | ) | (657 | ) | (2,599 | ) | (2,129 | ) |
| Operating netback ($000's)1 | 6,927 | 7,506 | 27,513 | 24,656 | ||||
| Sales volume (Mcf) | 5,269,061 | 5,255,725 | 20,817,673 | 17,149,079 | ||||
| Sales ($/Mcf) | 3.55 | 3.56 | 3.56 | 3.50 | ||||
| Royalties ($/Mcf) | (0.49 | ) | (0.49 | ) | (0.49 | ) | (0.48 | ) |
| Production costs ($/Mcf) | (1.63 | ) | (1.52 | ) | (1.63 | ) | (1.46 | ) |
| Transportation and selling ($/Mcf) | (0.12 | ) | (0.12 | ) | (0.12 | ) | (0.12 | ) |
| Operating netback ($/Mcf)1 | 1.31 | 1.43 | 1.32 | 1.44 | ||||
|
Operating Netback – Condensate1 |
Condensate | |||||||
|
Three months ended December 31 |
Year ended December 31 |
|||||||
| 2025 | 2024 | 2025 | 20243 | |||||
| Sales ($000's) | 1,645 | 2,199 | 6,451 | 6,097 | ||||
| Royalties ($000's) | (237 | ) | (317 | ) | (930 | ) | (879 | ) |
| Production costs ($000's) | (193 | ) | (184 | ) | (703 | ) | (508 | ) |
| Transportation and selling ($000's) | (11 | ) | (10 | ) | (39 | ) | (29 | ) |
| Operating netback ($000's)1 | 1,204 | 1,688 | 4,779 | 4,681 | ||||
| Sales volume (bbl) | 28,609 | 26,823 | 102,030 | 76,544 | ||||
| Sales ($/bbl) | 57.50 | 81.98 | 63.22 | 79.65 | ||||
| Royalties ($/bbl) | (8.29 | ) | (11.82 | ) | (9.11 | ) | (11.48 | ) |
| Production costs ($/bbl) | (6.75 | ) | (6.86 | ) | (6.89 | ) | (6.64 | ) |
| Transportation and selling ($/bbl) | (0.38 | ) | (0.37 | ) | (0.38 | ) | (0.38 | ) |
| Operating netback ($/bbl)1 | 42.08 | 62.93 | 46.84 | 61.15 | ||||
|
Operating netback reconciliation Uzbekistan segmented information For the year ended December 31, 20251,2 |
Natural Gas | Condensate | Total | |||
| Sales ($000's) | 74,211 | 6,451 | 80,662 | |||
| Royalties ($000's) | (10,218 | ) | (930 | ) | (11,148 | ) |
| Production costs ($000's) | (33,881 | ) | (703 | ) | (34,584 | ) |
| Transportation and selling ($000's) | (2,599 | ) | (39 | ) | (2,638 | ) |
| Operating netback ($000's)1 | 27,513 | 4,779 | 32,292 | |||
|
Operating netback reconciliation Uzbekistan segmented information For the year ended December 31, 20241,2,3 |
||||||
| Sales ($000's) | 60,135 | 6,097 | 66,232 | |||
| Royalties ($000's) | (8,286 | ) | (879 | ) | (9,165 | ) |
| Production costs ($000's) | (25,064 | ) | (508 | ) | (25,572 | ) |
| Transportation and selling ($000's) | (2,129 | ) | (29 | ) | (2,158 | ) |
| Operating netback ($000's)1 | 24,656 | 4,681 | 29,337 |
| 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 | Reconciliation to the respective Financial Statement amount for each netback component for the Uzbekistan segment. | |
| 3 | Production commenced on March 1, 2024. Production volumes, sales and expenses for the year ended December 31, 2024 are for ten months (306 days). | |
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.
RESERVES ADVISORY
This news release 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: 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.
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 “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 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 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 to reduce drilling days and costs; 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 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 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 the SEDAR+ website (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 are 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:
| 3-D | Three dimensional | |
| Mcf | Thousands of standard cubic feet | |
| Mcf/d | Thousands 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 | |
| CAD | Canadian Dollars | |
| USD | United States Dollars | |
| LNG | Liquefied natural gas | |
| Türkiye | Republic of Türkiye | |
| Kazakhstan | Republic of Kazakhstan | |
| Uzbekistan | Republic of Uzbekistan | |
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.
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