Condor Energies Inc. (“Condor”) (TSX:CDR), a Canadian based, internationally focused energy transition company working in Central Asia is pleased to announce it has started a multi-well drilling program in Uzbekistan.
The first well is being drilled vertically to approximately 3,000 meters to penetrate and evaluate the currently producing carbonate reservoir sections as well as multiple deeper, under-exploited stacked clastic reservoirs and basement rock formations. Drilling of the first well and a detailed evaluation program are expected to be completed in October 2025. Data from the first well will be used to optimize subsequent horizontal wells which are internally estimated to initially produce between 13 and 20 MMscf/day per well, cost USD 4.2 million to drill and complete and take forty to forty-five days to drill. Accounting for a drilling ‘learning curve’, the estimated cost of the upcoming 12 well horizontal program is, on average, USD $3.3 million per well to drill and complete. The first horizontal well has a planned 1,000 meter lateral section which could be extended in subsequent wells as reservoir parameters dictate. Given that horizontal well performance was not included in the Company’s 2024 reserves report prepared by independent reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”, see “Reserves Advisory” section below), material proved and proved plus probable reserves growth is possible once production history is obtained from the initial horizontal wells.
Condor continues to expand its well prospect inventory by interpreting and integrating 1,462 km2 of recently reprocessed 3D seismic data and 142 km2 of 3D seismic inversion attributes. These efforts have increased Condor’s portfolio to 18 targets that can be classified as either undrilled attic gas accumulations in producing structures or newly identified structures and could extend the drilling program beyond 2026. The Company is currently investigating the availability and timing to contract a second drilling rig to further accelerate overall gas production.
In Uzbekistan, a detailed engineering study is underway for the installation of field compression to mitigate increasing sales gas pipeline pressures. Field compression is expected to be installed in 2026, and internal estimates suggest base production could increase by 25 to 55 percent, although actual results may differ (see the “Forward-Looking Statements” advisory, below). The preliminary cost of compression could range between USD $12 million to USD $20 million based on various compression scenarios that will be further refined during detailed engineering and procurement activities.
Uzbekistan production for the third quarter of 2025 through September 7, 2025 has averaged 10,284 boepd, in line with the second quarter of 2025 which averaged 10,258 boepd. Near term production growth has been impacted by a combination of increased sales gas pipeline pressures and recent workovers that were more focused on modern data collection. However, production growth is expected to resume from the multi-well drilling program and the installation of field compression.
In Kazakhstan, fabrication of the Company’s first modular LNG facility is on schedule to be completed by the end of the fourth quarter of 2025 (the “First Facility”). The First Facility and supporting equipment will then be shipped to Saryozek, Kazakhstan for assembly and commissioning. Construction of LNG storage tanks and transport trailers has also commenced. LNG production from the First Facility remains on track to begin in the second quarter of 2026 at 48,000 gallons of LNG per day. The Company is finalizing LNG off-taker agreements and advancing several financing solutions for the First Facility.
Two additional liquefaction units are planned to be constructed at Saryozek shortly afterwards, increasing Saryozek LNG production to approximately 150,000 gallons per day for a total EPC cost of USD $70.4 million. As previously disclosed, planning for additional LNG facilities at Kuryk and Aktobe is ongoing.
Non-Controlling Interest in PEC Project
The Company operates under a production enhancement services contract 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”). In the Company’s financial statements, 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. Accordingly, the production volumes, planned wells to be drilled, estimated capital costs and other metrics 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.
RESERVES ADVISORY
This news release includes information pertaining to the Evaluation of Crude Oil and Natural Gas Reserves as of December 31, 2024 prepared by 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 McDaniel pricing effective as of December 31, 2024. Additional reserves information as required under NI 51-101 is included in the Company’s Annual Information Form (“AIF”) 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 on volumetric calculations, probabilistic methods and analogy to similar types of reserves, rather than actual production history. Estimates based on such methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based on 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 do 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.