Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Business Overview
The following discussion is designed to provide information that we believe necessary for an understanding of our financial condition, changes in our financial condition and results of our operations. The following discussion and analysis should be read in conjunction with the accompanying audited consolidated financial statements and related notes. The financial statements have been prepared in accordance with US GAAP.
Industry and Market Update
Rising electricity demand from data centers, decarbonization goals, apparent changes in public attitudes, and changes in government policies aimed at addressing energy supply and security concerns are contributing to the expansion of the nuclear industry in the U.S. and abroad.
The International Energy Agency reports that nuclear generation reached a record level in 2025 and that its growth rate will more than double from 2026 through 2030 compared with 2021 to 2025. The most recent projections of the International Atomic Energy Agency are that global nuclear capacity could more than double by 2050, and the World Nuclear Association (“WNA”) has called for nuclear power generation to triple by 2050.
Efforts to increase the availability of nuclear power to help satisfy the increasing demand for electricity have been driven in part by the emergence of artificial intelligence (“AI”) and the expansion of the data center industry. The U.S. Department of Energy (“DOE”) has reported that the data center industry consumed approximately 4.4% of U.S. electricity in 2023, and projects that its share of consumption will grow to 7 to 12% by 2028. Amazon, Google, Meta, Microsoft, Switch, and others have partnered with nuclear reactor developers and utilities to support their planned expansions. This trend continued in January 2026, when Meta signed additional agreements with Vistra Corp. and advanced reactor developers, Oklo Inc. and TerraPower, for significant power offtake to support Meta’s AI expansion.
Many nations continue to maintain commitments to reducing carbon emissions and recognize that nuclear energy can provide continuous, low-carbon electricity. Following a declaration at the Congress of Parties (“COP”) 28 in 2023, which was expanded at COP29 in 2024 and COP30 in 2025, more than 30 nations have committed to tripling nuclear power capacity by 2050. In the U.S., major AI and data center companies have recognized climate and sustainability objectives as part of their rationale for working with the nuclear industry. Public attitudes also appear to be changing. In April 2025, Gallup reported that the Americans polled who support nuclear energy rose to 61%, a 6% increase since Gallup’s last measurement in 2023.
In the U.S., changes in government policies, including energy security initiatives, domestic fuel cycle incentives, and reactor deployment programs, are providing greater support to the nuclear industry.
In reaction to the Russian invasion of Ukraine in 2022, the U.S. in May 2024 enacted the Prohibiting Russian Uranium Imports Act (“PRUIA”), which bans imports of Russian uranium products through 2040. Waivers may be granted under PRUIA by the DOE only if there is no viable alternative supply to sustain nuclear reactors or the imports are in the national interest.
In May 2025, President Trump signed four Executive Orders (“EOs”): EO 14299 – Deploying Advanced Nuclear Reactor Technologies for National Security; EO 14300 – Ordering the Reform of the Nuclear Regulatory Commission; EO 14301 – Reforming Nuclear Reactor Testing at the Department of Energy; and EO 14302 – Reinvigorating the Nuclear Industrial Base. Collectively, these orders are aimed at accelerating U.S. nuclear technology development and deployment, reforming related regulations, strengthening the fuel cycle industrial base, and supporting nuclear contributions to national security.
The U.S. government has taken actions recently aimed at strengthening the commercial nuclear industry and domestic fuel cycle capabilities. The DOE’s fiscal year 2026 budget includes approximately $3.1 billion for the Office of Nuclear Energy to support advanced reactor development and deployment. In addition, DOE announced $2.7 billion in contract awards to three enrichment suppliers to support the deployment of near-term domestic enrichment capacity. DOE has also initiated a competitive process for states to host Nuclear Lifecycle Innovation Campuses intended to advance fuel cycle capabilities, including enrichment, fuel fabrication, used fuel recycling, and potential reactor deployments. In October 2025, the U.S. Department of Commerce entered into a strategic
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partnership with Westinghouse Electric Company and its owners to help facilitate financing and permitting for a potential multi-reactor build program in the U.S. with an estimated value up to $80 billion.
The U.S. government has also taken some actions aimed at supporting the U.S. uranium mining industry, although those actions have been more modest. The U.S. Geological Survey officially added uranium to the national List of Critical Minerals in 2025. EO 14241, signed by President Trump in March 2025, directs federal agencies to facilitate domestic mineral production, including uranium, to the greatest extent possible. In response, the U.S. Department of the Interior has begun fast-tracking uranium projects.
Policy support for nuclear energy and restrictions on Russian uranium imports in the U.S. and certain other markets have contributed to tighter uranium and enrichment market conditions. Utilities have increasingly sought medium- and long-term fuel supply agreements to diversify supply sources. In the future, additional reactor deployments are expected to increase uranium demand. In its September 2025 report, the WNA projected that global uranium requirements could increase by approximately one-third to about 86,000 metric tonnes by 2030 and to approximately 150,000 metric tonnes by 2040. The report further indicates that, absent increased investment, additional exploration, new mine development, and efficient permitting, projected demand may exceed anticipated primary supply over time.
2025 Developments
Lost Creek Property – Great Divide Basin, Wyoming
Status of Lost Creek
Since commencement of operations at Lost Creek in 2013 through December 31, 2025, we have captured nearly 3.5 million pounds U 3 O 8 , which includes 370,893 pounds U 3 O 8 captured in 2025.
As operations continued to ramp up at Lost Creek in 2025, we brought four additional header houses online in MU2. The average production solution head grade in 2025 Q4 was 46.4 mg/L. We captured approximately 78,177 pounds U 3 O 8 in 2025 Q4, and a total of 370,893 pounds U 3 O 8 in 2025. Production was slowed in December because of a loss of power at the site, following a regional storm with winds estimated at over 100 mph. The storm damaged approximately 30 power poles on the main line which provides power to Lost Creek. In coordination with the power company, the power interruption was addressed as quickly as possible and Lost Creek was back online in a matter of days.
Notwithstanding the power outage in December, we drummed 121,818 pounds U 3 O 8 in 2025 Q4 and a total of 410,440 pounds U 3 O 8 in 2025. Pounds drummed increased from 249,209 pounds in 2024 to 410,440 pounds U 3 O 8 in 2025. Pounds U 3 O 8 shipped in 2025 totaled 420,144, of which 138,337 pounds U 3 O 8 were shipped in 2025 Q4.
Lost Creek Operations
In 2025, wellfield delineation and development continued in MU2, MU1 Phase 2, and MUs 4 and 5. All remaining planned header houses in MU2 came online in 2025. During 2026 H1, we anticipate bringing several header houses online in MU1 Phase 2 as we continue to progress toward full plant capacity production. The first of those header houses was brought online in February 2026.
Commissioning new production areas, including the recovery of U 3 O 8 in MU2, and the restart of plant operations, not unexpectedly, have come with unique start-up issues. As the plant has been recommissioned, we have encountered equipment and process issues which we continue to optimize. Complete optimization of the plant will facilitate increasing our flow rates from the wellfield into the plant. Additionally, the planned construction of a water treatment facility at Lost Creek during 2026 is anticipated to allow for sustained increased flow rates.
At year end, we were generally fully staffed at Lost Creek. Retention and training remain a primary focus to complete stabilization and optimization of our operations at the site. As our growing core staff have more time on the job, including specifically our operations staff in the wellfield and plant, we anticipate continued steady improvement in production activities.
Our drill contractors currently have 15 drill rigs at Lost Creek, which is anticipated to be sufficient for Lost Creek drill programs in 2026. Drilling and wellfield construction and development are on schedule for our production plans.
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In 2025, we mobilized rigs from Lost Creek to Shirley Basin and to support our Great Divide Basin exploration program. The two drill rigs working at our North Hadsell Project in early 2026 will return to the Lost Creek Property when the North Hadsell work is complete to continue exploration at the LC South Project and support Lost Creek as necessary.
Lost Creek Regulatory Proceedings
The first two mine units at Lost Creek have all permits necessary for commercial level operations. We have received Wyoming Uranium Recovery Program (“URP”) approval of the amendment to the Lost Creek source material license to include recovery from the LC East Project (HJ and KM horizons) immediately adjacent to the Lost Creek Project and additional HJ horizons at the Lost Creek Project. This license amendment approved access to six planned mine units in addition to the already licensed three mine units at Lost Creek. The approval also increased the license limit for annual plant production to 2.2 million pounds U 3 O 8 which includes wellfield production of up to 1.2 million pounds U 3 O 8 and confirmed toll processing up to one million pounds U 3 O 8 .
During 2025, the Wyoming Department of Environmental Quality (“WDEQ”), Land Quality Division (“LQD) approved the LC East and KM horizon amendment, which adds HJ and KM geological horizons within the area that is immediately adjacent to the existing permit and provides for an additional mine unit in the HJ geological horizon for the existing permitted area. This final approval followed Water Quality Division (“WQD”) and EPA issuance of the required aquifer exemption for the expanded area.
2025 Purchases and Sales of U 3 O 8 and Sales Projections for 2026
As projected, during 2025, we sold 440,000 pounds U 3 O 8 of which 165,000 pounds U 3 O 8 were sold in 2025 Q4. We received sales proceeds of $27.2 million for the 440,000 pounds U 3 O 8 sold to our customers.
To maintain a strong product inventory, we purchased 100,000 pounds U 3 O 8 in 2025 Q4 at an average cost of $82.25. As previously disclosed, we used our 2024 inventory loan facility to borrow 250,000 pounds U 3 O 8 in December 2024. This facility was extended in 2025 Q4 for one year, and we entered into an additional inventory loan facility in October 2025, under which we may borrow up to 150,000 pounds U 3 O 8 .
Our sales in 2026 are currently projected to be 1,300,000 pounds U 3 O 8 into our existing sales agreements in addition to the planned return of 250,000 pounds U 3 O 8 to the lender under our inventory loan facility.
Sales Agreements
We currently have multi-year sales agreements with eight global nuclear energy companies. We completed two additional agreements in 2025 that provide for combined delivery commitments of 200,000 pounds U 3 O 8 in 2028 and 2029 and 100,000 pounds U 3 O 8 in 2030.
Several of our sales agreements are a combination of escalated fixed price and market-related pricing, subject to a floor and ceiling, while others are escalated fixed pricing. Also, several of the agreements include provisions by which the purchaser may flex the delivery amount (up or down) as much as 10% in a delivery year and others provide options to add sales quantities in additional delivery years.
We have sales agreements with various global nuclear purchasers which provide for deliveries between 2026 and 2033 as follows:
Base Quantity
Year
(U 3 O 8 Pounds)
The 2026 base quantity was adjusted to recognize that certain customers elected to flex up their 2026 deliveries.
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Shirley Basin Project
During 2025, we continued to advance wellfield drilling and development at our Shirley Basin project in Carbon County, Wyoming, and, in August 2025, initiated construction of the Shirley Basin plant facility. By 2025 Q4, the foundation was installed, and construction of the metal building commenced. While we have now significantly advanced construction on the plant building, installed all IX columns, and set many tanks, we anticipate that construction activities inside the plant will continue in 2026 to complete the production phase of the facility and, subsequently, the installation of phase two operations which includes wastewater disposal. Commissioning of all site operations, followed by ramp up is expected to continue throughout 2026.
Drilling and installation of wells is complete in HH 1-1 while construction continues; the building is set and piping has been run to all wells. The wellfield data package for Mine Unit 1 is under review by the WDEQ. HH 1-1 is ready to be brought online when all approvals are received by regulators. HH 1-2 development is nearly complete and construction initiated. Well installation continues at various stages for HHs 1-3 through 1-5. We anticipate that production and recovery from the wellfield will advance as we commission operations in the wellfield and plant throughout 2026.
Drilling and wellfield development is progressing well, following mobilization of rigs to the site in 2025 Q2. Recently, we have increased our Shirley Basin drill rig count to eight. Through February 2026, we have pilot drilled 469 injection and production wells in the first mine unit. Delineation and exploration drilling were completed historically, allowing for focused construction and development of MU1 at Shirley Basin.
Following aquifer testing in 2024-2025, we are now planning for higher flow from the wellfield, although it is anticipated that flow rates will vary throughout the project. The higher flow rates are within the range of 70-80 gpm, which is consistent with the high historical inflow of water into the underground workings at Shirley Basin in the early 1960s that drove innovation toward in situ mining at the project. Before again changing course on recovery operations, 1.5 million pounds U 3 O 8 were recovered historically through in-situ technology.
The modular main office complex was delivered and installed in August 2025, and all electrical, IT and plumbing work was efficiently completed for occupancy. Our professional and management staff are now working from the ~10,000 sq. ft. office complex. We have completed significant additional Shirley Basin construction and development during the 2024-2025 program to prepare for operations: the first two evaporation ponds are installed with piping being completed; the existing road was upgraded to an all-weather surface; all monitor wells for the first mine unit are installed; power between the historical substation and the site for the satellite plant is installed; communications and security systems are installed; and the septic system for the satellite plant enclosure is installed. Additionally, we completed the refurbishment of the existing warehouse, construction bay and maintenance bay, including installation and furnishing of
modular offices for these buildings. A new drilling support building was constructed and is being completed in 2026 Q1.
With few exceptions, we have been fully staffed at Shirley Basin since October 2025, and training of all staff is ongoing. Our phased recruitment plan was implemented throughout 2025 to allow time for task and safety training as well as cross training. We have been able to train Shirley Basin operations staff at Lost Creek to facilitate a stronger early understanding of our wellfield and plant operations.
All major pre-operational permits and licenses to advance the project have been received. Authorization to commence recovery operations is awaiting final regulatory verification of construction and approval of baseline water quality. The URP began its pre-operational inspection in late February 2026. We expect the URP to conduct additional site visits to conclude the pre-operational inspection. After these inspections and reviews are completed, we expect approval for recovery from the wellfield and collection of uranium onto resin in the plant.
The project has a licensed wellfield capacity of one million pounds U 3 O 8 per year. The Company plans three relatively shallow mining units at the project, where we plan to construct a satellite plant, from which loaded resin will be sent to Lost Creek for processing, drying and drumming. An additional inspection by the URP will be conducted when all production circuits are complete and Shirley Basin is prepared to transport resin to Lost Creek for processing and drying.
The annual production of U 3 O 8 from wellfield production and toll processing of loaded resin or yellowcake slurry will not exceed two million pounds equivalent of dried U 3 O 8 .
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Casper Construction and Operations Facilities
Throughout 2025, our Casper construction shop ramped up its work to progress from supplying header houses solely to Lost Creek to advancing timely deliveries of header houses to both our production sites. The construction team delivered three header houses to Lost Creek in 2025, and an additional three houses will be delivered to Lost Creek during 2026 Q1. The first two header houses have been delivered to Shirley Basin, with three additional houses to be delivered to Shirley Basin in 2026 Q1. All header houses are fabricated and built in Casper, allowing for efficiency and cost savings, as well as greater safety, due to minimized travel requirements.
Our Casper chemistry lab continues to support mine unit analysis at both Lost Creek and Shirley Basin through uranium analysis, product quality testing, and water sampling analysis. The lab staff also support ongoing research and development programs.
Exploration Programs
Lost Soldier Project
In 2025, we renewed exploration activities in the Great Divide Basin (“GDB”) Wyoming. Work began at our Lost Soldier Project northeast of Lost Creek in 2025 Q3. The program at Lost Soldier included the installation of a series of aquifer test wells to facilitate a better understanding of the local hydrogeology. While the geology of the project is largely understood with the benefit of data from approximately 4,000 historical drill holes, additional hydrogeologic data and characterization will enable our professional staff to better plan for potential permitting and development of the site. We will commence aquifer testing in 2026 Q1 and plan to initiate baseline environmental studies in 2026 in anticipation of possible permitting to advance the project. Located approximately 17 road miles to the Lost Creek plant, Lost Soldier has the potential to be developed as a satellite operation.
North Hadsell and LC South Projects
As work concluded at Lost Soldier in 2025, the drill rigs and related teams began exploration drilling at our North Hadsell Project, also in the GDB north of Lost Creek, for a planned 50-drill hole program. Through February 2026, we have drilled 32 wide-spaced framework holes, each approximately 1,000 feet deep, for a total of 32,965 feet. Seven of these initial drill holes have returned significant mineralization, indicating the presence of a stacked roll-front system containing 13 individual intercepts exceeding 0.20 GT (Grade (%eU3O8) times Thickness (ft)). These grades and thicknesses closely resemble the mineralization at Lost Creek, where the Company applies a 0.20 GT cut-off in evaluating economic mineral resources. Preliminary interpretation suggests the potential for up to eight individual roll fronts within a depth range of approximately 300 to 800 feet below surface, ideal for ISR mining, with indications of additional mineralized horizons at depth.
Drilling will continue until March 15, when seasonal sage grouse restrictions begin. Remaining work should resume in the summer. Thereafter, we will move to our third exploration program in the GDB at our LC South Project, where we anticipate a 120-drill hole program will commence in summer 2026.
Corporate Developments
Convertible Debt Financing
In December 2025, the Company closed an offering of $120 million aggregate principal amount of 4.75% Convertible Senior Notes due 2031 (the “Convertible Notes”) in a private placement, which included the exercise in full by the initial purchasers of their option to purchase an additional $20 million of Convertible Notes.
The cash interest coupon of 4.75% per annum is payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2026. The conversion price is approximately $1.73 per common share, which represents a conversion premium of approximately 27.5% to the last reported sale price of the common shares on the NYSE American on December 10, 2025, subject to adjustments in some events but will not be adjusted for any accrued and unpaid interest. The potential economic dilution upon conversions of the notes was mitigated through the purchase of cash-settled capped call options with a cap price of $2.72 (representing a premium of 100% over the last reported sale price of the common shares on the NYSE American on December 10, 2025). The purchase price for the capped call options was approximately $16.6 million. Conversions may be settled in common shares, cash or a combination of common shares and cash at the Company’s election. Additionally, we will have the right to redeem the Convertible Notes in certain circumstances and will be required to offer to repurchase the notes upon the occurrence of certain events. The Convertible Notes will mature on January 15, 2031 unless earlier converted, redeemed or repurchased.
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Senior Management and Changes in Board Composition
Effective December 13, 2025, Matthew D. Gili, the Company’s President, was appointed to succeed John W. Cash as Chief Executive Officer and President, following Mr. Cash’s retirement on December 12, 2025. Mr. Gili also joined the Board of Directors on December 13, 2025. Mr. Cash continues to serve as Chairman of the Board of Directors and is working closely with our management team as a strategic advisor to support a seamless leadership transition and ongoing Company growth.
Mr. Gili is a Professional Engineer with deep C-suite experience having served as a Chief Executive Officer, Chief Operating Officer, Chief Technical Officer and Executive General Manager. Mr. Gili has served in executive roles with publicly traded mining companies, including as President and Chief Operating Officer of i-80 Gold Corporation (2021-2025) and, prior to that, as Chief Executive Officer with Nevada Copper Corporation (2018-2020). Mr. Gili became President of Ur-Energy in June 2025.
In September 2025, the Company announced the expansion of its accounting and finance team with the appointment of Jade Walle as Vice President Finance. Mr. Walle brings broad experience in corporate finance, capital markets, and financial reporting within the mining and energy sectors. Mr. Walle most recently served as an audit partner with PricewaterhouseCoopers LLP (PwC) from 2011 to 2024. He began his career with PwC in 1996 and advised publicly traded energy and mining companies across PwC’s offices in Tulsa, London, Houston, and Denver.
Mr. Walle’s technical accounting and capital markets experience includes serving in PwC’s Global Capital Markets Group in London from 1999 to 2002, where he assisted non-U.S. companies with U.S. market transactions and SEC reporting. He also held leadership roles, including oversight of a division of PwC’s center of excellence and its India acceleration center, which provided outsourced services to approximately 75 U.S. audit clients. Mr. Walle is a CPA, licensed in Oklahoma, Texas, and Colorado.
Subsequent to year end, Alex Ritchie was appointed General Counsel and Corporate Secretary of the Company, to succeed the retiring Penne Goplerud. Ms. Goplerud remains with the Company in a transition period. Mr. Ritchie has more than 25 years of diverse legal, executive and business experience. He was in private practice from 1999-2009, including nine years at a prominent Denver law firm, where he represented mining and energy clients on billions of dollars of transactions.
From 2009 to 2012, Mr. Ritchie served as senior corporate counsel for the U.S. subsidiary of an international oil and gas company, where he worked on environmental, major project, acquisition and divestiture, contract, and corporate matters. Before law school, he was a public accountant for three years at KPMG. Mr. Ritchie has been a thought leader and educator on natural resources law. From 2017 until joining Ur-Energy in January 2026, he was the Executive Director of The Foundation for Natural Resources and Energy Law (formerly the Rocky Mountain Mineral Law Foundation). From 2012 – 2017, he was an associate professor of law at the University of New Mexico School of Law where he taught natural resources, property and business law. Mr. Ritchie obtained his J.D. from the University of Virginia School of Law and his B.S.B.A in accounting from Georgetown University.
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Results of Operations
Reconciliation of Non-GAAP measures with US GAAP financial statement presentation
The following tables include measures specific to U 3 O 8 product sales, product costs, product profits, pounds sold, price per pound sold, cost per pound sold, and product profit (loss) per pound sold. These measures do not have standardized meanings within US GAAP or a defined basis of calculation. These measures are used by management to assess business performance and determine production and pricing strategies. They may also be used by certain investors to evaluate performance. The following two tables provide a reconciliation of U 3 O 8 price per pound sold and U 3 O 8 cost per pound sold to the consolidated financial statements.
U 3 O 8 Price per Pound Sold Calculation
Unit
Sales per financial statements
Disposal fees
U 3 O 8 sales
U 3 O 8 pounds sold
U 3 O 8 price per pound sold
Sales per the consolidated financial statements includes U 3 O 8 sales and disposal fees. Disposal fees received at Pathfinder’s Shirley Basin facility do not relate to the sale of U 3 O 8 and are excluded from the U 3 O 8 sales and U 3 O 8 price per pound sold measures.
U 3 O 8 Cost per Pound Sold Calculation
Unit
Cost of sales per financial statements
Lower of cost or NRV adjustment
U 3 O 8 product costs
U 3 O 8 pounds sold
U 3 O 8 cost per pound sold
Cost of sales per the consolidated financial statements includes U 3 O 8 costs of sales and lower of cost or net realizable value (“NRV”) adjustments. U 3 O 8 cost of sales includes ad valorem and severance taxes related to the extraction of uranium, all costs of wellfield operations, plant operations, site administration, and product distribution costs, including the related depreciation and amortization of capitalized assets, asset retirement costs, and mineral property costs. These costs are also used to value inventory. The resulting inventoried cost per pound is compared to the NRV of the product, which is based on the estimated sales price of the product, net of any necessary costs to finish the product. Any inventory value in excess of the NRV is charged to cost of sales in the consolidated financial statements. NRV adjustments, if any, relate to U 3 O 8 inventories and do not relate to the sale of U 3 O 8 , and are excluded from the U 3 O 8 cost of sales and U 3 O 8 cost per pound sold measures.
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U 3 O 8 Product Sales
The following table provides information on our U 3 O 8 product sales.
U 3 O 8 Product Sales
Unit
U 3 O 8 Product Sales
Produced
Non-produced
U 3 O 8 Pounds Sold
Produced
Non-produced
U 3 O 8 Price per Pounds Sold
Produced
Non-produced
In 2024, we delivered 570,000 pounds into term contracts at an average price per pound sold of $58.15.
In 2025, we delivered 440,000 pounds into term contracts at an average price per pound sold of $61.77. The lower U 3 O 8 pounds sold in 2025 was the result of deferring a 300,000-pound term contract sale to 2026. The higher 2025 price per pound sold resulted from normal escalation factors in the existing term contracts.
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U 3 O 8 Product Costs
The following table provides information on our U 3 O 8 product costs.
U 3 O 8 Product Costs
Unit
U 3 O 8 Product Costs
Ad valorem and severance taxes
Cash costs
Non-cash costs
Produced
Non-produced
U 3 O 8 Pounds Sold
Produced
Non-produced
U 3 O 8 Cost per Pound Sold
Ad valorem and severance taxes
Cash costs
Non-cash costs
Produced
Non-produced
In 2024, we delivered 570,000 pounds into term contracts at an average U 3 O 8 cost per pound sold of $64.34. In 2025, we delivered 440,000 pounds into term contracts at an average U 3 O 8 cost per pound sold of $55.52.
Our 2024 sales consisted of 270,000 produced pounds and 300,000 non-produced pounds. The produced pounds were captured and drummed during the initial ramp up period at a higher average cost per pound when the mine operated at lower production levels. During 2024, we purchased 300,000 pounds and borrowed 250,000 pounds at an average cost of $75.87 per pound to meet 2024 delivery requirements and to establish a base inventory position for 2025. We delivered 300,000 of the 550,000 non-produced pounds into a term contract in 2024, leaving 250,000 non-produced pounds in ending inventory available for 2025 delivery requirements.
Our 2025 sales consisted of 330,000 produced pounds and 110,000 non-produced pounds. Production increased during 2025 leading to lower cash and non-cash costs per pound sold. Ad valorem and severance tax rates increased in 2025. In addition, the taxes are based on the sales value of the product sold, which increased in 2025. Driven by higher taxes, the produced cost per pound sold increased slightly in 2025 as compared to 2024.
The non-produced pounds acquired in 2024 were adjusted down to their NRV, which was the average spot price of $64.23 per pound, in 2025 Q1. We sold 110,000 of the non-produced pounds in 2025 Q3 at the reduced NRV.
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U 3 O 8 Product Profit and Loss
The following table provides information on our U 3 O 8 product profit and loss.
U 3 O 8 Product Profit (Loss)
Unit
U 3 O 8 Product Sales
Produced
Non-produced
U 3 O 8 Product Costs
Produced
Non-produced
U 3 O 8 Product Profit (Loss)
Produced
Non-produced
U 3 O 8 Pounds Sold
Produced
Non-produced
U 3 O 8 Price per Pound Sold
Produced
Non-produced
U 3 O 8 Cost per Pound Sold
Ad valorem and severance taxes
Cash costs
Non-cash costs
Produced
Non-produced
U 3 O 8 Profit (Loss) per Pound Sold
Cash costs
Less ad valorem and severance taxes
Less non-cash costs
Produced
Non-produced
U 3 O 8 Profit (Loss) Margin
Cash costs
Less ad valorem and severance taxes
Less non-cash costs
Produced
Non-produced
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In 2024, sales of produced pounds generated a profit of $10.12 per pound sold and an average profit margin of about 16%. The combined 2024 average price per pound sold was $58.15 and the average cost per pound sold was $64.34, which resulted in an average loss per pound sold of $6.19 and an average loss margin of about 11%. The loss was driven by the sale of non-produced pounds, which were purchased and borrowed at an average cost of $75.87 per pound. The non-produced pounds were delivered into a sales contract that was executed in 2022 when the long-term price was between $43 and $52 per pound.
In 2025, normal term contract escalation factors led to a $1.55 per pound increase in the average price per produced pound sold in 2025. As noted above, the cost per produced pound sold increased slightly in 2025, driven by higher ad valorem and severance taxes. As a result, sales of produced pounds generated a profit of $10.58 per pound sold and an average profit margin of about 17%, up slightly from 2024.
The average price per non-produced pound sold also increased in 2025, again driven by normal term contract escalation factors. As noted above, the cost per non-produced pound sold decreased in 2025 due to an adjustment down to their NRV in 2025 Q1. The resulting loss per non-produced pound sold decreased as compared to 2024.
The produced and non-produced pounds were primarily delivered into sales contracts that were executed in 2022 when the long-term price was between $43 and $52 per pound.
The combined 2025 average price per pound sold was $61.77 and the average cost per pound sold was $55.52, which resulted in an average profit per pound sold of $6.25 and an average profit margin of about 10%, up from a loss per pound sold of $6.19, or about 11%, in 2024.
U 3 O 8 Production and Ending Inventory
The following table provides information on our production of U 3 O 8 pounds.
U 3 O 8 Production
Unit
Pounds captured
Pounds drummed in
Pounds shipped
Non-produced pounds acquired
Wellfield production at Lost Creek continued to improve in 2025, with pounds captured increasing by 105,147 pounds, or 40%, during the year. The wellfield continued to add additional header houses in 2025, with average flow rates increasing by 890 gallons per minute, or 69%. Efforts in 2026 will continue to focus on increasing flow rates into the plant.
Plant production at Lost Creek also continued to improve in 2025, with pounds drummed increasing by 161,231 pounds, or 65%, during the year. During 2025, we began to receive assay reports from the conversion facility dating back to shipments made in 2024 through 2025 Q1. The results of the assays were positive, indicating that we drummed 9,778 more pounds in 2024 and 6,611 more pounds in 2025 Q1 than we initially estimated. The plant will continue to focus on daily drumming to allow us to capture more pounds within the plant in 2026.
Pounds shipped increased 180,295 pounds, or 75%, in 2025 as compared to 2024. This reflects our increased focus on production and pounds drummed, in particular.
We currently have 15 drill rigs operating at Lost Creek, which is sufficient to meet our present development requirements. The Casper construction shop continues to function well and has demonstrated that it is capable of meeting our current header house development needs for both Lost Creek and Shirley Basin.
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The following table provides information on our ending inventory of U 3 O 8 pounds.
U 3 O 8 Ending Inventory
Unit
Pounds
In-process inventory
Plant inventory
Conversion inventory - produced
Conversion inventory - non-produced
Value
In-process inventory
Plant inventory
Conversion inventory - produced
Conversion inventory - non-produced
Cost per Pound
In-process inventory
Plant inventory
Conversion inventory:
Ad valorem and severance tax
Cash cost
Non-cash cost
Conversion inventory - produced
Conversion inventory - non-produced
We ended 2025 with a total of 406,089 pounds in inventory as compared to 335,327 pounds in 2024. Non-produced pounds in inventory decreased slightly after purchasing 100,000 pounds and selling 110,000 pounds. Produced pounds at the conversion facility increased by 112,352 pounds.
The related cost per produced pound at the conversion facility decreased by $11.16 per pound, or 19%, during 2025. This reflects the increase in production in combination with consistent costs year over year. NRV adjustments on produced pounds were lower in 2025, decreasing from $3.5 million in 2024 to $0.6 million in 2025. As noted previously, we anticipate production related NRV adjustments to end as production increases.
The cost per non-produced pound in ending inventory decreased slightly during the year. The decrease includes an NRV adjustment of $2.1 million as the non-produced pounds were decreased to their NRV in 2025 Q1, which was nearly offset by the purchase of 100,000 pounds at approximately $82.25 per pound in 2025 Q4.
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Quarterly U 3 O 8 Product Profit and Loss, Production, and Ending Inventory
The following table provides information on our quarterly U 3 O 8 product profit and loss.
U 3 O 8 Product Profit (Loss)
Unit
U 3 O 8 Product Sales
Produced
Non-produced
U 3 O 8 Product Costs
Produced
Non-produced
U 3 O 8 Product Profit (Loss)
Produced
Non-produced
U 3 O 8 Pounds Sold
Produced
Non-produced
U 3 O 8 Price per Pound Sold
Produced
Non-produced
U 3 O 8 Cost per Pound Sold
Ad valorem and severance taxes
Cash costs
Non-cash costs
Produced
Non-produced
U 3 O 8 Profit (Loss) per Pound Sold
Cash costs
Less ad valorem and severance taxes
Less non-cash costs
Produced
Non-produced
U 3 O 8 Profit (Loss) Margin
Cash costs
Less ad valorem and severance taxes
Less non-cash costs
Produced
Non-produced
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The following table provides information on our quarterly U 3 O 8 production.
U 3 O 8 Production
Unit
Pounds captured
Pounds drummed in
Pounds shipped
Non-produced pounds acquired
The following table provides information on our quarterly U 3 O 8 ending inventory.
U 3 O 8 Ending Inventory
Unit
Pounds
In-process inventory
Plant inventory
Conversion inventory - produced
Conversion inventory - non-produced
Value
In-process inventory
Plant inventory
Conversion inventory - produced
Conversion inventory - non-produced
Cost per Pound
In-process inventory
Plant inventory
Conversion inventory:
Ad valorem and severance tax
Cash cost
Non-cash cost
Conversion inventory - produced
Conversion inventory - non-produced
Generally, our cost per produced pound sold was relatively consistent during the year, while our price per pound sold fluctuated depending on the term contract prices of the respective sales.
Except for 2025 Q3, pounds drummed increased each quarter. As noted above, pounds drummed increased by 161,231 pounds, or 65%, during the year as compared to 2024. We were pleased with the overall increase during 2025 and remain focused on achieving further growth in 2026.
The cash cost per produced pound at the conversion facility decreased during the year, reflecting consistent production costs combined with increasing production levels. As noted above, ad valorem and severance taxes were impacted by higher tax rates and higher sales prices, which are used to calculate the taxes. Non-cash costs per produced pound increased slightly. The increase was driven by the amortization of asset retirement obligation assets, which increased as we expanded development activities in the wellfields.
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The non-produced cost per pound at the conversion facility increased in 2025 Q4 as compared to 2025 Q3 because of purchasing 100,000 pounds at approximately $82.25 per pound in 2025 Q4.
Year Ended December 31, 2025, Compared to Year Ended December 31, 2024
The following table summarizes the results of operations for the years ended December 31, 2025, and 2024:
Results of Operations
Year Ended
(expressed in thousands of U.S. dollars,
December 31,
except per share and non-GAAP per pound data)
Change
Sales
Cost of sales
Gross profit (loss)
Operating costs
Operating profit (loss)
Interest income
Interest expense
Mark to market gain (loss)
Foreign exchange gain (loss)
Other income (loss)
Net income (loss)
Foreign currency translation adjustment
Comprehensive income (loss)
Earnings (loss) per common share:
Basic
Diluted
U 3 O 8 pounds sold
U 3 O 8 price per pound sold
U 3 O 8 cost per pound sold
U 3 O 8 profit (loss) per pound sold
Sales
Sales per the consolidated financial statements include U 3 O 8 product sales and disposal fees and consists of the following:
Year Ended
Sales
December 31,
(expressed in thousands of U.S. dollars)
Change
U 3 O 8 product sales
Disposal fees
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Due to the nature of our contracts, we have a limited number of deliveries, which do not occur consistently during the year. Sales revenues are recognized when the product is transferred to the purchaser.
During 2025, we sold 440,000 pounds at an average price of $61.77 per pound for U 3 O 8 product sales of $27.2 million. Disposal fees during 2025 were less than $0.1 million.
During 2024, we sold 570,000 pounds at an average price of $58.15 per pound for U 3 O 8 product sales of $33.1 million. Disposal fees during 2024 were $0.6 million.
The higher average price per pound sold in 2025 compared to 2024 was due to normal term contract price escalation factors. The lower volume in 2025 was due to the deferral of a 300,000-pound term contract sale to 2026.
The U 3 O 8 product sales in 2024 and 2025 were primarily delivered into sales contracts that were executed in 2022 when the long-term price was between $43 and $52 per pound.
Cost of Sales
Cost of sales per the consolidated financial statements includes U 3 O 8 product costs of sales and lower of cost or NRV adjustments and consists of the following:
Year Ended
Cost of Sales
December 31,
(expressed in thousands of U.S. dollars)
Change
U 3 O 8 product costs
Lower of cost or NRV adjustments
During 2025, we sold 440,000 pounds at an average cost of $55.52 per pound for U 3 O 8 product costs of $24.4 million. NRV adjustments during 2025 were $2.7 million.
During 2024, we sold 570,000 pounds at an average cost of $64.34 per pound for U 3 O 8 product costs of $36.7 million. NRV adjustments during 2024 were $6.0 million.
The lower average cost per pound sold in 2025 compared to 2024 was primarily due to an NRV adjustment to non-produced pounds of $2.1 million in 2025 Q1, which lowered the average costs of the non-produced pounds when they were subsequently sold in 2025 Q3. As noted above, the lower volume in 2025 was due to the deferral of a 300,000-pound term contract sale to 2026.
Cost of sales in 2025 included $2.7 million of NRV adjustments, of which $0.6 million related to produced inventory and $2.1 million related to non-produced inventory. The produced inventory NRV adjustments were incurred in the first half of 2025. As production levels gradually increased, the NRV adjustments decreased, and largely stopped in the second half of 2025. The non-produced inventory NRV adjustments were incurred in 2025 Q1 when the uranium spot price decreased below the carrying value of the non-produced pounds.
Cost of sales in 2024 included $6.0 million of NRV adjustments, of which $3.5 million related to produced inventory and $2.5 million related to non-produced inventory.
The lower NRV adjustment in 2025 compared to 2024 was due to increased production levels and higher uranium spot prices, which reduced NRV adjustments on produced and non-produced pounds, respectively.
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Gross Profit (Loss)
Gross profit (loss) per the consolidated financial statements includes U 3 O 8 product sales, U 3 O 8 product costs, disposal fees, and lower of cost or NRV adjustments and consists of the following:
Year Ended
Gross Profit (Loss)
December 31,
(expressed in thousands of U.S. dollars)
Change
U 3 O 8 product sales
U 3 O 8 product costs
U 3 O 8 product gross profit (loss)
Disposal fees
Lower of cost or NRV adjustments
Gross profit (loss) is based on sales, which include product sales and disposal fees, and cost of sales, which include product costs and NRV adjustments. The gross profit was $0.1 million in 2025 compared to a gross loss of $9.0 million in 2024. In 2025, the gross profit from selling U 3 O 8 product was nearly offset by the lower of cost or NRV adjustments. The majority of the 2025 NRV adjustment related to non-produced pounds.
In 2024, the Company purchased 300,000 pounds with cash at spot uranium prices and borrowed 250,000 pounds. The non-produced pounds were used to meet a 300,000-pound delivery requirement in 2024 Q4, which resulted in an average U 3 O 8 loss of approximately $20.87 per pound sold and contributed to the larger gross loss in 2024.
Operating Costs
The following table summarizes the operating costs for the years ended December 31, 2025, and 2024:
Year Ended
Operating Costs
December 31,
(expressed in thousands of U.S. dollars)
Change
Exploration and evaluation
Development
General and administration
Accretion of asset retirement obligations
Total operating costs increased $15.3 million in 2025. The increase was primarily due to development costs, which increased by $12.9 million due to ramp up activities at Lost Creek and initial pre-mining development activities at Shirley Basin.
Exploration and evaluation expense consists of labor and the associated costs of the geology, evaluation, and regulatory departments, as well as land holding and exploration costs on properties that have not reached the development or operations stage. The $1.1 million increase in 2025 was primarily due to additional labor costs and exploration costs related to our exploration programs at Lost Soldier, North Hadsell, and Lost Creek South. These increases were partially offset by lower service and non-cash costs.
General and administration expenses relate to the administration, finance, investor relations, land, and legal functions, and consist principally of personnel, facility, and support costs. The $0.8 million increase in 2025 was primarily related to higher labor and outside service costs, which were partially offset by lower non-cash costs.
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Development expenses increased approximately $12.9 million in 2025. The following table summarizes the development costs included in operating costs for the years ended December 31, 2025, and 2024:
Year Ended
Development Costs
December 31,
(expressed in thousands of U.S. dollars)
Change
Lost Creek mine unit development
Lost Creek disposal well development
Shirley Basin mine unit development
Other development
The Company is considered an exploration stage issuer and expenses its pre-production development costs. These development costs are incurred in advance of production from the related mining areas. Development expense includes costs incurred at the Lost Creek Project not directly attributable to current production activities, including wellfield construction, drilling, and development costs. It also includes costs incurred at the Shirley Basin Project not directly attributable to the construction of the capitalizable assets of the project, including the installation of the first mine unit and other development costs.
Production stage issuers, as defined by the SEC, having established proven and probable reserves, typically capitalize expenditures relating to ongoing development activities, with corresponding depletion calculated over proven and probable reserves using the units-of-production method. Depletion is then allocated to inventory and as the inventory is sold, to cost of sales. We are an exploration stage issuer which has resulted in the Company reporting larger losses than if we were a production stage issuer, due to the expensing, instead of capitalization, of expenditures relating to ongoing mine development activities. Additionally, there would be no corresponding depletion allocated to future periods of the Company since those costs had been expensed previously, resulting in both lower inventory costs and cost of sales, and results of operations with higher gross profit and lower gross loss than if we would have been in the production stage. As a result, our consolidated financial statements may not be directly comparable to the financial statements of production stage issuers.
As noted above, development expenses increased approximately $12.9 million in the year ended December 31, 2025. The increase was driven by development activities and wellfield construction costs related to the Shirley Basin mine unit (“MU”) one development program. Lost Creek development costs also increased in 2025 as we completed development activities at MU2 and began development activities in MU1 Phase 2, MU4, and MU5. Activities related to drilling a disposal well at Lost Creek were completed in 2024, leading to higher disposal well development costs in that year as compared to 2025.
Other Income and Expenses
Interest income decreased by $1.3 million in 2025, reflecting lower interest rates and cash balances during the year. Interest expense increased by $1.6 million in 2025, reflecting a full year of interest costs on the Company’s uranium inventory loan.
Mark-to-market adjustments include revaluations of the Company’s warrant liability and uranium inventory loan during the year plus the initial December 2025 revaluation of derivative instruments associated with the Company’s convertible notes. Increases in the Company’s share price and spot uranium prices led to mark-to-market losses on the warrant liability and uranium inventory loan, respectively, in 2025. Initial revaluation losses on the derivative instruments related to the convertible notes in December 2025 increased the mark-to-market loss in 2025.
Earnings (loss) per Common Share
The basic and diluted loss per common share was $0.20 and $0.17 for the years ended December 31, 2025, and 2024, respectively. The diluted loss per common share is equal to the basic loss per common share in periods of loss due to the anti-dilutive effects of outstanding stock awards and convertible securities.
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Liquidity and Capital Resources
As shown in the Consolidated Statements of Cash Flow, our cash and cash equivalents, and restricted cash and cash equivalents, increased from $87.1 million as of December 31, 2024, to $135.3 million as of December 31, 2025. During 2025, net cash of $114.9 million was provided from financing activities, $43.1 million was used in operating activities, and $23.6 million was used in investing activities.
Operating activities used $43.1 million of cash and cash equivalents in 2025. This includes sales of 440,000 pounds of U 3 O 8 for $27.2 million and the collection of $16.5 million in January 2025 from a uranium sale made in late 2024. It also reflects the receipt of $2.4 million in interest income, the payment of $1.2 million in interest expense, and spending of $17.6 million on production costs, $8.2 million on uranium purchase costs, and $65.5 million on operating costs. We had $3.3 million of other favorable working capital movements primarily related to increases in accounts payable and accrued liabilities.
Investing activities used $23.6 million of cash in 2025. We spent $18.4 million on construction at Shirley Basin and $5.2 million on vehicles, equipment, and enclosures primarily at Shirley Basin.
Financing activities provided net cash of $114.9 million in 2025. We received net proceeds of $15.6 million from the sale of common shares through our At Market Facility. We raised net proceeds of $98.3 million through the sale of convertible notes, net of financing costs and related capped call purchase costs. We received $1.8 million from the exercise of warrants and stock options and paid $0.1 million in settlement of RSUs redeemed for cash. We made principal payments of $0.7 million related to vehicle and equipment leases.
Wyoming State Bond Loan
On October 23, 2013, we closed a $34.0 million Sweetwater County, State of Wyoming, Taxable Industrial Development Revenue Bond financing program loan (“State Bond Loan”). The State Bond Loan called for payments of interest at a fixed rate of 5.75% per annum on a quarterly basis, which commenced January 1, 2014. As amended, the principal was payable in quarterly installments with the last payment due on October 1, 2024. The final payment was made March 27, 2024, after which the loan was paid in full.
Universal Shelf Registration and At Market Facility
On May 29, 2020, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc. (“B. Riley Securities”), relating to our common shares. On June 7, 2021, we amended and restated the Sales Agreement to include Cantor Fitzgerald & Co. (“Cantor,” and together with B. Riley Securities, the “Agents”) as a co-agent. Under the Sales Agreement, as amended, we may, from time to time, issue and sell common shares at market prices on the NYSE American or other U.S. market. The Sales Agreement was filed in conjunction with a universal shelf registration statement on Form S-3, effective May 27, 2020, which has now expired.
On June 28, 2023, we filed a new universal shelf registration statement on Form S-3 with the SEC through which we may offer and sell, from time to time, in one or more offerings, at prices and terms to be determined, up to $175 million of our common shares, warrants to purchase our common shares, our senior and subordinated debt securities, and rights to purchase our common shares and/or senior and subordinated debt securities. The registration statement became effective July 19, 2023, for a three-year period.
On July 19, 2023, we entered into an amendment to the Amended Sales Agreement (“Amendment No. 2” and hereafter the “Amended Sales Agreement”) with the Agents to, among other things, reflect the new registration statement. Under the current prospectus supplement to the registration statement, we may sell up to $70 million from time to time through or to the Agents pursuant to the Amended Sales Agreement.
In 2025, we utilized the Amended Sales Agreement for gross proceeds of $16.0 million from sales of 10,619,331 common shares.
2023 Underwritten Public Offering
On February 21, 2023, the Company closed a $46.1 million underwritten public offering of 39,100,000 common shares and accompanying warrants to purchase up to 19,550,000 common shares, at a combined public offering price of $1.18 per common share and accompanying warrant. The gross proceeds to Ur-Energy from this offering were approximately $46.1 million. After fees and
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expenses of $3.0 million, net proceeds to the Company were approximately $43.1 million. Prior to their expiry, 39,086,499 warrants were exercised to purchase 19,543,249 common shares at $1.50 per common share for proceeds of $29.3 million. The remaining 13,501 warrants expired on February 20, 2026.
2024 Underwritten Public Offering
On July 29, 2024, the Company closed an underwritten public offering of 57,150,000 common shares at a price of $1.05 per common share. The Company also granted the underwriters a 30-day option to purchase up to 8,572,500 additional common shares on the same terms. The option was exercised in full. Including the exercised option, the Company issued a total of 65,722,500 common shares. The gross proceeds to the Company from this offering were approximately $69.0 million. After fees and expenses of $3.8 million, net proceeds to the Company were approximately $65.2 million.
Liquidity Outlook
We have multi-year sales contracts in place with eight customers and realized revenues of $27.2 million from the sale of 440,000 pounds U 3 O 8 in 2025. We expect to realize revenues of up to $82.9 million from the sale of as many as 1,300,000 pounds of uranium in 2026. As of March 4, 2026, we had 379,197 pounds of conversion facility inventory including two shipments totaling 69,606 pounds made in 2026, the last of which was enroute to the conversion facility on March 4, 2026. We expect to return 250,000 pounds to a lender in 2026 Q4 to satisfy the terms of our uranium inventory loan. The return of the uranium inventory loan pounds and deliveries into term contracts in 2026 are expected to be made from our existing conversion facility inventory and new production from Lost Creek and Shirley Basin. We are closely monitoring current and expected production from both projects. The Company may seek to alter our 2026 delivery and inventory loan repayment schedules, borrow additional pounds from the inventory loans, or consider additional uranium purchases, if necessary.
In 2025, we recorded construction costs and capital equipment purchases of approximately $25.5 million at Shirley Basin. We expected to spend approximately $35.6 million in 2025. The $10.1 million variance was largely a timing difference as certain construction activities related to the plant enclosure could not be completed in 2025 Q4 primarily due to wind and other weather-related conditions at the site. The remaining 2025 capital expenditures are expected to be made in 2026. In 2026, we expect to record total construction costs and capital equipment purchases of approximately $25.5 million, including the $10.1 million timing difference from 2025 and the construction of a water treatment system at Shirley Basin.
In 2025, we recorded development costs of approximately $15.2 million at Shirley Basin, including initial wellfield, plant and site administrations costs, which are being charged to development expense until production commences. We expected to spend approximately $13.4 million in 2025. The $1.8 million variance reflects additional costs associated with development efforts at Shirley Basin to achieve start up expectations. In 2026, we expect to spend approximately $10.1 million on development expenditures at Shirley Basin plus a portion of the initial 2026 wellfield, plant and site administration costs. After production commences, the subsequent wellfield, plant and site administration costs will be treated as production costs and no longer included in development costs.
At Lost Creek, we plan to construct a wastewater treatment facility. The estimated cost of the facility is $25.0 million. The construction is expected to start in 2026 H2 and be completed in 2027. The purpose of the facility is to improve our ability to remove solids carried in the wellfield solutions before entering the plant and to reduce the amount of wastewater going to deep disposal wells. The facility is expected to benefit current operations and future restoration by allowing greater flow rates into the plant and optimize wastewater disposal from restoration of depleted wellfields.
Subsequent to December 31, 2025, 38,259,999 warrants were exercised for 19,129,999 underlying whole common shares at an average exercise price of $1.50 per share for proceeds of $28.7 million. As of March 4, 2026, our cash and restricted cash position was $115.3 million and did not include 24,684,999 of the aforementioned warrants exercised in February 2026 for 12,342,499 whole common shares at an average exercise price of $1.50 per share for proceeds of $18.5 million, which will be collected in March 2026.
We anticipate that the capital projects at Shirley Basin and Lost Creek will be funded by cash on hand, warrant proceeds, and expected operating cash flow. We have no immediate plans to issue additional securities or obtain additional financing other than that which may be required due to the uneven nature of cash flows generated from operations and used for construction related activities.
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Looking Ahead
We anticipate that 2026 will be a pivotal year for the Company as we commence operations and production at Shirley Basin, our second ISR uranium mining facility with a licensed wellfield capacity of one million pounds U 3 O 8 per year. In addition to Shirley Basin, we will remain focused on the continued ramp up and optimization of operations to increase production rates at Lost Creek.
At Shirley Basin, we have significantly advanced the construction of the plant building and have installed all IX columns and other tanks. Through February 2026, we have pilot drilled 469 injection and production wells in MU1. HHs 1-1 and 1-2 are onsite and three additional header houses are awaiting delivery to Shirley Basin from our Casper construction facility.
HH 1-1 is ready to be brought online to commence injection in and recovery from the wellfield once we have received regulatory approvals. The URP began its pre-operational inspection in late February 2026, and the wellfield data package is under review by the WDEQ.
After initial injection, we will continue to focus at Shirley Basin on completing construction activities inside the plant and the installation and commissioning of all production circuits to transport resin to Lost Creek for processing, drying and drumming. We expect to be able to commence transporting loaded resin to Lost Creek in summer 2026, subject to the receipt of regulatory approvals. Once we are producing and processing U 3 O 8 from Shirley Basin, we intend to commence the development of phase two operations, which will include wastewater disposal.
We look forward to the commencement of production operations at Shirley Basin, as it will diversify our production sources and further support our efforts to remain a leading U.S. uranium producer.
At Lost Creek, in 2025 compared to 2024: we captured 105,147 more pounds U 3 O 8 ; drummed 161,231 more pounds U 3 O 8 ; and sold 60,000 more produced pounds U 3 O 8 . Although the total pounds that we sold decreased from 2024 to 2025, the decrease was due to the deferral of a 300,000-pound term contract sale to 2026. Our production increases from 2024 to 2025 led to lower cash and non-cash costs per pound sold (exclusive of taxes), higher U 3 O 8 profit per pound sold, and higher U 3 O 8 profit margin. In 2026 at Lost Creek, we will continue to focus on increasing production rates, profit per pound sold, and profit margin.
Our efforts to increase production rates at Lost Creek will include continuing work to resolve the remaining operational challenges associated with our ramp-up. To allow for sustained higher flow rates into the plant and to reduce the amount of wastewater generated at Lost Creek, we plan to initiate construction of a wastewater treatment facility in 2026. We also intend to improve our reverse osmosis systems, implement a more robust maintenance plan, and continue our focus on daily drumming to allow us to package and ship more pounds from the plant.
We plan to conduct additional development activities in MU1 Phase 2, MU5 and MU3 at Lost Creek, and to bring new header houses online in MU1 Phase 2 in 2026 H2. We have 15 drill rigs supporting the development of these Lost Creek recovery areas, as well as delineation of MU4 for planning and development work.
We have conducted a significant amount of hiring since 2023 for the ramp up at Lost Creek and construction and commencement of operations at Shirley Basin. We completed recruitment and hiring within our phased plan for staffing at Shirley Basin. Our recruitment approach has allowed for more thorough safety and task training of staff prior to commencement of operations.
With few exceptions, now that we are fully staffed at both Lost Creek and Shirley Basin, we are focused on retention and training and anticipate continued improvement in operations as our core staff has more time on the job.
As discussed above, we have secured multi-year sales agreements with leading nuclear companies, including several which include market-related pricing components. Our agreements call for base annual deliveries of 100,000 to 1.4 million pounds U 3 O 8 from 2026 through 2033, with additional deliveries at our election of up to 100,000 pounds in 2028, 2029, and 2030. Combined base deliveries from 2026 through 2033 total 5.75 million pounds U 3 O 8 . Sales prices are anticipated to be profitable on an all-in production cost basis and escalate annually from initial pricing.
Although Lost Creek and Shirley Basin remain the Company’s priorities, we also plan to continue our exploration program in 2026 to increase our potential to leverage existing infrastructure and expand our potential uranium resources.
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In 2025, we began exploration work at our Lost Soldier project northeast of Lost Creek, which included the installation of 18 aquifer test wells. In anticipation of possible permitting, we plan to begin aquifer testing in 2026 Q1 to allow us to better understand the local hydrogeology. Also to prepare for possible permitting, we plan to initiate baseline environmental studies in 2026. Our work continues to analyze drill data and other geologic and hydrogeologic data to calculate a mineral resource estimate; we anticipate preparing a technical report of estimated mineral resources at Lost Soldier in 2026.
We also commenced a program to drill 50 exploration holes at our North Hadsel Project in 2025. We intend to complete that program by the summer 2026, after which we plan to commence a program to drill 120 exploration holes at our LC South Project.
Subsequent to December 31, 2025, 38,259,999 warrants were exercised for 19,129,999 underlying whole common shares at an average exercise price of $1.50 per share for proceeds of $28.7 million. As of March 4, 2026, our cash and restricted cash position was $115.3 million and did not include 24,684,999 of the aforementioned warrants exercised in February 2026 for 12,342,499 whole common shares at an average exercise price of $1.50 per share for proceeds of $18.5 million, which will be collected in March 2026.
Our safety performance improved from 2024 to 2025. Particularly with the level of new staff and contractors and significant construction and operational activity at both mine sites, we will continue to focus on maintaining safe and compliant operations.
Outstanding Share Data
As of December 31, 2025, and 2024, the Company’s capital consisted of the following:
Share Data
December 31, 2025
December 31, 2024
Common shares
Shares issuable upon the exercise or redemption of:
Stock options
Restricted share units
Warrants
Off Balance Sheet Arrangements
We have not entered into any material off balance sheet arrangements such as guaranteed contracts, contingent interests in assets transferred to unconsolidated entities, derivative instrument obligations, or with respect to any obligations under a variable interest entity arrangement.
Financial Instruments and Other Instruments
As of December 31, 2025, and 2024, the Company’s cash and cash equivalents, and restricted cash and cash equivalents are composed of:
(expressed in thousands of U.S. dollars)
Cash and Cash Equivalents, and Restricted Cash and Cash Equivalents
December 31, 2025
December 31, 2024
Cash and cash equivalents
Restricted cash and cash equivalents
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Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, and restricted cash and cash equivalents. These assets include Canadian dollar and U.S. dollar denominated certificates of deposit, money market accounts, and demand deposits. These instruments are maintained at financial institutions in Canada and the U.S. Of the amount held on deposit, approximately $0.6 million is covered by the Canada Deposit Insurance Corporation, the Securities Investor Protection Corporation, or the U.S. Federal Deposit Insurance Corporation (“FDIC”), leaving approximately $134.7 million at risk on December 31, 2025, should the financial institutions with which these amounts are invested be rendered insolvent. The Company does not consider any of its financial assets to be impaired as of December 31, 2025.
Subsequent to December 31, 2025, 38,259,999 warrants were exercised for 19,129,999 underlying whole common shares at an average exercise price of $1.50 per share for proceeds of $28.7 million. As of March 4, 2026, our cash and restricted cash position was $115.3 million and did not include 24,684,999 of the aforementioned warrants exercised in February 2026 for 12,342,499 whole common shares at an average exercise price of $1.50 per share for proceeds of $18.5 million, which will be collected in March 2026.
Subsequent to December 31, 2025, the Company entered into an arrangement with a bank that utilizes the IntraFi Cash Service (“ICS”) network to allow our U.S. deposits to be placed at multiple deposit institutions in order to maximize FDIC insurance coverage. As a result, the amount covered by the Canada Deposit Insurance Corporation, the Securities Investor Protection Corporation, or the FDIC increased to $31.1 million as of March 4, 2026, leaving approximately $95.7 million at risk should the financial institutions in which these amounts are invested be rendered insolvent.
Currency Risk
As of December 31, 2025, we maintained a balance of approximately $3.6 million Canadian dollars. The funds will be used to pay Canadian dollar expenses and are considered to be a low currency risk to the Company.
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due. As of December 31, 2025, the Company’s current financial liabilities consisted of accounts payable and accrued liabilities of $10.4 million, the current portion of leases payable of $0.5 million and the repayment of the inventory loan currently valued at $16.6 million. As of December 31, 2025, we had $123.9 million in cash and cash equivalents, no trade receivables and $24.3 million in inventory.
Interest Rate Risk
The Company has completed a sensitivity analysis to estimate the impact that a change in interest rates would have on the net loss and considers the change to be a low interest rate risk to the Company.
